26504 Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / 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: Notice of proposed rulemaking. 

SUMMARY: The Federal Energy 

Regulatory Commission (Commission) 

proposes to reform both the pro forma 

Open Access Transmission Tariff and 

the pro forma Large Generator 

Interconnection Agreement to remedy 

deficiencies in the Commission’s 

existing regional transmission planning 

and cost allocation requirements. 

Specifically, the proposal would require 

public utility transmission providers to; 

conduct long-term regional transmission 

planning on a sufficiently forwardlooking basis to meet transmission 

needs driven by changes in the resource 

mix and demand; more fully consider 

dynamic line ratings and advanced 

power flow control devices in regional 

transmission planning processes; seek 

the agreement of relevant state entities 

within the transmission planning region 

regarding the cost allocation method or 

methods that will apply to transmission 

facilities selected in the regional 

transmission plan for purposes of cost 

allocation through long-term regional 

transmission planning; adopt enhanced 

transparency requirements for local 

transmission planning processes and 

improve coordination between regional 

and local transmission planning with 

the aim of identifying potential 

opportunities to ‘‘right-size’’ 

replacement transmission facilities; and 

revise their existing interregional 

transmission coordination procedures to 

reflect the long-term regional 

transmission planning reforms proposed 

in this NOPR. In addition, the proposal 

would not permit public utility 

transmission providers to take 

advantage of the construction-work-inprogress incentive for regional 

transmission facilities selected for 

purposes of cost allocation through 

long-term regional transmission 

planning and would permit the exercise 

of federal rights of first refusal for 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation, conditioned on the 

incumbent transmission provider with 

the federal right of first refusal for such 

regional transmission facilities 

establishing joint ownership of the 

transmission facilities. 

DATES: Comments are due July 18, 2022 

and Reply Comments are due August 

17, 2022. 

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 USPS mail or by hand (including 

courier) delivery. 

Æ Mail via U.S. Postal Service Only: 

Addressed to: Federal Energy 

Regulatory Commission, Secretary of the 

Commission, 888 First Street NE, 

Washington, DC 20426. 

Æ Hand (including courier) delivery: 

Deliver to: Federal Energy Regulatory 

Commission, 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 

Noah Lichtenstein (Technical 

Information), Office of Energy Market 

Regulation, 888 First Street NE, 

Washington, DC 20426, (202) 502– 

8696, noah.lichtenstein@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 ........................................................................................................................................................................................... 12 

A. Historical Framework: Order Nos. 888, 890, and 1000 ................................................................................................................. 12 

B. ANOPR and Technical Conference ................................................................................................................................................. 18 

C. Joint Federal-State Task Force on Electric Transmission .............................................................................................................. 20 

D. High-Level Overview of ANOPR Comments .................................................................................................................................. 23 

III. Need for Reform .................................................................................................................................................................................. 24 

A. Potential Benefits of Long-Term Regional Transmission Planning and Cost Allocation to Identify and Plan for Transmission Needs Driven by Changes in the Resource Mix and Demand .......................................................................................... 28 

B. Unjust and Unreasonable and Unduly Discriminatory and Preferential Commission-Jurisdictional Rates .............................. 34 

1. The Transmission Investment Landscape Today .................................................................................................................... 36 

2. Deficiencies in the Commission’s Existing Regional Transmission Planning and Cost Allocation Requirements ............ 47 

IV. Regional Transmission Planning ....................................................................................................................................................... 56 

A. Overview of Existing Regional Transmission Planning Processes ............................................................................................... 57 

1. Reliability Needs ....................................................................................................................................................................... 58 

2. Economic Needs ........................................................................................................................................................................ 59 

3. Transmission Needs Driven by Public Policy Requirements ................................................................................................. 60 

B. Comments ......................................................................................................................................................................................... 61 

C. Proposed Reforms ............................................................................................................................................................................. 64 

1. Long-Term Regional Transmission Planning ........................................................................................................................... 64 

a. Need for Reform ................................................................................................................................................................. 64 

b. Proposed Reform ................................................................................................................................................................ 68 

i. Development of Long-Term Scenarios For Use In Long-Term Regional Transmission Planning .......................... 79 

(a) Comments ............................................................................................................................................................ 80 

(b) Proposed Reform ................................................................................................................................................ 84 

(1) Long-Term Scenarios Requirements .................................................................................................................. 91 

(i) Transmission Planning Horizon and Frequency ............................................................................................... 92 

(01) Comments ......................................................................................................................................................... 95 


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Paragraph 

Nos. 

(02) Proposed Requirement ..................................................................................................................................... 97 

(ii) Factors ................................................................................................................................................................. 101 

(01) Comments ......................................................................................................................................................... 103 

(02) Proposed Requirement ..................................................................................................................................... 104 

(iii) Number and Range of Long-Term Scenarios ................................................................................................... 113 

(01) Comments ......................................................................................................................................................... 118 

(02) Proposed Requirement ..................................................................................................................................... 121 

(iv) Specificity of Data Inputs ................................................................................................................................. 127 

(01) Comments ......................................................................................................................................................... 129 

(02) Proposed Requirement ..................................................................................................................................... 130 

(v) Identification of Geographic Zones ................................................................................................................... 135 

(01) Comments ......................................................................................................................................................... 136 

(02) Proposed Requirement ..................................................................................................................................... 145 

ii. Coordination of Regional Transmission Planning and Generator Interconnection Processes ............................... 154 

(a) ANOPR ................................................................................................................................................................ 155 

(b) Comments ........................................................................................................................................................... 157 

(c) Need for Reform .................................................................................................................................................. 161 

(d) Proposed Reform ................................................................................................................................................ 166 

iii. Evaluation of the Benefits of Regional Transmission Facilities ............................................................................. 175 

(a) Evaluations of Long-Term Regional Transmission Benefits ............................................................................ 176 

(1) Comments ........................................................................................................................................................... 178 

(2) Proposed Reform ................................................................................................................................................ 183 

(3) Description of Long-Term Regional Transmission Benefits ............................................................................ 189 

(b) Evaluation of Transmission Benefits Over Longer Time Horizon ................................................................... 226 

(1) Comments ........................................................................................................................................................... 226 

(2) Proposed Reform ................................................................................................................................................ 227 

(c) Evaluation of the Benefits of Portfolios of Transmission Facilities ................................................................ 231 

(1) Comments ........................................................................................................................................................... 232 

(2) Proposed Reform ................................................................................................................................................ 233 

iv. Selection of Regional Transmission Facilities ......................................................................................................... 236 

(a) Comments ............................................................................................................................................................ 238 

(b) Proposed Reform ................................................................................................................................................ 241 

c. Implementation of Long-Term Regional Transmission Planning .................................................................................... 253 

2. Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices in Long-Term Regional Transmission Planning ........................................................................................................................................................................ 256 

a. ANOPR ................................................................................................................................................................................ 256 

b. Comments ........................................................................................................................................................................... 257 

c. Need for Reform ................................................................................................................................................................. 267 

d. Proposed Reform ................................................................................................................................................................ 272 

V. Regional Transmission Cost Allocation ............................................................................................................................................. 278 

A. Background ....................................................................................................................................................................................... 280 

B. ANOPR .............................................................................................................................................................................................. 286 

C. Comments ......................................................................................................................................................................................... 288 

D. Need for Reform ............................................................................................................................................................................... 297 

E. Proposed Reform .............................................................................................................................................................................. 302 

1. State Involvement in Cost Allocation for Long-Term Regional Transmission Facilities ...................................................... 302 

a. Agreement of Relevant State Entities ................................................................................................................................ 304 

b. State Agreement Process .................................................................................................................................................... 311 

2. Time Period in Long-Term Regional Transmission Planning Cost Allocation Processes for State-Negotiated Alternate 

Cost Allocation Method ............................................................................................................................................................. 319 

3. Identification of Benefits Considered in Cost Allocation for Long-Term Regional Transmission Facilities ...................... 325 

VI. Construction Work in Progress Incentive ......................................................................................................................................... 328 

A. Background ....................................................................................................................................................................................... 328 

B. Need for Reform ............................................................................................................................................................................... 330 

C. Proposed Reform .............................................................................................................................................................................. 333 

VII. Exercise of a Federal Right of First Refusal in Commission-Jurisdictional Tariffs and Agreements .......................................... 335 

A. Background ....................................................................................................................................................................................... 337 

1. Order No. 1000’s Nonincumbent Transmission Developer Reforms and Federal Right of First Refusal Elimination 

Mandate ...................................................................................................................................................................................... 337 

2. Experience Since Order No. 1000 ............................................................................................................................................ 343 

3. ANOPR ....................................................................................................................................................................................... 345 

4. Comments .................................................................................................................................................................................. 346 

B. Need for Reform ............................................................................................................................................................................... 349 

C. Proposed Reform .............................................................................................................................................................................. 351 

1. Approach to Reform .................................................................................................................................................................. 351 

2. Conditional Federal Rights of First Refusal for Certain Jointly-Owned Transmission Facilities ........................................ 358 

a. Background ......................................................................................................................................................................... 359 

b. Comments ........................................................................................................................................................................... 360 

c. Proposed Reform ................................................................................................................................................................ 365 

VIII. Enhanced Transparency of Local Transmission Planning Inputs In the Regional Transmission Planning Process and Identifying Potential Opportunities to Right-Size Replacement Transmission Facilities ....................................................................... 383 

A. Background ....................................................................................................................................................................................... 383 

B. ANOPR .............................................................................................................................................................................................. 387 


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26506 Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 

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

Commission-jurisdictional rates, terms, and 

conditions, including those for transmission 

services, be just and reasonable and not unduly 

discriminatory or preferential. The phrase 

‘‘Commission-jurisdictional rates,’’ as used in this 

NOPR, includes rates, terms, and conditions. 

2Promoting Wholesale Competition Through 

Open Access Non-Discriminatory Transmission 

Services by Pub. Utils.; Recovery of Stranded Costs 

by Publ. Utils. & Transmitting Utils., Order No. 888, 

61 FR 21540 (May 10, 1996), FERC Stats. & Regs. 

¶ 31,036 (1996) (cross-referenced at 75 FERC 

¶ 61,080), order on reh’g, Order No. 888–A, 62 FR 

12274 (Mar. 14, 1997), 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 Pol’y Study Group v. FERC, 225 F.3d 667 

(D.C. Cir. 2000), aff’d sub nom. N. Y. v. FERC, 535 

U.S. 1 (2002). 

3Preventing Undue Discrimination & Preference 

in Transmission Serv., Order No. 890, 72 FR 12266 

(Mar. 15, 2007), 118 FERC ¶ 61,119, order on reh’g, 

Order No. 890–A, 73 FR 2984 (Jan. 16, 2008), 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, 74 FR 12540 (Mar. 25, 2009), 126 

FERC ¶ 61,228, order on clarification, Order No. 

890–D, 129 FERC ¶ 61,126 (2009). 

4Transmission Planning & Cost Allocation by 

Transmission Owning & Operating Pub. Utils., 

Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 

FERC ¶ 61,051 (2011), order on reh’g, Order No. 

1000–A, 77 FR 32184 (May 31, 2012), 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). 

5A public utility transmission provider means a 

public utility that owns, controls, or operates 

transmission facilities. The term public utility 

transmission provider should be read to include a 

public utility transmission owner when the 

transmission owner is separate from the 

transmission provider, as is the case in regional 

transmission organizations (RTO) and independent 

system operators (ISO). The term ‘‘public utility’’ 

means ‘‘any person who owns or operates facilities 

subject to the jurisdiction of the Commission 

. . . .’’ 16 U.S.C. 824(e). 

6This NOPR refers to such facilities as ‘‘LongTerm Regional Transmission Facilities’’. 

Paragraph 

Nos. 

C. Comments ......................................................................................................................................................................................... 390 

D. Need for Reform ............................................................................................................................................................................... 398 

E. Proposed Reform .............................................................................................................................................................................. 400 

IX. Interregional Transmission Coordination and Cost Allocation ....................................................................................................... 416 

A. Background ....................................................................................................................................................................................... 417 

B. ANOPR .............................................................................................................................................................................................. 422 

C. Comments ......................................................................................................................................................................................... 423 

D. Need for Reform ............................................................................................................................................................................... 424 

E. Proposed Reform .............................................................................................................................................................................. 426 

X. Proposed Compliance Procedures ...................................................................................................................................................... 430 

XI. Information Collection Statement ...................................................................................................................................................... 434 

XII. Environmental Analysis .................................................................................................................................................................... 451 

XIII. Regulatory Flexibility Act [Analysis or Certification] ................................................................................................................... 452 

XIV. Comment Procedures ....................................................................................................................................................................... 460 

XV. Document Availability ...................................................................................................................................................................... 463 

Appendix A: Abbreviated Names of Commenters 

Appendix B: Pro Forma Open Access Transmission Tariff Attachment K 

Appendix C: Pro forma Large Generator Interconnection Procedures (LGIP) 

I. Introduction 

1. In this Notice of Proposed 

Rulemaking (NOPR), the Federal Energy 

Regulatory Commission (Commission) is 

proposing, pursuant to its authority 

under section 206 of the Federal Power 

Act (FPA),1 to reform its electric 

regional transmission planning and cost 

allocation requirements. The proposed 

reforms are intended to remedy 

deficiencies in the Commission’s 

existing regional transmission planning 

and cost allocation requirements to 

ensure that Commission-jurisdictional 

rates remain just and reasonable and not 

unduly discriminatory or preferential. 

2. This NOPR builds on Order Nos. 

888,2 890,3 and 1000,4 in which the 

Commission incrementally developed 

the requirements that govern regional 

transmission planning and cost 

allocation processes to ensure that 

Commission-jurisdictional rates remain 

just and reasonable and not unduly 

discriminatory or preferential. 

3. With respect to regional 

transmission planning, as discussed in 

more detail below, the reforms proposed 

in this NOPR would require public 

utility transmission providers to 

conduct long-term regional transmission 

planning on a sufficiently forwardlooking basis to meet transmission 

needs driven by changes in the resource 

mix and demand.5 As part of this longterm regional transmission planning, 

public utility transmission providers 

would be required to: (1) Identify 

transmission needs driven by changes in 

the resource mix and demand through 

the development of long-term scenarios 

that satisfy the requirements set forth in 

this NOPR, including accounting for 

low-frequency, high-impact events such 

as extreme weather events; (2) evaluate 

the benefits of regional transmission 

facilities to meet these needs over a time 

horizon that covers, at a minimum, 20 

years starting from the estimated inservice date of the transmission 

facilities; and (3) establish transparent 

and not unduly discriminatory criteria 

to select transmission facilities in the 

regional transmission plan for purposes 

of cost allocation that more efficiently or 

cost-effectively address these 

transmission needs in collaboration 

with states and other stakeholders. We 

do not propose in this NOPR to change 

Order No. 1000’s requirements for 

public utility transmission providers 

with respect to existing reliability and 

economic planning requirements. 

Additionally, we propose to require that 

public utility transmission providers 

more fully consider dynamic line 

ratings and advanced power flow 

control devices in regional transmission 

planning processes. 

4. With respect to transmission cost 

allocation, the reforms proposed in this 

NOPR would require that public utility 

transmission providers in each 

transmission planning region seek the 

agreement of relevant state entities 

within the transmission planning region 

regarding the cost allocation method or 

methods that will apply to transmission 

facilities selected in the regional 

transmission plan for purposes of cost 

allocation through long-term regional 

transmission planning 6 and revise their 

OATTs to include those method or 

methods. 

5. We also propose to not permit 

public utility transmission providers to 

take advantage of the constructionwork-in-progress (CWIP) incentive for 

regional transmission facilities selected 

for purposes of cost allocation through 

long-term regional transmission 

planning. 

6. With respect to federal rights of 

first refusal, the reforms proposed in 

this NOPR would amend Order No. 

1000’s requirements, in part, to permit 


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7Building for the Future Through Electric 

Regional Transmission Planning & Cost Allocation 

& Generator Interconnection, 86 FR 40266 (July 15, 

2021), 176 FERC ¶ 61,024 (2021) (ANOPR); see infra 

P 18 (briefly summarizing the ANOPR). 

8Order No. 890, 118 FERC ¶ 61,119 at PP 418– 

601. 

9Order No. 1000, 136 FERC ¶ 61,051 at P 3. The 

term ‘‘stakeholder’’ means any interested party. Id. 

P 151 n.143. 

10 Id. P 2. 

11 Id. P 22. 

12Public 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). Id. 

P 2. Order No. 1000–A clarified that Public Policy 

Requirements include local laws or regulations 

passed by a local governmental entity, such as a 

municipal or county government. Order No. 1000– 

A, 139 FERC ¶ 61,132 at P 319. 

13Order No. 1000, 136 FERC ¶ 61,051 at P 3. 

14 Id. PP 11–12, 42–44; Order No. 1000–A, 139 

FERC ¶ 61,132 at PP 3, 4–6. 

15Order No. 1000, 136 FERC ¶ 61,051 at P 12. 

the exercise of federal rights of first 

refusal for transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation, 

conditioned on the incumbent 

transmission provider with the federal 

right of first refusal for such regional 

transmission facilities establishing joint 

ownership of the transmission facilities 

consistent with the proposal below. 

7. With respect to transparency and 

coordination, we propose to require 

public utility transmission providers to 

adopt enhanced transparency 

requirements for local transmission 

planning processes and improve 

coordination between regional and local 

transmission planning with the aim of 

identifying potential opportunities to 

‘‘right-size’’ replacement transmission 

facilities. 

8. With respect to interregional 

transmission coordination and cost 

allocation, the reforms proposed in this 

NOPR would require that public utility 

transmission providers revise their 

existing interregional transmission 

coordination procedures to reflect the 

long-term regional transmission 

planning reforms proposed in this 

NOPR. 

9. The proposed reforms in this NOPR 

related to regional transmission 

planning and cost allocation 

requirements, like those of Order Nos. 

890 and 1000, are focused on the 

transmission planning process, and not 

on any substantive outcomes that may 

result from this process. Taken together, 

these proposed reforms would work 

together to remedy deficiencies in the 

Commission’s existing regional 

transmission planning and cost 

allocation requirements. This, in turn, 

would fulfill our statutory obligation to 

ensure that Commission-jurisdictional 

rates remain just and reasonable and not 

unduly discriminatory or preferential. 

10. The Advance Notice of Proposed 

Rulemaking (ANOPR),7 the Commission 

also sought comment on reforms related 

to cost allocation for interconnectionrelated network upgrades, 

interconnection queue processes, 

interregional transmission coordination 

and planning, and oversight of 

transmission planning and costs. While 

this NOPR does not propose broad or 

comprehensive reforms directly related 

to these topics, we will continue to 

review the record developed to date and 

expect to address possible inadequacies 

through subsequent proceedings that 

propose reforms, as warranted, related 

to these topics. In addition, concurrent 

with the issuance of this NOPR, we 

notice a technical conference on 

Transmission Planning and Cost 

Management. 

11. We seek comment on the reforms 

proposed herein and encourage 

commenters to identify enhancements 

to those reforms that could better 

support development of more efficient 

or cost-effective transmission facilities 

than is the case under the Commission’s 

existing regional transmission planning 

and cost allocation requirements. 

II. Background 

A. Historical Framework: Order Nos. 

888, 890, and 1000 

12. Over the last several decades, the 

Commission has taken multiple 

significant actions on transmission 

planning and cost allocation, including 

issuing Order Nos. 888, 890, and 1000. 

In 1996, the Commission issued Order 

No. 888, which implemented open 

access to transmission facilities owned, 

operated, or controlled by a public 

utility and included certain minimum 

requirements for transmission planning. 

In 2007, the Commission issued Order 

No. 890 to address deficiencies in the 

pro forma OATT that it identified after 

more than 10 years of experience since 

Order No. 888. Among other OATT 

reforms, the Commission required all 

public utility transmission providers’ 

local transmission planning processes to 

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.8

13. Then, in 2011, the Commission 

recognized the need for further 

transmission planning reforms with its 

issuance of Order No. 1000. The 

Commission based the reforms it 

adopted in Order No. 1000 on changes 

in the energy industry, its experience 

implementing Order No. 890, and a 

robust record developed through 

technical conferences and comments 

from a diverse range of stakeholders.9

The Commission stated in Order No. 

1000 that ‘‘the electric industry is 

currently facing the possibility of 

substantial investment in future 

transmission facilities to meet the 

challenge of maintaining reliable service 

at a reasonable cost.’’ 10 In establishing 

the requirements of Order No. 1000, the 

Commission found that the existing 

requirements of Order No. 890 were not 

adequate, noting that Order No. 1000 

‘‘expands upon the reforms begun in 

Order No. 890 by addressing new 

concerns that have become apparent in 

the Commission’s ongoing monitoring of 

these matters.’’ 11 The Commission then 

enumerated multiple concerns that it 

had regarding existing transmission 

planning practices, including concerns 

about: (1) The lack of an affirmative 

obligation to develop a transmission 

plan evaluating if a regional 

transmission facility ‘‘may be more 

efficient or cost-effective than solutions 

identified in local transmission 

planning processes;’’ (2) the lack of a 

requirement to address Public Policy 

Requirements; 12 (3) the federal right of 

first refusal for incumbent transmission 

developers to build upgrades to their 

existing transmission facilities; (4) the 

lack of procedures to identify and 

evaluate the benefits of interregional 

transmission facilities; and (5) cost 

allocation for regional and interregional 

transmission facilities.13

14. Order No. 1000 included a 

package of reforms to ensure that the 

transmission planning and cost 

allocation requirements embodied in the 

pro forma OATT were adequate to 

support the development of more 

efficient or cost-effective transmission 

facilities.14 The reforms in Order No. 

1000 fell into the following categories: 

Regional transmission planning; 

transmission needs driven by Public 

Policy Requirements; nonincumbent 

transmission developer reforms; 

regional and interregional cost 

allocation, including a set of principles 

for each category of cost allocation; and 

interregional transmission coordination. 

The reforms focused on the process by 

which public utility transmission 

providers engage in regional 

transmission planning and associated 

cost allocation rather than on the 

outcomes of the process.15


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16The Commission did not include the regional 

participation or cost allocation transmission 

planning principles with respect to regional 

transmission planning processes because those 

issues were addressed by other reforms in Order 

No. 1000. Id. P 151. 

17A transmission planning region is one in which 

public utility transmission providers, in 

consultation with stakeholders and affected states, 

have agreed to participate for purposes of regional 

transmission planning and development of a single 

regional transmission plan. Id. P 160. 

18 Id. P 63. 

19 Id. n.374. 

20 Id. 

21 Id. P 63. 

22 Id. PP 7, 226, 318. 

23 Id. P 63. The Commission clarified in Order No. 

1000–A that a local transmission facility is one that 

is located within the geographical boundaries of a 

public utility transmission provider’s retail 

distribution service territory, if it has one; otherwise 

the area is defined by the public utility 

transmission provider’s footprint. In the case of an 

RTO/ISO whose footprint covers the entire region, 

a local transmission facility is defined by reference 

to the retail distribution service territories or 

footprints of its underlying transmission owing 

members. Order No. 1000–A, 139 FERC ¶ 61,132 at 

P 429. 

24ANOPR, 176 FERC ¶ 61,024 at P 3. 

25Building for the Future Through Elec. Reg’l 

Transmission Planning & Cost Allocation & 

Generator Interconnection, Further Supplemental 

Notice of Technical Conference, Docket No. RM21– 

17–000 (issued Nov. 12, 2021) (attaching agenda). 

26 Joint Fed.-State Task Force on Elec. 

Transmission, 175 FERC ¶ 61,224, at PP 1, 6 (2021). 

27 Id. P 2. 

28An up-to-date list of Task Force members, as 

well as additional information on the Task Force, 

is available on the Commission’s website at: https:// 

www.ferc.gov/TFSOET. Public materials related to 

the Task Force, including transcripts from public 

15. Among other regional 

transmission planning reforms in Order 

No. 1000, the Commission required that 

the following Order No. 890 

transmission planning principles apply 

to regional transmission planning 

processes: (1) Coordination; (2) 

openness; (3) transparency; (4) 

information exchange; (5) 

comparability; (6) dispute resolution; 

and (7) economic planning studies.16

16. In addition, with respect to the 

Order No. 1000 reforms, there is a 

distinction between a transmission 

facility ‘‘included’’ in a regional 

transmission plan and a transmission 

facility ‘‘selected’’ in a regional 

transmission plan for purposes of cost 

allocation. A transmission facility 

selected in a regional transmission plan 

for purposes of cost allocation is a 

transmission facility that has been 

selected pursuant to a transmission 

planning region’s 17 Commissionapproved regional transmission 

planning process for inclusion in a 

regional transmission plan for purposes 

of cost allocation because it is a more 

efficient or cost-effective transmission 

facility needed to meet regional 

transmission needs. Both regional 

transmission facilities and interregional 

transmission facilities are eligible for 

potential ‘‘selection’’ in a regional 

transmission plan for purposes of cost 

allocation.18 A regional transmission 

facility is a transmission facility located 

entirely in one transmission planning 

region.19 An interregional transmission 

facility is one that is located in two or 

more transmission planning regions.20

17. Transmission facilities selected in 

a regional transmission plan for 

purposes of cost allocation often will 

not comprise all of the transmission 

facilities that are included in a regional 

transmission plan.21 Some transmission 

facilities are merely ‘‘rolled up’’ and 

listed in a regional transmission plan 

without going through an analysis at the 

regional level, and therefore, are not 

eligible for selection and regional cost 

allocation.22 For example, a local 

transmission facility is a transmission 

facility located solely within a public 

utility transmission provider’s retail 

distribution service territory or footprint 

that is not selected in the regional 

transmission plan for purposes of cost 

allocation.23 Thus, a local transmission 

facility may be rolled up and 

‘‘included’’ in a regional transmission 

plan for informational purposes, but it 

is not ‘‘selected’’ in a regional 

transmission plan for purposes of cost 

allocation. 

B. ANOPR and Technical Conference 

18. In July 2021, the Commission 

issued an ANOPR presenting potential 

reforms to improve the regional 

transmission planning and cost 

allocation and generator interconnection 

processes. In issuing the ANOPR, the 

Commission noted that, more than a 

decade after Order No. 1000, it was time 

to review its regulations governing 

regional transmission planning and cost 

allocation and generator interconnection 

processes to determine whether reforms 

are needed to ensure Commissionjurisdictional rates remain just and 

reasonable and not unduly 

discriminatory or preferential.24 The 

Commission noted that the electricity 

sector is transforming as the generation 

fleet shifts from resources located close 

to population centers toward resources 

that may often be located far from load 

centers. The Commission also 

highlighted the growth of new resources 

seeking to interconnect to the 

transmission system and that the 

differing characteristics of those 

resources are creating new demands on 

the transmission system. The 

Commission explained that ensuring 

just and reasonable Commissionjurisdictional rates as the resource mix 

changes, while maintaining grid 

reliability, remains the Commission’s 

priority in adopting requirements for the 

regional transmission planning and cost 

allocation and generator interconnection 

processes. As a result, the Commission 

issued the ANOPR 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 Commissionjurisdictional rates remain just and 

reasonable and not unduly 

discriminatory or preferential and that 

reliability is maintained. 

19. On November 15, 2021, the 

Commission convened a staff-led 

technical conference (November 2021 

Technical Conference or Technical 

Conference) to examine in detail issues 

and potential reforms related to regional 

transmission planning as described in 

ANOPR. Specifically, the Technical 

Conference included three panels 

covering issues related to factors to 

consider in long-term scenarios, 

consideration of longer-term scenarios 

in regional transmission planning 

processes, and identifying geographic 

zones with high renewable resource 

potential for use in regional 

transmission planning processes.25

After the Technical Conference, the 

Commission invited all interested 

persons to file comments after the 

Technical Conference to address issues 

raised during the Technical Conference. 

C. Joint Federal-State Task Force on 

Electric Transmission 

20. On June 17, 2021, the Commission 

established a Joint Federal-State Task 

Force on Electric Transmission (Task 

Force) to formally explore broad 

categories of transmission-related 

topics.26 The Commission explained 

that the development of new 

transmission infrastructure implicates a 

host of different issues, including how 

to plan and pay for these facilities. 

Given that federal and state regulators 

each have authority over transmissionrelated issues and the impact of 

transmission infrastructure 

development on numerous different 

priorities of federal and state regulators, 

the Commission determined that the 

area is ripe for greater federal-state 

coordination and cooperation.27 The 

Task Force is comprised of all FERC 

Commissioners as well as 

representatives from 10 state 

commissions nominated by the National 

Association of Regulatory Utility 

Commissioners (NARUC), with two 

originating from each NARUC region.28


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meetings, are available in the Commission’s 

eLibrary in Docket No. AD21–15–000. 

29 Joint Fed.-State Task Force on Elec. 

Transmission, Notice of Meeting, Docket No. AD21– 

15–000 (issued Oct. 27, 2021) (attaching agenda). 

30 Joint Fed.-State Task Force on Elec. 

Transmission, Notice of Meeting, Docket No. AD21– 

15–000 (issued Feb. 2, 2022) (attaching agenda). 

31See Appendix A for a list of commenters and 

the abbreviated names of commenters that are used 

in this NOPR. 

32See supra PP 12–14. 33S.C. Pub. Serv. Auth., 762 F.3d at 56–59. 

21. The Task Force will convene for 

multiple formal meetings and has thus 

far met twice—on November 10, 2021, 

and on February 16, 2022. The 

discussion at the November meeting 

was focused on incorporating state 

perspectives into regional transmission 

planning. The Task Force members 

discussed: Whether the existing regional 

transmission planning processes 

adequately plan for future transmission 

needs, including those of states in 

meeting their energy-related goals; what 

methods are currently employed to 

provide states a role in regional 

transmission planning processes and 

whether reforms are needed to increase 

consideration and incorporation of state 

perspectives and energy-related goals in 

those processes; transparency in 

existing regional transmission planning 

processes; and criteria for use in 

selecting transmission facilities, 

including the proper role for states in 

selection of transmission facilities 

identified during regional transmission 

planning processes.29

22. The February meeting included 

discussion of specific categories and 

types of transmission benefits that 

transmission providers should consider 

for the purposes of transmission 

planning and cost allocation. The Task 

Force Members discussed: Whether and 

how the three categories and types of 

transmission (to address transmission 

needs driven by reliability, economic 

considerations, and Public Policy 

Requirements) that are considered for 

the purposes of transmission planning 

and cost allocation should be expanded 

or changed; whether these categories are 

being adequately considered or can be 

improved upon; if there any specific 

benefits being considered by public 

utility transmission providers today that 

should be more widely adopted by other 

public utility transmission providers 

and whether certain benefits are unique 

to specific regions; and how the 

certainty of benefits should be 

addressed, such as whether and how 

benefits need to be quantified. The Task 

Force Members also discussed at the 

February meeting cost allocation 

principles, methodologies, and decision 

processes, such as whether the current 

cost allocation methodologies used by 

public utility transmission providers 

allocate costs roughly commensurate 

with estimated benefits, and if not, how 

should this be improved; under what set 

of benefits—both existing and 

expanded—would states be amenable to 

bearing the costs of transmission that is 

expected to deliver those estimated 

benefits to ratepayers; and whether 

there is sufficient opportunity for 

stakeholders, including states, to 

collaborate in the development and 

approval of cost allocation 

methodologies to build consensus 

among and increase buy-in from 

stakeholders within a transmission 

planning region, and if not, how this 

can be improved.30

D. High-Level Overview of ANOPR 

Comments 

23. The Commission received many 

comments from a diverse set of parties 

in response to the ANOPR.31 One 

hundred and seventy five parties, 

including federal agencies, state 

regulatory commissions, state policy 

makers and other state representatives, 

ratepayer advocates, municipalities, 

RTOs/ISOs, RTO/ISO market monitors, 

public utility transmission providers, 

transmission-dependent utilities, 

electric cooperatives, municipal power 

providers, independent power 

producers, transmission developers, 

generation trade associations, 

transmission trade associations, 

industry interest groups, consumer 

interest groups, energy policy and law 

interest groups, individual businesses, 

landowners, and individuals, filed 

initial comments that totaled over 4,000 

pages without attachments. A similarly 

diverse set of 95 parties filed reply 

comments that totaled nearly 2,000 

pages. 

III. Need for Reform 

24. Over the last 25 years, the 

Commission has undertaken a series of 

significant reforms to ensure that 

transmission planning and cost 

allocation processes result in 

Commission-jurisdictional rates that are 

just and reasonable and not unduly 

discriminatory or preferential.32 It has 

now been more than a decade since 

Order No. 1000—the Commission’s last 

significant regional transmission 

planning and cost allocation rule—and 

there is mounting evidence that the 

Commission’s regional transmission 

planning and cost allocation 

requirements may be inadequate to 

ensure Commission-jurisdictional rates 

remain just and reasonable and not 

unduly discriminatory or preferential. 

In particular, although public utility 

transmission providers are required to 

participate in regional transmission 

planning and cost allocation processes 

under Order No. 1000, we are concerned 

that those processes may not be 

planning transmission on a sufficiently 

long-term, forward-looking basis to meet 

transmission needs driven by changes in 

the resource mix and demand. 

25. As a result, the regional 

transmission planning and cost 

allocation processes that public utility 

transmission providers adopted to 

comply with Order No. 1000 may not be 

identifying the more efficient or costeffective transmission facilities. We are 

concerned that the absence of 

sufficiently long-term, comprehensive 

transmission planning processes 

appears to be resulting in piecemeal 

transmission expansion to address 

relatively near-term transmission needs. 

We are concerned that continuing with 

the status quo approach may cause 

public utility transmission providers to 

undertake relatively inefficient 

investments in transmission 

infrastructure, the costs of which are 

ultimately recovered through 

Commission-jurisdictional rates.33 That 

dynamic may result in transmission 

customers paying more than necessary 

to meet their transmission needs, 

customers forgoing benefits that 

outweigh their costs, or some 

combination thereof—either or both of 

which could potentially render 

Commission-jurisdictional rates unjust 

and unreasonable or unduly 

discriminatory or preferential. As the 

Commission has an obligation under the 

FPA to ensure that those rates are just 

and reasonable and not unduly 

discriminatory or preferential, we are 

proposing reforms to remedy these 

potential deficiencies in the 

Commission’s existing regional 

transmission planning and cost 

allocation requirements. 

26. As explained in the next section, 

we believe that there are substantial 

potential benefits of long-term regional 

transmission planning and cost 

allocation to identify and plan for 

transmission needs driven by changes in 

the resource mix and demand. But, as 

explained below, expansion of the high 

voltage transmission system is 

apparently increasingly occurring 

outside of the regional transmission 

planning process, and in a piecemeal 

fashion through other avenues, such as 

the generator interconnection process 

primarily in response to individual (or 

a small cluster of) interconnection 

requests rather than through regional 


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34 16 U.S.C. 824, 824d, 824e; see also U.S. DOE 

Comments at 2 (stating that ‘‘strengthening and 

expanding existing transmission infrastructure, 

particularly the development of regional and interregional transmission projects, is key to continued 

access to reliable, resilient, lower-cost, and clean 

electricity for all’’). 35See, e.g., Testimony of James B. Robb Before 

the U.S. Senate Energy and Natural Resources 

Committee, Reliability, Resiliency, and Affordability 

of Electric Service in the United States Amid the 

Changing Energy Mix and Extreme Weather Events, 

at 9 (Mar. 11, 2021), https://www.nerc.com/news/ 

Headlines%20DL/NERC%20

Reliability%20Hearing%20Testimony%203-11- 

21%20-%20Final.pdf (testifying that more 

transmission infrastructure is required to ensure 

reliability and resilience of the bulk power system 

in light of changing conditions); MISO Comments 

at 40. 

36U.S. DOE Comments at 18; NERC Comments at 

16–17; ACORE Comments, Ex. 4, Transmission 

Makes the Power System Resilient to Extreme 

Weather; Mark Chupka & Pearl Donohoo-Vallett, 

Recognizing the Role of Transmission in Electric 

System Resilience (May 2018). 

37MISO’s Multi-Value Project (MVP) regional 

transmission planning process, for example, 

eliminated the need for approximately $300 million 

in reliability transmission facilities, resolving 

reliability violations and mitigating system 

instability conditions, through a forward-looking 

approach. Midcontinent Independent System 

Operator, MTEP17 MVP Triennial Review: A 2017 

review of the public policy, economic, and 

qualitative benefits of the Multi-Value Project 

Portfolio, at 11, 33 (Sept. 2017) (MTEP17 Review). 

38 Johannes Pfeifenberger et al., The Brattle Group 

and Grid Strategies, Transmission Planning for the 

21st Century: Proven Practices that Increase Value 

and Reduce Costs, at 48–49 (Oct. 2021), https://

gridprogress.files.wordpress.com/2021/10/ 

transmission-planning-for-the-21st-century-provenpractices-that-increase-value-and-reduce-costs7.pdf (Brattle-Grid Strategies Oct. 2021 Report); 

Policy Integrity Comments at 13 (citing Mohamed 

Awad et al., The California ISO Transmission 

Economic Assessment Methodology (TEAM): 

Principles and Applications to Path 26, at 3 (‘‘A 

new transmission project can enhance competition 

by both increasing the total supply that can be 

delivered to consumers and the number of suppliers 

that are available to serve load.’’)); PIOs Comments 

at 48 (quoting F.A. Wolak, World Bank, Managing 

Unilateral Market Power in Electricity, Policy 

Research Working Paper; No. 3691, at 8 (2005) 

(‘‘Expansion of the transmission network typically 

increases the number of independent wholesale 

electricity suppliers that are able to compete to 

supply electricity at locations in the transmission 

network served by the upgrade . . . .’’)). 

39See, e.g., PJM Interconnection, L.L.C., PJM 

Value Proposition (2019), https://www.pjm.com/ 

about-pjm/∼/media/about-pjm/pjm-valueproposition.ashx (PJM’s planning of resource 

adequacy over a large region is estimated to result 

in savings of $1.2–1.8 billion.); Midcontinent 

Independent System Operator, Value Proposition 

(2020), https://www.misoenergy.org/about/misostrategy-and-value-proposition/miso-valueproposition/ (MISO estimates $517–572 million in 

savings from more efficient use of existing assets 

and $2.5–3.2 billion from reduced need for 

additional assets.); Southwest Power Pool, SPP’s 

Value of Transmission: 2021 Report and Update 

(Jan. 5, 2022) (SPP estimates $382.7 million in 

adjusted product costs savings in 2020 due to 

transmission investment.). 

40U.S. Dep’t of Energy, National Electric 

Transmission Congestion Study, at 11 (Sept. 2015) 

(stating transmission expansion can strengthen and 

increase the flexibility of the overall network and 

‘‘create real options to use the transmission system 

in ways that were not originally envisioned’’); 

Vikram S. Budhraja et al., Improving Electricity 

Resource Planning Processes by Considering the 

Strategic Benefits of Transmission, 22 ELEC. J. 54 

(Mar. 2009), (high voltage transmission affords 

‘‘mitigation of risks as a form of insurance against 

extreme events’’). 

41See, e.g., Southwest Power Pool, The Value of 

Transmission (Jan. 2016), https://www.spp.org/ 

value-of-transmission/ (A 2016 study of 348 

transmission projects in SPP constructed between 

2012 and 2014 found the overall ratio of benefits 

to costs to be at least 3.5 to 1.); NextEra Comments 

at 95 (citing ACEG, Texas as a National Model for 

Bringing Clean Energy to the Grid (Oct. 2017), 

https://cleanenergygrid.org/texas-national-modelbringing-clean-energy-grid/) (Transmission 

developed due to Texas’s Competitive Renewable 

Energy Zone planning process estimated to save 

$1.7 billion each year in production costs alone, far 

surpassing its $6.9 billion cost.); Brattle-Grid 

Strategies Oct. 2021 Report at 4–8 & app. A 

(describing evidence showing that well-planned 

transmission expansion resulted in lower total cost 

to construct the needed transmission facilities). 

42MTEP17 Review at 4. 

43Midcontinent Independent System Operator, 

RGOS: Regional Generation Outlet Study at 2 (Nov. 

19, 2010) (RGOS Study). MISO staff and 

stakeholders determined that allowing the 

transmission expansion needed to accommodate 

these requests to occur through the generator 

interconnection process ‘‘would not be an efficient 

means for building a cost-effective transmission 

system either immediately, over the next 5–10 year 

period or in the foreseeable future beyond that timeframe.’’ Id. 

44MISO relied on stakeholder surveys of likely 

renewable energy needs over the next 20 years, and 

calculations of the new generation that would be 

needed in order to achieve state renewable portfolio 

transmission planning and cost 

allocation processes. 

27. In light of those concerns, we 

propose reforms to require public utility 

transmission providers to conduct longterm regional transmission planning on 

a sufficiently long-term, forward-looking 

basis to identify and plan for 

transmission needs driven by changes in 

the resource mix and demand. Absent 

such reforms, we are concerned that 

meeting transmission needs driven by 

changes in the resource mix and 

demand through short-term, piecemeal 

transmission expansion will result in 

unjust and unreasonable and unduly 

discriminatory and preferential 

Commission-jurisdictional rates for 

customers. Specifically, without these 

reforms, we believe that regional 

transmission planning processes are 

unlikely to identify the more efficient or 

cost-effective solutions to transmission 

needs driven by changes in the resource 

mix and demand. Thus, we 

preliminarily find that these reforms are 

necessary to ensure that Commissionjurisdictional rates remain just and 

reasonable and not unduly 

discriminatory or preferential. 

A. Potential Benefits of Long-Term 

Regional Transmission Planning and 

Cost Allocation To Identify and Plan for 

Transmission Needs Driven by Changes 

in the Resource Mix and Demand 

28. A robust, well-planned 

transmission system is foundational to 

ensuring an affordable, reliable supply 

of electricity.34 Due to continuing 

changes in both supply and demand, 

ongoing investment in transmission 

facilities is necessary to ensure the 

transmission system continues to serve 

load in a reliable 35 and economically 

efficient fashion. Such investments also 

support enhanced reliability, as larger, 

more integrated transmission systems 

result in a diversity of supply and 

demand conditions and a certain degree 

of redundancy that allows the system to 

better withstand failures during 

unexpected events.36 Proactive, 

forward-looking transmission planning 

that considers evolving supply and 

demand conditions more 

comprehensively can enable potential 

reliability problems and economic 

constraints to be identified and resolved 

before they affect the transmission 

system,37 which can facilitate the 

selection of more efficient or costeffective transmission facilities to meet 

transmission needs. 

29. In addition, transmission can 

unlock the forces of competition, 

changing who can sell to whom, 

eliminating barriers to entry, and 

mitigating market power.38 That, in 

turn, can provide a host of benefits for 

customers, including cost-savings from 

greater access to low-cost power and a 

wider range of resources.39

Transmission infrastructure can also 

serve as a form of insurance for the 

uncertainties of the future, because a 

more robust, integrated transmission 

system has the potential to afford 

consumers the benefits of competition 

and enhanced reliability even if supply 

and demand fundamentals change over 

time.40

30. Given these potential benefits, it 

should be no surprise that investments 

in more efficient or cost-effective 

transmission infrastructure can yield 

substantial benefits to consumers.41 For 

example, MISO’s MVP transmission 

planning process resulted in 

transmission facilities that are estimated 

to generate $2.20 to $3.40 of benefit per 

dollar invested.42

31. MISO achieved these benefits by 

proactively planning over a 20-year 

period for two key drivers of 

transmission needs: The impacts of 

changing state laws on the resource mix, 

and a large increase in the number of 

generator interconnection requests.43 To 

mitigate the uncertainties of such 

projections of need, MISO relied on 

scenarios to consider a range of 

potential future conditions 44 and 


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standards by 2027. MISO also identified the 

location of expected ‘‘renewable energy zones’’ with 

potential to achieve high capacity factors for use in 

its analysis. Id. at 26–29. 

45See, e.g., MTEP17 Review at 16. 

46 Id. at 13. 

47MISO Comments at 9. 

48Order No. 890, 118 FERC ¶ 61,119 at P 57. 

49Order No. 1000, 136 FERC ¶ 61,051 at P 486. 

50 Id. PP 498–501. 

51The Commission’s pro forma large generator 

interconnection agreement (LGIA) defines Network 

Upgrades as: ‘‘the additions, modifications, and 

upgrades to the Transmission Provider’s 

Transmission System required at or beyond the 

point at which the Interconnection Facilities 

connect to the Transmission Provider’s 

Transmission System to accommodate the 

interconnection of the Large Generating Facility to 

the Transmission Provider’s Transmission System.’’ 

Pro forma LGIA Art. 1 (Definitions); see also 

Standardization of Generator Interconnection 

Agreements & Proc., Order No. 2003, 68 FR 49846 

(Aug. 19, 2003), 104 FERC ¶ 61,103, at P 21 (2003) 

(describing network upgrades developed through 

the generator interconnection process as those 

interconnection facilities located at or beyond the 

point where the interconnection customer’s 

generating facility interconnects to the transmission 

provider’s transmission system), 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), cert. denied, 552 U.S. 1230 (2008). We refer 

to network upgrades developed through the 

generator interconnection process as 

interconnection-related network upgrades. 

disclosed the assumptions and inputs 

underlying each.45 The MVP process 

then identified a portfolio of ‘‘no 

regrets’’ transmission projects that were 

projected to provide multiple kinds of 

reliability and economic benefits under 

all the alternate future scenarios 

studied.46 At each stage of the MVP 

process, MISO invested in significant 

stakeholder engagement and 

collaboration, from developing the 

technical parameters underlying its 

scenarios and the weights to give to 

each, to the metrics and methodology 

used to evaluate the portfolio of 

transmission projects.47

32. Although, as illustrated by the 

MVP example, transmission 

infrastructure can provide significant 

benefits to consumers, there are often 

substantial barriers to developing more 

efficient or cost-effective transmission 

facilities. For example, as the 

Commission has long recognized, 

‘‘vertically-integrated utilities do not 

have an incentive to expand the grid to 

accommodate new entries or to facilitate 

the dispatch of more efficient 

competitors.’’ 48 Further, because largescale transmission investments that 

geographically extend or strengthen the 

integration of the transmission system 

are both costly and tend to produce 

widespread benefits, there is significant 

risk that free ridership problems inhibit 

their development.49 In any event, the 

logistics alone of coordinating among 

multiple public utility transmission 

providers within a region, seeking 

support across what is often multiple 

state jurisdictions, and attaining 

sufficient certainty over who will pay 

the costs of the needed transmission 

facilities can thwart investments in 

more efficient or cost-effective 

transmission expansion.50

33. We are concerned that these 

barriers continue to stymie investment 

in more efficient or cost-effective 

transmission facilities. In particular, we 

are concerned that public utility 

transmission providers are not engaging 

in the type of long-term, more 

comprehensive regional transmission 

planning and cost allocation 

processes—like the process used to plan 

the MISO MVPs—that is necessary to 

increase the likelihood that such highly 

beneficial transmission infrastructure is 

developed. Without this kind of 

transmission planning and cost 

allocation process, opportunities to 

meet transmission needs more 

efficiently or cost-effectively may be 

lost. Customers may be forced to pay for 

less efficient or cost-effective 

investment in transmission facilities 

that, for example, achieve lower costbenefit ratios than would otherwise be 

achieved with long-term, more 

comprehensive regional transmission 

planning and cost allocation. In short, 

absent reforms, we are concerned 

customers may be paying more for less. 

B. Unjust and Unreasonable and 

Unduly Discriminatory and Preferential 

Commission-Jurisdictional Rates 

34. The evidence suggests that 

sufficiently long-term, forward-looking 

regional transmission planning and cost 

allocation to meet transmission needs 

driven by changes in the resource mix 

and demand is not occurring in most 

transmission planning regions on a 

regular or consistent basis. As such, 

consumers may not be seeing the 

benefits such as enhanced reliability, 

improved resource adequacy, access to 

lower cost and diverse resources, and 

other benefits that result from regional 

transmission planning and cost 

allocation processes that identify, select, 

and allocate the costs of the more 

efficient or cost-effective transmission 

solutions to transmission needs driven 

by changes in the resource mix and 

demand. We preliminarily find that the 

failure of existing regional transmission 

planning and cost allocation processes 

to perform this type of transmission 

planning and cost allocation is resulting 

in unjust, unreasonable, unduly 

discriminatory, and preferential 

Commission-jurisdictional rates. 

35. More specifically, we 

preliminarily find that reforms are 

needed to the Commission’s existing 

regional transmission planning and cost 

allocation requirements because they 

fail to require public utility 

transmission providers to: (1) Perform a 

sufficiently long-term assessment of 

transmission needs; (2) adequately 

account on a forward-looking basis for 

known determinants of transmission 

needs driven by changes in the resource 

mix and demand; and (3) consider the 

broader set of benefits and beneficiaries 

of transmission facilities planned to 

meet those transmission needs. We 

believe that these deficiencies may be 

resulting in unjust and unreasonable 

and unduly discriminatory and 

preferential Commission-jurisdictional 

rates to the extent that they lead to 

public utility transmission providers 

failing to identify transmission needs 

driven by changes in the resource mix 

and demand, failing to select more 

efficient or cost-effective transmission 

facilities to meet those transmission 

needs, and failing to allocate the costs 

of transmission facilities selected in the 

regional transmission plan for purposes 

of cost allocation to meet those 

transmission needs in a manner that is 

at least roughly commensurate with the 

estimated benefits. 

1. The Transmission Investment 

Landscape Today 

36. We begin with the facts on the 

ground: The evidence suggests that 

long-term regional transmission 

planning and cost allocation to identify 

and plan for transmission needs driven 

by changes in the resource mix and 

demand is not occurring in most 

transmission planning regions on a 

regular or consistent basis. Rather, the 

status quo appears to be resulting in a 

disproportionate share of transmission 

facilities to meet transmission needs 

driven by changes in the resource mix 

and demand being developed outside 

regional transmission planning and cost 

allocation processes, resulting in less 

efficient and cost-effective transmission 

development. Significant expansion of 

the transmission system instead appears 

to occur through interconnection-related 

network upgrades 51 constructed as a 

result of generator interconnection 

requests. Because the generator 

interconnection process is not designed 

to consider how to more efficiently or 

cost-effectively address transmission 

needs beyond the interconnection 

request(s) being studied, it cannot 

achieve the economies of scale in 

transmission investment needed to 


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52 ICF Resources, LLC, Just and Reasonable? 

Transmission Upgrades Charged to Interconnecting 

Generators Are Delivering System-Wide Benefits, at 

2 (Sept. 9, 2021), https://acore.org/wp-content/ 

uploads/2021/09/Just-Reasonable-TransmissionUpgrades-Charged-to-Interconnecting-GeneratorsAre-Delivering-System-Wide-Benefits.pdf (ICF Sept. 

2021 Report) (attached to ACORE Comments as 

Exhibit 5). 

53Americans For A Clean Energy Grid, 

Disconnected: The Need for a New Generator 

Interconnection Policy, at 14 (Jan. 2021), https://

acore.org/wp-content/uploads/2021/01/ 

Disconnected-The-Need-for-a-New-GeneratorInterconnection-Policy-1.14.21.pdf (ACEG Jan. 2021 

Interconnection Report) (attached to ACORE 

Comments as Exhibit 2); NextEra Comments at 16 

(citing Midcontinent Independent System Operator, 

2020 Interconnection Queue Outlook, at 9 (2020), 

https://cdn.misoenergy.org/MISO2020

InterconnectionQueueOutlook445829.pdf (MISO 

2020 Queue Outlook)). 

54 ICF Sept. 2021 Report at 2. 

55ACEG Jan. 2021 Interconnection Report at 14; 

NextEra Comments at 16 (citing MISO 2020 Queue 

Outlook at fig. 7). 

56E.g., ACEG Jan. 2021 Interconnection Report at 

14 & tbl. 2 (showing that, as of 2019, 

interconnection costs in PJM for constructed wind 

and solar projects were $19.07/kW and 61.83/kW, 

respectively, as compared to a greater than 100% 

increase to $54/kW and $131.90/kW, respectively, 

for projects newly proposed today); NextEra 

Comments at 16–17 (stating that interconnectionrelated network upgrade cost estimates have nearly 

tripled for newly proposed wind projects, and more 

than doubled for solar projects in PJM); see also 

ACEG Jan. 2021 Interconnection Report at 16 

(illustrating an increase in average interconnectionrelated network upgrade costs in NYISO from $67/ 

kW in 2013 to $124/kW in 2019). Compare ACEG 

Jan. 2021 Interconnection Report at 15 (identifying 

interconnection-related network upgrade costs in 

2013 in SPP as $89/kW) with ICF Sept. 2021 Report 

at 2 (citing interconnection-related network upgrade 

costs of $448/kW for interconnection customers 

studied in SPP’s system impact study published in 

April 2021). 

57ACEG Jan. 2021 Interconnection Report at 6; 

see also id. at 13 (stating that the rising 

interconnection costs of wind projects in MISO 

recently reached approximately 23% of the capital 

cost of the project); id. at 15 (identifying the 

increase in interconnection-related network 

upgrade costs in SPP between 2013 and 2017 as 

representing an increase from around 8% to over 

43% of the capital cost of wind generation); NextEra 

Comments at 17 (similar). 

58See ACEG Jan. 2021 Interconnection Report at 

15 (describing interconnection-related network 

upgrades for a 120 MW solar plus storage project 

in southern Virginia to interconnect to PJM that cost 

as much as $12,086/kW). 

59See id. (describing one interconnection-related 

network upgrade in SPP identified in the system 

impact study published in April 2021); ICF Sept. 

2021 Report at 3 (same); NextEra Comments at 17 

(same). 

60Brattle-Grid Strategies Oct. 2021 Report at 2 

(citing Johannes Pfeifenberger & John Tsoukalis, 

The Brattle Group, Transmission Investment Needs 

and Challenges, at slide 2 (June 1, 2021), https:// 

www.brattle.com/wp-content/uploads/2021/10/ 

Transmission-Investment-Needs-andChallenges.pdf); Johannes Pfeifenberger et al., The 

Brattle Group, Cost Savings Offered by Competition 

in Electric Transmission: Experience to Date and 

the Potential for Additional Customer Value, at 2– 

3 & fig.1 (Apr. 2019), https://www.brattle.com/wpcontent/uploads/2021/05/16726_cost_savings_

offered_by_competition_in_electric_

transmission.pdf (Brattle Apr. 2019 Competition 

Report). 

61See, e.g., Rob Gramlich & Jay Caspary, 

Americans for a Clean Energy Grid, Planning for the 

Future, at 25 & fig. 8 (Jan. 2021) (included as Ex. 

1 to ACORE Comments) (ACEG Jan. 2021 Planning 

Report) (charting the annual investment in regional 

transmission facilities in RTOs/ISOs from 2010 to 

2018); ACORE Comments at 4 (citing Ex. 1, ACEG 

Jan. 2021 Planning Report at 25). 

integrate significant quantities of new 

generation resources while maintaining 

Commission-jurisdictional rates that are 

just and reasonable and not unduly 

discriminatory or preferential. 

Transmission expansion in this 

incremental manner may miss the 

potential for more efficient or costeffective transmission facilities to solve 

transmission needs driven by changes in 

the resource mix and demand, as well 

as to afford system-wide benefits that 

may not be achieved through piecemeal, 

one-off transmission upgrades. Robust 

long-term regional transmission 

planning, on the other hand, may enable 

the same needs to be met more 

efficiently or cost-effectively, or identify 

transmission facilities that meet those 

same needs while generating additional 

benefits. Today’s incremental 

transmission planning may also fail to 

consider opportunities to ‘‘right size’’ 

certain replacement transmission 

facilities and thereby fail to identify the 

potential for more efficient or costeffective regional transmission facilities. 

37. The problems with the status quo 

are evident in the dramatic increase in 

recent years (and continuing upward 

trend) in investment in transmission 

facilities through the generator 

interconnection process in the form of 

interconnection-related network 

upgrades. The evidence demonstrates a 

sharp growth in both the total cost of 

interconnection-related network 

upgrades and in the cost of such 

upgrades relative to generation project 

costs. It appears that the average cost of 

interconnection-related network 

upgrades is increasing over time as the 

transmission system is fully subscribed 

and demand for interconnection service 

outpaces transmission investment. 

Recent studies of the total cost of 

network upgrades needed to 

interconnect new generation resources 

reflect this trend. In the generator 

interconnection study MISO published 

in July 2020, MISO identified the need 

for nearly $2.5 billion in 

interconnection-related network 

upgrades to interconnect 9.2 GW of 

generation in MISO South.52 In MISO’s 

2020 interconnection queue outlook, 

MISO reported that it expects new 

generation resources in MISO West will 

need over $3 billion in interconnectionrelated network upgrades and noted a 

similar trend in other MISO subregions.53 In its most recent system 

impact study for generator 

interconnection, published in April 

2021, SPP identified the need for over 

$4.6 billion in network upgrades to 

interconnect 10.4 GW of generation.54

38. The dramatic increase in the cost 

of interconnection-related network 

upgrades per kilowatt (kW) of an 

interconnection customer’s generating 

capacity may also be problematic. For 

example, interconnection-related 

network upgrade costs in MISO West 

went from approximately $300/kW in 

2016 to nearly $1,000/kW in 2017.55

The trend is evident in other parts of the 

country as well.56 The costs of 

interconnection-related network 

upgrades seem to have become an evergrowing percentage of the total capital 

costs of new generation projects. 

According to one report, 

interconnection costs for new renewable 

resources were less than 10% of total 

generation project costs until a few 

years ago, but recently these costs have 

risen to as much as 50–100% of the total 

generation project costs.57 At the same 

time, interconnection-related network 

upgrades appear to have transitioned 

from primarily small transmission 

facilities that serve the needs of a 

limited number of interconnection 

customers to the size and scope of what 

has traditionally been considered high 

voltage transmission facilities. For 

example, interconnection-related 

network upgrades have recently 

included demolishing and rebuilding 

multiple 500 kV transmission lines 58

and constructing long, double-circuit, 

765 kV transmission lines,59 all at 

significant cost to the interconnection 

customer—and ultimately to consumers. 

39. In contrast to the significant 

investment in transmission facilities 

through the generator interconnection 

process, the regional transmission 

planning and cost allocation processes 

have yielded limited investment in 

regional transmission facilities. 

Transmission developers in the United 

States invested $20 to $25 billion 

annually in transmission facilities from 

2013 to 2020.60 Yet only a limited 

portion of these investments have gone 

toward regional transmission facilities 

since Order No. 1000. In fact, 

investment in regional transmission 

facilities in some regions has declined 

compared to prior Order No. 1000.61

Moreover, across all the non-RTO/ISO 

regions, there has not yet been a single 

transmission facility selected in a 

regional transmission plan for purposes 


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62LS Power Oct. 12 Comments, app. I, at 18 & 

n.57; FERC, Staff Report, 2017 Transmission 

Metrics, at 19 (Oct. 6, 2017), https://www.ferc.gov/ 

sites/default/files/2020-05/transmissioninvestment-metrics.pdf. 63See generally ACEG Jan. 2021 Planning Report 

at 25–26, 71 (describing investment in local 

transmission facilities nationwide since 

implementation of Order No. 1000). In MISO, 

investment in local transmission facilities went 

from $1.1 billion per year from 2010 to 2013, to $2.7 

billion per year from 2014 to 2019. Harvard ELI 

Comments at 20 & n.89; see also ACEG Jan. 2021 

Planning Report at 104 (charting MISO transmission 

investment by project type from 2010 to 2019); 

ACPA and ESA Comments at 22 (showing $247 

million invested in nine regional transmission 

projects versus $16.6 billion in 2,165 local 

transmission projects in MISO between 2016 and 

2020). In PJM, investment in local transmission 

facilities went from $1.25 billion per year from 2005 

to 2013, to $3.79 billion per year from 2014 to 2020. 

During the same time periods, investment in 

regional transmission facilities decreased from 

$2.76 billion per year to $1.65 billion per year. 

Harvard ELI Comments at 21 n.92; PIOs Comments 

at 33 n.98 (citing PJM Transmission Expansion 

Advisory Committee, Project Statistics (May 12, 

2020)); Ari Peskoe, Is the Utility Transmission 

Syndicate Forever?, 42 Energy L.J. 1, 51 n.324 

(2021), https://www.eba-net.org/assets/1/6/5_-_

%5BPeskoe%5D%5B1-66%5D.pdf. 

64Brattle-Grid Strategies Oct. 2021 Report at 2–3. 

65LS Power October 12 Comments, Ex. 9, at 7. 

66See Order No. 1000–A, 139 FERC ¶ 61,132 at 

P 5. 

67See id. 68See supra PP 28–32. 

69Order No. 1000, 136 FERC ¶ 61,051 at P 3. 70 Id. P 4. The interregional transmission 

coordination and cost allocation requirements were 

aimed at the same objectives with respect to 

possible transmission solutions located in 

neighboring transmission planning regions. Id. 

71 In its 2021 Long-Term Reliability Assessment, 

NERC reports over 504 GW of nameplate capacity 

from new solar and wind in development through 

2031. In contrast, confirmed coal-fired, nuclear, and 

natural-gas-fired retirements through the year 2026 

Continued 

of cost allocation since implementation 

of Order No. 1000.62

40. The vast majority of investment in 

transmission facilities since the 

issuance of Order No. 1000 has been in 

local transmission facilities.63 For 

example, transmission investment to 

resolve local needs accounted for almost 

80% of total transmission investment in 

MISO from 2018 to 2020.64 Similarly, in 

PJM, about two-thirds of the total 

transmission investment in the region 

went to resolving local needs.65

41. This evidence runs counter to the 

Commission’s expectation that, in light 

of growing demand for transmission, the 

regional transmission planning and cost 

allocation reforms adopted in Order No. 

1000 should have resulted in 

investment in more efficient or costeffective transmission facilities over 

time. In Order No. 1000, the 

Commission recognized a growing need 

for transmission investment to ensure 

reliability and integrate new resources 

in light of industry trends changing the 

demands placed on the transmission 

system.66 The Commission concluded 

that increasing transmission needs 

amplified the need for and importance 

of effective transmission planning and 

cost allocation processes to identify 

transmission needs and select regional 

transmission facilities where they are 

more efficient or cost-effective than the 

alternatives.67

42. In sum, the evidence suggests that 

improvements to the Commission’s 

regional transmission planning and cost 

allocation requirements may be needed 

to realize the full potential of the 

benefits to be achieved through the 

planning and development of regional 

transmission facilities. Today, 

transmission needs driven by changes in 

the resource mix and demand appear to 

be largely addressed outside the 

regional transmission process—e.g., 

through generator interconnection 

processes—through mechanisms that 

are not designed to consider regional 

transmission needs and identify and 

select the more efficient or cost-effective 

transmission facility to meet those 

needs. We believe that this may result 

in an inefficient expansion of the 

transmission system to meet 

transmission needs driven by changes in 

the resource mix and demand. 

43. To the extent public utility 

transmission providers may not be 

identifying the more efficient or costeffective transmission facilities needed 

to meet underlying transmission needs, 

including needs driven by changes in 

the resource mix and demand, over 

time, consumers may ultimately bear 

the costs of inefficient piecemeal 

transmission expansion. Moreover, this 

concern may be exacerbated when 

wholesale electricity rates reflect the 

costs of the interconnection-related 

network upgrades that address needs 

that could have been more efficiently or 

cost-effectively addressed through 

effective regional transmission planning 

and cost allocation. Additionally, 

relying on generator interconnection 

processes to identify transmission 

facilities to address transmission needs 

driven by changes in the resource mix 

and demand leaves other benefits on the 

table as well, as described earlier,68

some of which are almost always (if not 

exclusively) achieved through the 

development of regional transmission 

facilities (e.g., avoiding emergency 

operations and lost load, especially 

during extreme weather events, and 

increased wholesale market 

competition). We preliminarily find that 

this paradigm results in Commissionjurisdictional rates that are unjust and 

unreasonable and unduly 

discriminatory and preferential. 

44. While the reforms adopted in 

Order No. 1000 were an important first 

step towards improved regional 

transmission planning and cost 

allocation, we preliminarily find that 

further reforms are necessary to ensure 

that public utility transmission 

providers engage in regional 

transmission planning and cost 

allocation on a sufficiently long-term, 

forward-looking basis to meet 

transmission needs driven by changes in 

the resource mix and demand. In Order 

No. 1000, the Commission was focused 

in particular on: The lack of an 

affirmative obligation for public utility 

transmission providers ‘‘to develop a 

regional transmission plan that reflects 

the evaluation of whether alternative 

regional solutions may be more efficient 

or cost-effective than solutions 

identified in local transmission 

planning processes;’’ the absence of a 

‘‘requirement that public utility 

transmission providers consider 

transmission needs at the local or 

regional level driven by Public Policy 

Requirements;’’ the potential for federal 

rights of first refusal to discourage 

investment by nonincumbent 

transmission developers; the limited 

procedures in place for interregional 

transmission coordination and cost 

allocation; and the failure of many cost 

allocation methods ‘‘to account for the 

beneficiaries of new transmission 

facilities.’’ 69 Order No. 1000 was aimed 

at ensuring two things: (1) That regional 

transmission planning processes 

‘‘consider and evaluate, on a nondiscriminatory basis, possible 

transmission alternatives and produce a 

transmission plan that can meet 

transmission needs more efficiently and 

cost-effectively;’’ and (2) ‘‘that the costs 

of transmission solutions chosen to 

meet regional transmission needs are 

allocated fairly to those who receive 

benefits from them.’’ 70 To that end, the 

Commission adopted reforms that set 

forth the minimum requirements to 

achieve these goals, requirements that 

were noteworthy at the time and 

required public utility transmission 

providers to expend substantial time 

and effort to comply. 

45. We believe that it is time to take 

the next step. The generation fleet is 

changing rapidly. In many cases, this is 

taking the form of a shift from large, 

centralized resources located close to 

population centers toward renewable 

resources (sometimes in combination 

with electric storage resources) that are 

often, but not always, located far from 

load centers where access to their fuel 

source, such as the wind or the sun, is 

greatest.71 The growth in these resource 


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total approximately 48.4 GW. NERC, 2021 LongTerm Reliability Assessment, at 30, 35 (Dec. 2021). 72See Lawrence Berkeley National Laboratory, 

Wind Energy Technology Data Update: 2020 

Edition, at 66 (Aug. 2020) (noting the average 

levelized cost of wind energy for commercial wind 

generation has decreased from $90 per MWh in 

2009, to $35 per MWh in 2019); Lawrence Berkeley 

National Laboratory, Utility-Scale Solar Data 

Update: 2020 Edition, at 32 (Nov. 2020) (noting the 

average levelized power purchase agreement price 

for utility-scale solar generation has decreased from 

approximately $160 per MWh in 2009, to 

approximately $40 per MWh in 2020). 

73See National Renewable Energy Laboratory 

(NREL), H2 2020 Solar Industry Update, at 31 

(2021) (stating that U.S. corporate solar contracts 

were up 34% annually in 2020, and 7.4 times 

higher over 5 years). 74See Deloitte, Insights, Utility Decarbonization 

Strategies, Renew, Reshape, and Refuel to Zero, at 

4 (2020) (indicating 43 of 55 utilities surveyed have 

emissions reductions targets and 22 have net-zero 

or carbon-free electricity goals); Esther Whieldon, 

S&P Global Market Intelligence, Path to net zero: 

70% of biggest US utilities have deep 

decarbonization targets, at 3–6 (2020) (indicating 

based on a review of utilities’ climate goals and 

decarbonization plans that, as of December 2020, 

70% of the 30 largest utilities have net-zero carbon 

targets, or are moving to comply with similarly 

aggressive state mandates). 

75See Lawrence Berkeley National Laboratory, 

U.S. Renewables Portfolio Standards 2021 Status 

Update: Early Release, at 9 (Feb. 2021) (stating 

renewable portfolio standards exist in 30 states and 

the District of Columbia, and apply to 58% of total 

U.S. retail electricity sales). 76For example, the electrification of end uses that 

currently rely on other energy sources is expected, 

under a moderate scenario that does not factor in 

public policy drivers, to increase electricity demand 

by 2050 to about 25% above today’s level. ACEG 

Jan. 2021 Planning Report at 35 (discussing 

National Renewable Energy Laboratory’s ‘‘medium 

electrification’’ case); see also AEE Comments at 

14–18 (describing local, state, and federal policies, 

technical and economic trends that are leading to 

increased electrification). 

77For example, during Winter Storm Uri in 

February 2021, SPP and MISO were able to avoid 

major power shortfalls during the extreme cold by 

importing electricity from the east. During the 

event, MISO imported nearly 9,000 MW from PJM 

and several thousand MW from the Tennessee 

Valley Authority. ACORE Comments, Ex. 4, 

Transmission Makes the Power System Resilient to 

Extreme Weather, at 7. 

78Moreover, we note that efforts for further 

regional integration of power markets continue 

today. See, e.g., Kassia Micek, Megawatt Daily, 

Three Colorado utilities to join SPP’s Western 

Energy Imbalance Service Market (Jan. 26, 2022) 

(‘‘Three Colorado utilities announced plans to join 

[SPP’s] Western Energy Imbalance Service market 

and continue studying long-term solutions to join 

or develop an organized wholesale market.’’). 

79See, e.g., NARUC Comments at 5 (‘‘NARUC 

identifies opportunities for reforms that may result 

in more efficient transmission planning and 

investment to the benefit of consumers, all while 

preserving jurisdictional authorities.’’); NASEO 

Comments at 1 (‘‘NASEO shares the Commission’s 

concern that the current approach to planning and 

allocating the costs of transmission facilities may 

lead to an inefficient, piecemeal expansion of the 

transmission grid.’’); NESCOE Comments at 35 

(‘‘NESCOE appreciates the Commission’s leadership 

in recognizing a need for longer-term and 

comprehensive regional transmission analysis to 

account for this changing resource mix.’’); Kansas 

Commission Comments at 5 (stating ‘‘the KCC 

believes that improvements can be made to 

optimize regional transmission planning policies 

and proceedings’’). 

80 Iowa Consumer Advocate Comments at 1 

(recognizing ‘‘an urgent need to review existing 

processes and identify opportunities for reform’’ 

and that failure to do so could ‘‘negatively impact 

reliability, and result in rates that are unjust and 

unreasonable’’); Consumers Council Comments at 

3–4 (stating reforms are ‘‘crucial’’ and that ‘‘since 

Order No. 1000 was implemented, several 

inefficiencies and unintended consequences have 

emerged in transmission planning’’); District of 

Columbia’s Office of the People’s Counsel 

Comments at 2 (arguing there are ‘‘significant 

flaws’’ in the regional transmission planning 

process in PJM). 

81See, e.g., NY TOs Comments at 14 (‘‘In 

conclusion, the NY TOs support the ANOPR’s goals 

of proactive, multi-value scenario modeling and 

recognize that further refinements to New York’s 

transmission planning processes and modeling will 

likely be needed to integrate renewables and to 

maintain reliability.’’); SoCal Edison Comments at 

3 (asserting that ‘‘enhancements are necessary’’ to 

CAISO’s regional transmission planning structure); 

AEP Comments at 2 (encouraging the Commission 

‘‘to consider broad reforms for both transmission 

planning and generator interconnections’’). 

82See, e.g., Enel Comments, attach. (Plugging In: 

A Roadmap for Modernizing & Integrating 

Interconnection and Transmission Planning) at 4 

(arguing certain deficiencies result in inadequate 

building of transmission and result in costinefficient solutions for load); Northwest and 

Intermountain Comments at 3–4 (pointing to 

limitations in existing Order No. 1000 processes 

and advocating additional reforms are needed to 

ensure just and reasonable transmission rates). 

83See, e.g., Joint Statement in Support of Large 

Scale Transmission at 1 (ACORE, ACPA, ACEG, 

AEE, National Electrical Manufacturers Association, 

and SEIA, among other signatories, support reforms 

to transmission planning and cost allocation 

policies); WIRES Comments at 7–18 (advocating for 

several reforms to regional transmission planning 

and cost allocation processes, and against others). 

84See, e.g., R Street Comments at 1 (stating 

‘‘planning processes require an overhaul’’); Policy 

Integrity Comments at 1 (arguing ‘‘current 

approaches to transmission planning and cost 

allocation are failing to capture [ ] large potential 

benefits’’). 

85See, e.g., EPSA Comments at 2, 4 (asserting 

reforms will be necessary to accommodate the 

evolving transmission system and longer-term 

regional transmission planning is warranted); 

Industrial Customers Comments at 13 (stating ‘‘[t]o 

be sure, there is room for improvement’’); Northern 

VA Coop Comments at 2 (noting ‘‘improvement is 

possible’’). 

86MISO Comments at 7 (arguing its transmission 

planning process is serving its intended purpose 

but acknowledging ‘‘improvements may be made’’); 

SPP Comments at 9 (stating ‘‘SPP realized there was 

a need to more strategically consider broader 

changes to SPP’s transmission planning process’’); 

PJM Reply Comments at 6 (stating ‘‘it is appropriate 

to enhance the long-term planning process to 

consider scenario planning and the interaction of 

many system enhancement drivers’’); ISO–NE 

Comments at 26 (noting ‘‘improvements may be 

needed to optimize transmission solutions for 

reliability, economic, and public policy based 

needs’’); NYISO Comments at 2 (‘‘NYISO sees an 

opportunity to build on the existing successes of its 

processes and to evolve them to address current 

conditions.’’); CAISO Comments at 2 (supporting 

the goal of enhancing regional transmission 

planning and generator interconnection processes 

to account for the transmission needs of a changing 

resource mix). 

87See, e.g., SPP Comments at 10 (SPP Board of 

Directors-appointed team identified critical issues 

with existing transmission planning process 

including sub-optimal transmission plans; 

deficiency in collective quantification of costcausers and beneficiaries which create free rider 

situations; and failure to consider congestion costs 

and other economic impacts in processes used to 

types is driven by many factors, 

including: (1) The improved economics 

of certain renewable resources; 72 (2) 

increased customer demand for such 

resources, including among major 

corporations; 73 (3) utility commitments 

to procure most or all of their electricity 

from renewable and/or non-emitting 

resources; 74 and (4) federal, state, and 

local policies incentivizing various 

forms of generation resources and other 

technologies.75 Similarly, changes in 

electric demand and associated load 

profiles are occurring as load-serving 

entities shift to meet increasing needs 

due to the electrification of our power 

system as well as new large loads 

associated with evolving industrial and 

commercial needs such as the growth in 

data centers.76 Moreover, transmission 

system operators are also increasing 

their reliance on regional and 

interregional transmission facilities to 

ensure operational stability in light of 

the rising share of variable resources in 

the resource mix and increasingly 

frequent extreme weather events.77

Lastly, in recognition of the benefits of 

regional power markets, regional 

integration efforts have expanded since 

Order No. 1000, as illustrated by the 

creation of the Western Energy 

Imbalance Market (EIM) and SPP 

Integrated Marketplace in 2014.78 These 

changes in the resource mix and 

demand, operational challenges, and 

increasing regional integration increase 

the importance of engaging in regional 

transmission planning and cost 

allocation to meet long-term 

transmission needs more efficiently or 

cost-effectively. 

46. A diverse range of stakeholders, 

including state and regulatory entities,79

consumer interest groups,80

transmission owners,81 independent 

power producers,82 and various trade 83

and non-government organizations,84

identify the need to build on existing 

regional transmission planning and cost 

allocation processes. A still broader 

range of stakeholders acknowledge, at a 

minimum, that there is scope for 

improvements in existing regional 

transmission planning and cost 

allocation processes.85 While RTOs/ 

ISOs defend the sufficiency of their 

regional transmission planning and cost 

allocation processes, all recognize the 

potential for reforms to respond to 

ongoing developments in the electric 

industry 86 and, in some instances, they 

have initiated analysis and other early 

steps toward proposing reforms.87


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identify needed upgrades.); ISO–NE Comments at 

14–16 (initiating a 2050 Transmission Study at the 

request of ISO–NE states and efforts to incorporate 

a new forward-looking, scenario-based transmission 

planning tool). 

88For example, SPP is required under its tariff to 

conduct a 20-year study of transmission at least 

every five years but is prohibited from using that 

study as the basis for authorizing construction of a 

transmission solution. SPP Market Monitor 

Comments at 4 (citing SPP, OATT, attach. O, § IV.2 

(8.0.0), § IV.2.a) 

89For example, in response to state requests, ISO– 

NE recently initiated a stakeholder process to 

respond to the problem that ‘‘[t]he current processes 

do not support the performance of state-requested 

transmission analysis based on state-developed 

scenarios, inputs and assumptions, nor do they 

support transmission analysis beyond the ten-year 

horizon.’’ ISO–NE, Attachment K Revisions: 

Extended-Term Planning, Transmission Committee, 

at slide 3 (Sept. 28, 2021), https://www.iso-ne.com/ 

static-assets/documents/2021/09/a07_tc_2021_09_

28_attk_ext_trans_presentation.pdf; see also 

Indicated PJM TOs Comments at 25 (stating ‘‘the 

PJM Tariff does not provide concrete time windows 

for scenario planning’’). 

90Policy Integrity Comments at 29. 

91PJM’s long-term assessment of the transmission 

system ostensibly considers a 15-year horizon, for 

example, but does not account for changes to the 

generation mix beyond a 5-year period. See PSEG 

Comments at 11 (stating that ‘‘in practice only new 

resources that are near the end of the 

interconnection queue process and have signed an 

Interconnection Service Agreement are considered 

in the RTEP base case’’); Union of Concerned 

Scientists Comments at 10 & n.11 (‘‘Generation 

additions are unchanged in the 15-year study 

period, as the input assumption has no additional 

information that would expand the set of generators 

included in the forecast.’’). 

92U.S. DOE Comments at 10 (stating failure to 

plan transmission far enough ahead results in 

‘‘adverse implications for system reliability, 

resilience, consumers’ electricity rates, and the 

achievement of clean energy goals’’); MISO Reply 

Comments at 5 (‘‘[G]iven long-term needs of an 

evolving system, additional transmission is 

necessary to reliably serve customers now and into 

the future. These challenges require immediate 

action and further delay only increases the risk that 

system enhancements may not be in place in the 

timeframe needed.’’). 

93U.S. DOE Comments at 10 (‘‘Relying on 

successive small transmission expansion projects to 

meet foreseeable long-term needs may lead to the 

need for expensive retrofits (at customers’ expense) 

at a later date. Economies of scale and network 

economies suggest that an initial larger-scale 

buildout will often represent a lower-cost 

solution.’’); see also Policy Integrity Comments at 

29 (citing A ́ lvaro Garcı ́a-Cerzo et al., Robust 

Transmission Network Expansion Planning 

Considering Non-Convex Operational Constraints, 

98 Energy Econ. (June 2021)). 

2. Deficiencies in the Commission’s 

Existing Regional Transmission 

Planning and Cost Allocation 

Requirements 

47. We preliminarily find deficiencies 

in the Commission’s existing regional 

transmission planning and cost 

allocation requirements are resulting in 

Commission-jurisdictional rates that are 

unjust and unreasonable and unduly 

discriminatory and preferential. In 

particular, we preliminarily find that 

the Commission’s regional transmission 

planning and cost allocation 

requirements fail to require public 

utility transmission providers to: (1) 

Perform a sufficiently long-term 

assessment of transmission needs; (2) 

adequately account on a forwardlooking basis for known determinants of 

transmission needs driven by changes in 

the resource mix and demand; and (3) 

consider the broader set of benefits and 

beneficiaries of regional transmission 

facilities planned to meet those 

transmission needs. We believe that 

these deficiencies may be resulting in 

unjust and unreasonable and unduly 

discriminatory and preferential 

Commission-jurisdictional rates to the 

extent that they lead public utility 

transmission providers to fail to identify 

transmission needs driven by changes in 

the resource mix and demand, select 

more efficient or cost-effective 

transmission facilities to meet those 

transmission needs, and allocate the 

costs of transmission facilities selected 

in the regional transmission plan for 

purposes of cost allocation to meet those 

transmission needs in a manner that is 

at least roughly commensurate with the 

estimated benefits. We address each 

deficiency in turn. 

48. The first deficiency—that the 

Commission’s existing regional 

transmission planning and cost 

allocation requirements do not require 

public utility transmission providers to 

perform a sufficiently long-term 

assessment of transmission needs—is 

reflected across multiple components of 

existing regional transmission planning 

processes, from the degree to which 

studies that inform assessment of 

transmission needs are forward looking, 

to whether forward-looking assessments 

actually inform selection and cost 

allocation of regional transmission 

facilities. Existing regional transmission 

planning and cost allocation processes 

typically look out and plan for 

transmission needs based on a relatively 

near-term horizon. While some existing 

regional transmission planning and cost 

allocation processes may incorporate 

studies or assessments that have a 

longer forward-looking period, these are 

typically for informational purposes and 

do not result in identification of longterm regional transmission needs, 

assessment of transmission alternatives 

to meet those needs, or selection of 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation.88 Such studies or 

assessments may be one-off, available 

only upon request, or conducted at 

irregular intervals.89 Additionally, many 

forward-looking studies treat key 

variables that affect transmission needs, 

such as generation additions and 

retirements, as fixed over the full time 

horizon of the study, even though these 

variables are likely to change.90 Such 

studies are therefore unlikely to 

adequately assess transmission needs 

over the longer-term horizon, as they do 

not attempt to assess the likelihood that 

conditions contributing to transmission 

needs change.91

49. While it is reasonable for regional 

transmission planning and cost 

allocation processes to include nearterm study of the transmission system, 

the absence of any longer-term 

assessment of transmission needs that 

may form the basis for selection and 

cost allocation may prevent public 

utility transmission providers from 

considering regional transmission 

facilities that may be more efficient or 

cost-effective in light of changing 

transmission needs.92 The failure to 

assess longer-term transmission needs is 

particularly problematic given the longlead times necessary to construct large 

(e.g., high voltage or long distance) 

transmission facilities, the potential for 

economies of scale in transmission 

investment, and the long life of 

transmission assets, which will 

continue to serve transmission needs 

well beyond a 5- or 10-year planning 

horizon—all of which suggest that 

relying solely on shorter-term studies 

may fail to identify transmission needs 

and undervalue the benefits of 

transmission investments to meet those 

needs. Moreover, the likelihood that 

near-term assessments will fail to 

identify more efficient or cost-effective 

regional transmission facilities is higher 

during periods, as the sector is now 

experiencing, in which the need for 

transmission is expected to grow 

considerably.93

50. The second deficiency is that 

existing requirements fail to ensure that 

public utility transmission providers 

adequately account on a forwardlooking basis for known determinants of 

transmission needs driven by changes in 

the resource mix and demand. This is 

closely related to the first deficiency in 

the sense that both relate to the failure 

of the existing requirements to result in 

processes that adequately plan for the 

foreseeable future. Orders Nos. 890 and 

1000 afforded flexibility to public utility 

transmission providers to determine the 

inputs, assumptions, and methodologies 

that are used in analyses of the 

transmission system to identify 

transmission needs and produce a 

regional transmission plan. In the 

absence of clear standards, public utility 

transmission providers have adopted 

widely divergent approaches to 


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94See AEE Comments at 10 (explaining that the 

majority of U.S. electricity customers take service 

from a load-serving entity subject to legally binding 

requirements that affect the resource mix). 

95See SPP Market Monitor Comments at 3 & n.5 

(describing that even SPP’s more forward-looking 

scenario analysis of an emerging technology case in 

its Integrated Transmission Plan presently 

underestimates the actual growth of renewables so 

much that ‘‘[w]ind capacity in service today (29.8 

GW) already exceeds wind levels projected in both 

2019 ITP futures that go out to 2029’’); AEE 

Comments at 18 (MISO projects electrification effect 

on load in its long-term regional transmission 

planning, but how other transmission providers 

account for electrification trends is not consistent 

or transparent.); Brattle-Grid Strategies Oct. 2021 

Report at 36 (stating that production cost 

simulations that are typically used to estimate the 

economic benefit of regional transmission facilities 

assumes no extreme weather events); U.S. DOE 

Comments, app. B (National Laboratories ’s 

Supplemental Information to Comments of 

Department of Energy to Advance Notice of 

Proposed Rulemaking (ANOPR)) at 79 (stating an 

array of tools exist to identify and analyze highvalue zones). 

96NERC Comments at 17–18 (‘‘Coordination and 

better certainty around anticipated future resource 

mix during transmission planning and 

interconnection studies could improve reliability 

assessments associated with the changing resource 

mix[.]’’); ACPA and ESA Comments at 29 (claiming 

the current approach ‘‘delays overall investment in 

the transmission system’’); AEE Comments at 8 

(arguing existing transmission planning processes’ 

failure to capture ‘‘documented and predictable 

trends in electricity demand and threats to the 

reliability, resilience, and sufficiency of the bulk 

electricity system’’ warrant reforms). 

97 Ill. Commerce Comm’n v. FERC, 576 F.3d 470, 

477 (7th Cir. 2009). Order No. 1000, 136 FERC 

¶ 61,051 at PP 622, 639 (requiring costs of regional 

transmission facilities to be allocated in a manner 

that is at least roughly commensurate with 

estimated benefits). 

98See infra P–235– . 

determining the factors that are relevant 

to regional transmission planning and 

addressing uncertainty in these 

variables. The result is that public 

utility transmission providers in some 

transmission planning regions do a 

better job than others in accounting for 

changes in the resource mix and 

demand when performing transmission 

planning studies. We are concerned that 

the reality is that none do so in a 

manner that ensures the consideration 

of more efficient or cost-effective 

transmission facilities to meet 

transmission needs driven by changes in 

the resource mix and demand. 

51. While we recognize the inevitable 

uncertainty in forecasting, a number of 

factors that increasingly shape the 

resource mix and demand are known in 

advance and have reasonably 

predictable effects, especially in the 

aggregate. For example, the economics 

of new and existing generating facilities 

has predictable effects on the resource 

mix, including which existing 

generating facilities are likely to retire 

and which type of new generating 

facility is likely to be built to replace 

them. Similarly, state laws, utility 

integrated resource plans and resource 

procurements, and other regulatory 

actions necessarily implicate the 

resource mix and demand for 

Commission-jurisdictional services.94

There are other known determinants of 

transmission needs as well, including 

factors affecting electricity demand (e.g., 

electrification trends, energy efficiency 

improvements, and demand response 

deployments), the risk of extreme 

weather, information derived from the 

generator interconnection process about 

needed transmission expansion, and the 

locations where transmission needs are 

likely to be particularly acute or 

concentrated because of desirable siting 

conditions for new generating facilities. 

Yet it appears that existing regional 

transmission planning processes may 

undervalue or entirely omit 

consideration of some or all of these 

factors.95

52. We believe that engaging in 

regional transmission planning without 

adequate consideration of such factors 

may be leading to transmission 

investment that is not more efficient or 

cost-effective and, in turn, Commissionjurisdictional rates that are unjust and 

unreasonable and unduly 

discriminatory and preferential.96 We 

believe that this deficiency may delay 

planning for the transmission system’s 

changing operational needs until shortly 

before those needs manifest, despite the 

fact that the continued shift in the 

resource mix and changes in demand 

can be reasonably forecast based on 

known factors. As explained above, the 

lack of sufficient long-term transmission 

planning appears to be resulting in 

significant transmission investment in 

recent years occurring through generator 

interconnection processes to satisfy 

near-term transmission needs, resulting 

in piecemeal development of 

transmission facilities that may not 

more efficiently or cost-effectively meet 

transmission needs driven by changes in 

the resource mix and demand. We 

expect the problems created by this 

deficiency to only grow more acute as 

the factors that impact the resource mix 

and demand are poised to continue 

increasing in their impact on 

transmission needs. 

53. The third potential deficiency is 

that public utility transmission 

providers may not identify a sufficiently 

broad set of benefits—and 

beneficiaries—associated with regional 

transmission facilities planned to meet 

transmission needs driven by changes in 

the resource mix and demand. Failing to 

adequately identify and consider the 

benefits of such transmission facilities 

may lead to sub-optimal or inefficient 

investment therein. In particular, the 

cost-benefit analyses that are used as 

part of the selection process may fail to 

identify more efficient or cost-effective 

transmission facilities for selection in 

the regional transmission plan for 

purposes of cost allocation because they 

provide an inaccurate portrayal of the 

comparative benefits of different 

transmission facilities. In addition, by 

not considering an expanded set of 

benefits and beneficiaries, cost 

allocation methods may fail to assign 

the costs of such facilities to 

beneficiaries in a manner that is at least 

roughly commensurate with the benefits 

they derive from them.97

54. We recognize that, in addressing 

these deficiencies, the Commission 

would be requiring public utility 

transmission providers to plan on a 

longer-term and more comprehensive 

basis. As discussed below, we 

acknowledge that such transmission 

planning may entail a more complex set 

of considerations compared to existing 

regional transmission planning 

requirements, which, in turn, may 

increase the importance of ensuring that 

the cost allocations method for projects 

identified and developed through these 

processes are perceived as fair.98 As 

discussed below, we are proposing to 

address these concerns in part through 

greater state involvement, particularly 

in the development of cost allocation 

methods. 

55. In sum, we preliminarily find that 

the deficiencies in the Commission’s 

existing regional transmission planning 

and cost allocation requirements that we 

identify in this NOPR are resulting in 

Commission-jurisdictional rates that are 

unjust and unreasonable and unduly 

discriminatory and preferential. To 

address the enumerated deficiencies 

and ensure that Commissionjurisdictional rates are just and 

reasonable and not unduly 

discriminatory or preferential, we 

propose reforms to these requirements, 

as described in detail in the sections 

that follow. 

IV. Regional Transmission Planning 

56. We preliminarily find that reforms 

to public utility transmission providers’ 

regional transmission planning 

processes are necessary to ensure that 

Commission-jurisdictional rates are just 

and reasonable and not unduly 

discriminatory or preferential. As 

discussed below, the regional 

transmission planning reforms proposed 

in this NOPR would require that public 

utility transmission providers conduct 

regional transmission planning on a 


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99ANOPR, 176 FERC ¶ 61,024 at P 13. 100NERC,Glossary of Terms Used in NERC 

Reliability Standards (June 28, 2021), https://

www.nerc.com/pa/Stand/ 

Glossary%20of%20Terms/Glossary_of_Terms.pdf. 

101Long-term planning for reliability by RTO/ISO 

varies as follows: CAISO at least 10 years (CAISO, 

CASIO eTariff, § 24.2 (Nature of the Transmission 

Planning Process) (6.0.0)); ISO–NE between 5 and 

10 years (ISO–NE, Transmission, Markets and 

Services Tariff, attach. K (Regional System Planning 

Process) (27.0.0), § 3.3 (RSP Planning Horizon and 

Parameters))); MISO maximum of 20 years (MISO, 

FERC Electric Tariff, attach. FF (Transmission 

Expansion Planning Protocol) (85.0.0), § I.C.8.a)); 

NYISO years 4 through 10 (NYISO, NYISO Tariffs, 

NYISO OATT, § 31.1, attach. Y (New York 

Comprehensive System Planning Process) (26.0.0)); 

PJM 10 years (PJM, Intra-PJM Tariffs, OA Schedule 

6, § 1.4 (Contents of the Regional Transmission 

Expansion Plan) (2.1.0), § 1.4.b)); and, SPP 10 and 

20 years (Southwest Power Pool, Inc., OATT, 

attach. Y, § III (The Integrated Transmission 

Planning Assessment) (8.0.0), § IV (Other Planning 

Studies) (8.0.0)). 

102For 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. 

Transmission Planner is defined as ‘‘the entity that 

develops a long-term (generally one year and 

beyond) plan for the reliability (adequacy) of the 

interconnected bulk electric transmission systems 

within its portion of the Planning Authority area.’’ 

NERC, Glossary of Terms Used in NERC Reliability 

Standards (June 28, 2021), https://www.nerc.com/ 

pa/Stand/Glossary%20of%20Terms/Glossary_of_

Terms.pdf. 

103The 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. 

104ANOPR, 176 FERC ¶ 61,024 at P 14. 105Order No. 1000, 136 FERC ¶ 61,051 at PP 3, 

81, 147. 106 Id. P 148. 107 Id. PP 147–148. 108Order No. 890, 118 FERC ¶ 61,119 at P 549. 

sufficiently long-term, forward-looking 

basis to identify and plan for 

transmission needs driven by changes in 

the resource mix and demand. As part 

of this long-term regional transmission 

planning, public utility transmission 

providers would be required, in 

coordination with states, to: (1) Identify 

transmission needs driven by changes in 

the resource mix and demand through 

the development of long-term scenarios 

that satisfy the requirements set forth in 

this NOPR; (2) evaluate the benefits of 

regional transmission facilities to meet 

identified transmission needs driven by 

changes in the resource mix and 

demand over a time horizon that covers, 

at a minimum, 20 years starting from the 

estimated in-service date of the 

transmission facilities; and (3) establish 

transparent and not unduly 

discriminatory criteria to select regional 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation that more efficiently or costeffectively address these transmission 

needs driven by changes in the resource 

mix and demand. Additionally, we 

propose to require that public utility 

transmission providers more fully 

consider dynamic line ratings and 

advanced power flow control devices in 

regional transmission planning 

processes. 

A. Overview of Existing Regional 

Transmission Planning Processes 

57. Public utility transmission 

providers currently plan their 

transmission systems to meet reliability, 

economic, and Public Policy 

Requirements needs identified through 

their regional transmission planning 

process, consistent with Order Nos. 890 

and 1000.99 The next few paragraphs 

provide a brief overview of how public 

utility transmission providers currently 

conduct regional transmission planning. 

1. Reliability Needs 

58. Public utility transmission 

providers within transmission planning 

regions conduct planning studies to 

help ensure the ability of the 

transmission system to meet minimum 

performance requirements under a 

variety of contingencies to provide 

reliable service to customers. These 

studies cover the near-term, which is 

years 1 through 5, and the long-term, 

which covers years 6 through year 10 

and beyond.100 Long-term transmission 

planning varies by public utility 

transmission provider; for example, 

studies conducted by RTOs/ISOs may 

range 10, 15, to 20 years 101 into the 

future depending on the transmission 

planning region’s regional transmission 

planning process and test for violations 

of established North American Electric 

Reliability Corporation (NERC) 

reliability requirements.102 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 withstand a range of 

probable contingencies (e.g., the sudden 

loss of a generator or higher-voltage 

transmission facilities) while reliably 

serving customer demand and 

preventing cascading outages.103

Generally, public utility transmission 

providers identify areas of the 

transmission system that they predict 

will not be in compliance with 

reliability criteria and develop plans to 

achieve compliance. Public utility 

transmission providers examine 

potential transmission facilities to 

mitigate identified reliability criteria 

violations for their feasibility, impact, 

and comparative costs, culminating in a 

recommended regional transmission 

plan.104

2. Economic Needs 

59. Public utility 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 public utility transmission 

providers to perform economic planning 

studies absent a request by 

stakeholders.105 To remedy this 

deficiency, the Commission required in 

Order No. 1000 that, in addition to 

economic planning studies requested by 

stakeholders, public utility transmission 

providers evaluate, through a regional 

transmission planning process and in 

consultation with stakeholders, regional 

transmission facilities that might meet 

the needs of the transmission planning 

region more efficiently or costeffectively than transmission facilities 

identified by individual public utility 

transmission providers in their local 

transmission planning process.106 These 

regional transmission facilities could 

include transmission facilities needed to 

meet reliability requirements, address 

economic considerations, and/or meet 

transmission needs driven by Public 

Policy Requirements.107 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.108 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. Transmission Needs Driven by Public 

Policy Requirements 

60. In Order No. 1000, the 

Commission required public utility 

transmission providers to consider 

transmission needs driven by Public 

Policy Requirements in their local and 

regional transmission planning 


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109Order No. 1000, 136 FERC ¶ 61,051 at PP 203, 

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

110Order No. 1000, 136 FERC ¶ 61,051 at P 220 

(explaining that the requirements in Order No. 1000 

related to transmission needs driven by Public 

Policy Requirements are intended to ‘‘provide 

flexibility for public utility transmission providers 

to develop procedures appropriate for their local 

and regional transmission planning processes’’). 

111 Id. P 215. 

112Order No. 1000–A, 139 FERC ¶ 61,132 at P 

322. 

113E.g., CAISO Comments at 5; MISO Comments 

at 41; ISO–NE Comments at 23; NYISO Comments 

at 26–28; PJM Comments at 3–4; SPP Comments at 

6; AEP Comments at 4; Ameren Comments at 5; BP 

Comments at 3–4; Exelon Comments at 2; National 

Grid Comments at 4; NextEra Comments at 56; 

PG&E Comments at 2; Indicated PJM TOs 

Comments at 3; PSEG Comments at 10–11; SDG&E 

Comments at 2; SCE Comments at 3–4; Shell 

Comments at 7; VEIR Comments at 14; Xcel 

Comments at 19–20; WIRES Comments at 7; EDP 

Renewables Comments at 4; EDF Comments at 5; 

EPSA Comments at 6; ITC Comments at 4; New 

England for Offshore Wind Comments at 1; Certain 

TDUs Comments at 7; ACORE Comments at 6; 

ACPA and ESA Comments at 44; AEE Comments 

at 3; EEI Comments at 12–14; Consumers Council 

Comments at 9; Harvard ELI Comments at 33; 

Nature Conservancy Comments at 2–3; PIOs 

Comments at 60; Resale Iowa Comments at 14; 

REBA Comments at 17; NARUC Comments at 6; 

California Public Utility Commission Comments at 

5; Michigan Commission Comments at 2–3; 

Minnesota Department of Commerce Comments at 

5; New Jersey Commission Comments at 10–11; 

District of Columbia Office of the People’s Counsel 

Comments at 22–23; Oregon Public Utility 

Commission Comments at 1; NEPOOL Comments at 

6–7; SPP RSC Comment at 2; NASUCA Comments 

at 4; Iowa Office Of Consumer Advocate Comments 

at 2; Massachusetts Attorney General Comments at 

2; State of Massachusetts Comments at 2; NESCOE 

Comments at 5–6; NASEO Comments at 1–2; City 

of New York Comments at 4; APPA Comments at 

9; American Municipal Power Comments at 33–34; 

California Municipal Utilities Association 

Comments at 7; Public Systems Comments at 17; 

U.S. DOE Comments at 12, 16; Association of Fish 

and Wildlife Agencies Comments at 3; see also 

ACEG Reply Comments, app. A (identifying 174 

entities supporting planning for a future resource 

mix). 

114For example, AEP, SoCal Edison, and NextEra 

support a 20-year planning horizon. AEP Comments 

at 1–2, 7–8; SoCal Edison Comments at 4; NextEra 

Comments at 70, 79–80. Exelon, PSEG, and NextEra 

support requirements for public utility transmission 

providers to include state statutes and goals in their 

scenarios. Exelon Comments at 12–20; PSEG 

Comments at 3–6; NextEra Comments at 80. LS 

Power and Resale Iowa support a requirement that 

all facilities above 100 kV be regionally planned. LS 

Power Oct. 12 Comments at 49–60; Resale Iowa 

Comments at 8. NextEra supports requiring public 

utility transmission providers to use an expanded 

set of transmission benefits and to designate 

renewable energy development zones. NextEra 

Comments at 92–101. Avangrid supports requiring 

public utility transmission providers to plan for 

offshore wind development. Avangrid Comments at 

21–23. 

115 District of Columbia’s Office of the People’s 

Counsel Comments at 1–5; NARUC Comments at 5– 

7, 46–47; NASUCA Comments at 3–5; Iowa 

Consumer Advocate Comments at 2. 

116CAISO Comments at 3–5; MISO Comments at 

2–4. 

117 ISO–NE Comments at 2, 13–16. 

118NYISO Comments at 2–4. 

119PJM Market Monitor Comments at 2–3. 

120Potomac Economics Comments at 4. 

121SPP Market Monitor Comments at 4. 

122Supra Need for Reform: Unjust and 

Unreasonable and Unduly Discriminatory and 

Preferential Commission-Jurisdictional Rates. For 

example, PJM’s Regional Transmission Expansion 

Plan (RTEP) baseline assessment looks out over a 

5-year period, the NorthernGrid Regional 

Transmission Plan has a 10-year planning horizon, 

and SPP’s Integrated Transmission Plan (ITP) also 

addresses a 10-year horizon. 

processes.109 However, the requirement 

in Order No. 1000 to consider 

transmission needs driven by Public 

Policy Requirements is limited, and the 

Commission provided public utility 

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,110 nor does 

it mandate the consideration of any 

particular transmission need driven by 

a Public Policy Requirement.111 In 

addition, while Order No. 1000 requires 

that public utility transmission 

providers consider transmission needs 

driven by Public Policy Requirements 

proposed by stakeholders, it provides 

flexibility on how active public utility 

transmission providers themselves 

choose to be in identifying such 

needs.112 As a result, the process for 

identifying and considering 

transmission needs driven by Public 

Policy Requirements varies from 

transmission planning region to 

transmission planning region. 

B. Comments 

61. In response to the ANOPR, the 

Commission received many comments 

on the need to reform regional 

transmission planning processes. Many 

comments support long-term regional 

transmission planning.113 Some 

transmission developers and incumbent 

public utility transmission providers 

support efforts to reform aspects of 

existing regional transmission planning 

processes, with some recommending 

that the Commission impose 

prescriptive planning requirements.114

Some state commissions and consumer 

advocates also support the need to 

reform regional transmission planning 

processes, but express concern about 

potential costs and ensuring that such 

costs are allocated commensurate with 

estimated benefits.115

62. Some RTOs/ISOs assert that their 

current regional transmission planning 

processes already incorporate many of 

the potential reforms discussed in the 

ANOPR and ask that the Commission 

provide sufficient flexibility and avoid 

being too prescriptive should it 

undertake those reforms.116 ISO–NE 

states that forward-looking scenario 

planning is underway in ISO–NE and 

asks that the Commission not require a 

one-size-fits-all approach.117 NYISO 

urges the Commission to consider that 

in NYISO, incremental, yet meaningful, 

reforms can implement many of the 

goals of the ANOPR, and asks that the 

Commission recognize the need for 

regional variation so that each RTO/ISO 

can improve its regional transmission 

planning process in light of its regional 

needs.118

63. The market monitors express 

mixed views on more comprehensive or 

long-term transmission planning. The 

PJM Market Monitor expresses a 

concern around the lack of certainty and 

quality of additional information being 

included in regional transmission 

planning that may impose additional 

uncertainty on the regional transmission 

planning process.119 Potomac 

Economics expresses concern regarding 

mandating long-term regional 

transmission planning that requires 

public utility transmission providers to 

speculate on certain future conditions, 

but notes improvements could be made 

to the regional transmission planning 

process to account for near-term 

emerging trends that are less uncertain 

than longer-term factors.120 In contrast, 

the SPP Market Monitor expresses a 

concern that SPP’s regional 

transmission planning process is not 

planning for generation resources of the 

future.121

C. Proposed Reforms 

1. Long-Term Regional Transmission 

Planning 

a. Need for Reform 

64. We are concerned that existing 

regional transmission planning 

processes may not be planning on a 

sufficiently long-term, forward-looking 

basis to meet transmission needs driven 

by changes in the resource mix and 

demand, leading to the piecemeal and 

inefficient development of new 

transmission facilities in a manner that 

is not more efficient or cost-effective. As 

discussed above, existing regional 

transmission planning processes 

typically look out and plan for 

transmission needs based on a relatively 

short time horizon.122 While some 

existing regional transmission planning 

processes may incorporate studies or 

assessments that have a longer forwardlooking period, these are typically for 

informational purposes and do not 

result in identification of long-term 

regional transmission needs, assessment 

of transmission alternatives to meet 


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123See infra P 94. 

124See supra P 36. 

125Order No. 1000, 136 FERC ¶ 61,051 at PP 624– 

625. 

126ANOPR, 176 FERC ¶ 61,024 at P 85. 

127See generally Paul L. Joskow, Facilitating 

Transmission Expansion to Support Efficient 

Decarbonization of the Electricity Sector, 

Economics of Energy & Environmental Policy, Vol. 

10, No. 2 (June 2021); Johannes Pfeifenberger et al., 

The Value of Diversifying Uncertain Renewable 

Generation through the Transmission System, 

Boston University Institute for Sustainable Energy 

(Sept. 1, 2020); Johannes Pfeifenberger et al., The 

Brattle Group, Toward More Effective Transmission 

Planning: Addressing the Costs and Risks of an 

Insufficiently Flexible Electricity Grid (Apr. 2015); 

Judy Chang et al., The Brattle Group, The Benefits 

of Electric Transmission: Identifying and Analyzing 

the Value of Investments (2013). 

128For example, two features of Long-Term 

Regional Transmission Planning included in these 

proposed reforms are the development of scenarios 

with a 20-year planning horizon to be reassessed 

and revised every three years, with each such reassessment providing the basis for identification 

and evaluation of transmission facilities for 

potential selection in the regional transmission plan 

for purposes of cost allocation. 

129We use the term Long-Term Scenarios in this 

NOPR to describe a tool to identify transmission 

needs driven by changes in the resource mix and 

demand, and enable the evaluation of transmission 

facilities to meet such needs, across multiple 

scenarios that incorporate different assumptions 

about the future electric power system over a 

sufficiently long-term, forward-looking 

transmission planning horizon. 

those needs, or selection of transmission 

facilities in the regional transmission 

plan for purposes of cost allocation.123

In lieu of such a long-term outlook, 

transmission needs driven by changes in 

the resource mix and demand are 

largely addressed through generator 

interconnection processes.124 However, 

such processes are not designed to 

evaluate the need for larger, regional 

transmission facilities to address 

transmission needs driven by changes in 

the resource mix and demand, resulting 

in a piecemeal expansion of the electric 

transmission system. 

65. Implementation challenges 

associated with long-term transmission 

planning—such as determining the 

appropriate time horizon, selecting a set 

of factors to forecast the future resource 

mix and demand, and choosing the 

appropriate method to account for 

uncertainty—make it unlikely that 

public utility transmission providers 

will engage in such transmission 

planning voluntarily and regularly. 

However, such challenges do not 

diminish the importance of long-term 

transmission planning. Moreover, even 

if long-term regional transmission 

planning is performed, failing to 

consider an adequate time horizon, set 

of factors to forecast the future resource 

mix and demand, and sufficient method 

to account for uncertainty—may result 

in transmission planning that is 

inadequate in identifying more efficient 

or cost-effective transmission facilities 

due a less comprehensive and accurate 

understanding of the areas impacted by 

transmission needs driven by changes in 

the resource mix and demand. 

Accordingly, we believe that reforms 

may be necessary to require public 

utility transmission providers to 

identify transmission needs driven by 

changes in the resource mix and 

demand. 

66. We are also concerned that 

existing regional transmission planning 

requirements may be inadequate to 

ensure that public utility transmission 

providers adequately assess the benefits 

of regional transmission facilities 

planned to meet transmission needs 

driven by changes in the resource mix 

and demand. In Order No. 1000, the 

Commission declined to prescribe 

particular definitions of or a uniform 

approach to identifying benefits and 

beneficiaries, in order to allow 

flexibility for public utility transmission 

providers to develop cost allocation 

methods for their transmission planning 

regions.125 However, transmission 

facilities may provide a wide variety of 

benefits to transmission customers, 

particularly for regional transmission 

facilities addressing large, systemic 

changes in the electric industry. We 

recognize that when public utility 

transmission providers fail to consider a 

broader set of benefits for transmission 

facilities meeting transmission needs 

driven by changes in the resource mix 

and demand, they may fail to select 

transmission facilities in their regional 

transmission plans for purposes of cost 

allocation that meet the transmission 

planning region’s transmission needs 

more efficiently or cost-effectively. 

67. As described in the ANOPR, 

existing regional transmission planning 

and cost allocation processes generally 

examine categories of transmission 

needs separately from one another based 

on the driver of the relevant 

transmission need, be it reliability, 

economic considerations, or Public 

Policy Requirements.126 As a general 

matter, public utility transmission 

providers only calculate the set of 

benefits specific to that category of 

transmission need for purposes of 

determining whether a regional 

transmission facility meets the criteria 

for selection. However, the literature 

and experience demonstrates a panoply 

of benefits beyond those currently 

considered by all public utility 

transmission providers in existing 

regional transmission planning and cost 

allocation processes.127 Failing to 

provide for the allocation of costs of 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation to address 

transmission needs driven by changes in 

the resource mix and demand in a way 

that aligns with a reasonable set of 

benefits through the transmission 

planning process could lead to needed 

transmission facilities not being built, 

adversely affecting ratepayers. 

Accordingly, we propose a list of 

benefits for public utility transmission 

providers to consider when assessing a 

broader set of benefits during long-term 

regional transmission planning, and 

require public utility transmission 

providers to provide certain 

information, as described below, about 

the benefits they will use. 

b. Proposed Reform 

68. To help to ensure just and 

reasonable and not unduly 

discriminatory or preferential 

Commission-jurisdictional rates, we 

propose to require that public utility 

transmission providers participate in a 

regional transmission planning process 

that includes Long-Term Regional 

Transmission Planning,128 meaning 

regional transmission planning on a 

sufficiently long-term, forward-looking 

basis to identify transmission needs 

driven by changes in the resource mix 

and demand, evaluate transmission 

facilities to meet such needs, and 

identify and evaluate transmission 

facilities for potential selection in the 

regional transmission plan for purposes 

of cost allocation as the more efficient 

or cost-effective transmission facilities 

to meet such needs. 

69. As discussed further below, we 

propose several specific requirements 

on how public utility transmission 

providers would be required to 

implement the requirement to conduct 

Long-Term Regional Transmission 

Planning. Specifically, we propose to 

require that public utility transmission 

providers in each transmission planning 

region: (1) Identify transmission needs 

driven by changes in the resource mix 

and demand through the development 

of Long-Term Scenarios 129 that satisfy 

the requirements set forth in this NOPR; 

(2) evaluate the benefits of regional 

transmission facilities to meet these 

needs over a time horizon that covers, 

at a minimum, 20 years starting from the 

estimated in-service date of the 

transmission facilities; and (3) establish 

transparent and not unduly 

discriminatory criteria to select 

transmission facilities in the regional 

transmission plan for purposes of cost 


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130See Order No. 1000, 136 FERC ¶ 61,051 at P 

11. 

131See id. PP 203–224 (discussing the 

requirement to consider transmission needs driven 

by Public Policy Requirements in regional 

transmission planning processes). This proposal 

would also leave unchanged the existing 

requirement for public utility transmission 

providers to consider transmission needs driven by 

Public Policy Requirements in their local 

transmission planning processes. 

132See id. P 2. 

allocation that more efficiently or costeffectively address these transmission 

needs in collaboration with states and 

other stakeholders. We discuss each of 

these requirements in greater detail 

below. 

70. Taken together, these proposed 

requirements would establish a more 

comprehensive and proactive approach 

to regional transmission planning, 

ensuring that public utility transmission 

providers plan for transmission needs 

driven by changes in the resource mix 

and demand. The Long-Term Regional 

Transmission Planning proposed in this 

NOPR is meant to require regional 

transmission planning based on a 

multitude of drivers of long-term 

transmission needs, as detailed below, 

and result in selection of more efficient 

or cost-effective transmission facilities 

in the regional transmission plan for 

purposes of cost allocation to meet those 

needs. 

71. We recognize that benefits from 

transmission facilities may change over 

time due to the inherent uncertainty in 

Long-Term Regional Transmission 

Planning and actual use of transmission 

facilities. We note that long-term 

benefits may be more stable or evenly 

distributed over time if they are 

evaluated for a portfolio of transmission 

facilities rather than for a single 

transmission facility. We propose to 

provide public utility transmission 

providers with the flexibility to propose 

to use a portfolio approach in the 

evaluation of benefits and selection of 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation through their Long-Term 

Regional Transmission Planning, as 

discussed below in this NOPR. 

72. The reforms proposed in this 

NOPR inevitably interact with the 

existing regional transmission planning 

and cost allocation processes required 

by Order No. 1000 to more efficiently or 

cost-effectively meet transmission needs 

driven by the transmission planning 

region’s reliability, economic, and 

Public Policy Requirements. With 

respect to transmission needs associated 

either with maintaining reliability or for 

addressing economic considerations and 

their associated cost allocation, we do 

not propose in this NOPR to change 

Order No. 1000’s requirements for 

public utility transmission providers to 

create a regional transmission plan that 

will identify transmission facilities that 

more efficiently or cost-effectively meet 

the region’s reliability and economic 

requirements.130 In other words, public 

utility transmission providers may 

continue to rely on their existing 

regional transmission planning and cost 

allocation processes to comply with 

Order No. 1000’s requirements related 

to transmission needs driven by 

reliability concerns or economic 

considerations. 

73. With respect to transmission 

needs driven by Public Policy 

Requirements, while we do not propose 

to change the existing Order No. 1000 

requirement to consider transmission 

needs driven by Public Policy 

Requirements in the regional 

transmission planning process,131 we 

propose to clarify that public utility 

transmission providers will comply 

with this existing Order No. 1000 

requirement through the Long-Term 

Regional Transmission Planning that we 

propose to require in this NOPR. 

Specifically, we propose that public 

utility transmission providers would be 

deemed to comply with the existing 

Order No. 1000 requirement to consider 

transmission needs driven by Public 

Policy Requirements in their regional 

transmission planning process through 

the proposed requirement to conduct 

Long-Term Regional Transmission 

Planning. As discussed in the Factors 

section below, we propose to require 

that public utility transmission 

providers incorporate state or federal 

laws or regulations, meaning enacted 

statutes (i.e., passed by the legislature 

and signed by the executive) and 

regulations promulgated by a relevant 

jurisdiction, whether within a state or at 

the federal level,132 that affect the future 

resource mix and demand into the 

development of Long-Term Scenarios. 

Thus, we preliminarily find that under 

the reforms proposed herein, public 

utility transmission providers that 

comply with the Long-Term Regional 

Transmission Planning requirements 

established in any final rule in this 

proceeding will comply with the 

requirement in Order No. 1000 that they 

participate in a regional transmission 

planning process that considers, and has 

associated cost allocation provisions 

related to, transmission needs driven by 

Public Policy Requirements. 

74. That said, we understand that 

public utility transmission providers in 

some transmission planning regions 

have developed processes to consider 

transmission needs driven by Public 

Policy Requirements through their 

regional transmission planning 

processes that they may wish to retain. 

Therefore, we propose to allow public 

utility transmission providers to 

propose to continue using some or all 

aspects of the existing regional 

transmission planning and cost 

allocation processes they use to 

consider transmission needs driven by 

Public Policy Requirements. However, 

such continued use of existing regional 

transmission planning and cost 

allocation processes would not supplant 

public utility transmission providers’ 

obligations to comply with the LongTerm Regional Transmission Planning 

requirements established in any final 

rule in this proceeding. Moreover, in 

their filing to comply with any final 

rule, public utility transmission 

providers seeking to retain existing 

regional transmission planning and cost 

allocation processes to consider 

transmission needs driven by Public 

Policy Requirements through their 

regional transmission planning 

processes would have to demonstrate 

that continued use of any such 

processes does not interfere or 

otherwise undermine the Long-Term 

Regional Transmission Planning that we 

propose to require in this NOPR by 

demonstrating that continued use of 

such processes is consistent with or 

superior to any final rule issued in this 

proceeding. 

75. Finally, we preliminarily find that 

public utility transmission providers 

could propose a regional transmission 

planning process that plans for 

reliability needs, economic needs, 

transmission needs driven by Public 

Policy Requirements, and transmission 

needs driven by changes in the resource 

mix and demand simultaneously 

through a combined approach. Public 

utility transmission providers proposing 

to address all such transmission needs 

in a single regional transmission 

planning process would bear the burden 

of demonstrating continued compliance 

with Order No. 1000 in addition to 

compliance with the requirements of 

any final rule in this proceeding; to do 

so, they would be required to 

demonstrate that such process is 

consistent with or superior to the 

requirements of both Order No. 1000 

and any final rule issued in this 

proceeding. 

76. Further, we propose to require 

that Long-Term Regional Transmission 

Planning comply with the following 

existing Order Nos. 890 and 1000 

transmission planning principles: (1) 

Coordination; (2) openness; (3) 

transparency; (4) information exchange; 


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133See id. PP 146, 151. 

134ANOPR, 176 FERC ¶ 61,024 at P 31. 

135 Id. 

136 Id. P 47. 137 Id. P 46. 138E.g., ACEG Comments at 5; ACPA and ESA 

Comments at 46–47; AEE Comments at 36; AEP 

Comments at 9–11; Ameren Comments at 5; APPA 

Comments at 7–9; Arizona Commission Comments 

at 2; Avangrid Comments at 11–12; Certain TDUs 

Comments at 11; Consumers Council Comments at 

8–9; Union of Concerned Scientists Comments at 

42; East Kentucky Comments at 4–7; EDF 

Comments at 3; EEI Comments at 24–26; Eversource 

Comments at 8; Exelon Comments at 11–19; 

Massachusetts Attorney General Comments at 13; 

NARUC Comments at 10–11; National Grid 

Comments at 11–17; Nature Conservancy 

Comments at 2–5; NESCOE Comments at 39–40; 

New England for Offshore Wind Comments at 2; 

NextEra Comments at 70–83; Northwest and 

Intermountain Comments at 6–8; Oregon 

Commission Comments at 1; PG&E Comments at 5– 

6; PIOs Comments at 76–81; Indicated PJM TOs 

Comments at 24–26; Policy Integrity Comments at 

25–40; PSEG Comments at 6–18; Resale Iowa 

Comments at 14; SAFE Comments at 11; SDG&E 

Comments at 3–4; Shell Comments at 7; State 

Agencies Comments at 21; State of Massachusetts 

Comments at 10–15; Tenaska Comments at 12–13; 

U.S. DOE Comments at 21–22; WIRES Comments at 

7–8; VEIR Comments at 13–17; Xcel Comments at 

19–20. 

139CAISO Comments at 42–44; MISO Comments 

at 7, 49; SPP Comments at 7; NYISO Comments at 

27–31; PJM Comments at 41–42, 45–46; ISO–NE 

Comments at 13–17, 20–22. 

140See SERTP Comments at 8, 14–17; SERTP 

Reply Comments at 11. 

141E.g., AEP Comments at 9–11; Ameren 

Comments at 5; Eversource Comments at 8; Exelon 

Comments at 11–19; National Grid Comments at 

11–17; NextEra Comments at 70–83; PG&E 

Comments at 5–6; PSEG Comments at 6–18; SDG&E 

Comments at 3–4; Xcel Comments at 19–20. 

142E.g., National Grid Comments at 4–9; Exelon 

Comments at 12–16. 

143E.g., Southern Comments at 36–37; Arizona 

Public Service Comments at 2–4; Xcel Comments at 

20. 

144E.g., Berkshire Comments at 12–13. 

145NARUC Comments at 6, 10–11. 

146E.g., Arizona Commission Comments at 2; 

Oregon Commission Comments at 8–9; 

Massachusetts Attorney General Comments at 5–15. 

147E.g., Mississippi Commission Comments at 3; 

Nebraska Commission Comments at 3–4; Michigan 

Commission Comments at 7. 

148PJM Market Monitor Comments at 2–3; 

Potomac Economics Comments at 3–4; see also Joint 

Fed.-State Task Force on Elec. Transmission, 

Technical Conference, Docket No. AD21–15–000, 

Tr. 59:17–24 (Andrew French) (Nov. 10, 2021) 

(November Joint Task Force Tr.) (commenting that 

in SPP, futures projections of renewables have 

‘‘probably not been based on data or reality’’ but 

‘‘have been more of a consensus of what 

stakeholders are willing to accept’’ with the result 

being that those projects have been too low). 

149SPP Market Monitor Comments at 3. 

(5) comparability; and (6) dispute 

resolution.133

77. We seek comment on the 

requirements proposed in this section of 

the NOPR. In particular, we seek 

comment on the proposed requirement 

for public utility transmission providers 

to participate in a regional transmission 

planning process that includes LongTerm Regional Transmission Planning. 

78. As part of this Long-Term 

Regional Transmission Planning, we 

propose to require that public utility 

transmission providers identify 

transmission needs driven by changes in 

the resource mix and demand through 

the development of Long-Term 

Scenarios that satisfy the specific 

requirements that we more fully 

enumerate below. We propose that 

public utility transmission providers: (1) 

Use a transmission planning horizon no 

less than 20 years into the future in 

developing Long-Term Scenarios and 

reassess and revise those scenarios at 

least once every three years; (2) 

incorporate into their Long-Term 

Scenarios a set of Commissionidentified categories of factors that may 

drive transmission needs driven by 

changes in the resource mix and 

demand; (3) develop a plausible and 

diverse set of at least four Long-Term 

Scenarios; (4) use ‘‘best available data’’ 

in developing their Long-Term 

Scenarios; and (5) consider whether to 

identify geographic zones with the 

potential for development of large 

amounts of new generation. 

i. Development of Long-Term Scenarios 

for Use in Long-Term Regional 

Transmission Planning 

79. In the ANOPR, the Commission 

expressed concern 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.134 The Commission 

stated that, to the extent that regional 

transmission planning processes 

consider generation development in 

scenario analyses, they tend to include 

in their baseline reliability model only 

those generators that have completed 

facilities studies, and thus are far along 

in the generator interconnection process 

and will likely come online in the short 

term.135 The Commission stated that 

such a short-term outlook may underforecast longer-term transmission needs 

and that more efficient or cost-effective 

transmission facilities that address 

longer-term needs may never be 

developed.136 The Commission sought 

comment on whether reforms are 

needed regarding how the regional 

transmission planning processes model 

scenarios to ensure they incorporate 

sufficiently long-term and 

comprehensive forecasts of future 

transmission needs.137

(a) Comments 

80. Many commenters responding to 

the ANOPR support scenario 

planning.138 All RTOs/ISOs express 

support for long-term scenario-based 

planning as a current or future practice; 

some request that the Commission allow 

for regional flexibility.139 SERTP states 

that its ‘‘bottom-up’’ regional 

transmission planning process already 

assesses a multitude of scenarios as part 

of each public utility transmission 

provider’s integrated resource planning 

process and that it could perform 

additional, hypothetical scenario 

planning to inform decision makers.140

81. Many public utility transmission 

providers support the idea of scenario 

planning.141 Most of these public utility 

transmission providers support targeted 

reforms that specify guardrails, or 

baselines, in scenario planning. For 

example, some public utility 

transmission providers list the 

minimum set of factors they think 

should be included in a scenario 

planning requirement.142 Other public 

utility transmission providers support 

scenario planning so long as it is strictly 

informational, limited, or nonbinding.143 Some public utility 

transmission providers equate scenario 

planning to their existing integrated 

resource plans.144

82. NARUC supports scenario 

planning as a means to evaluate the 

system needs to integrate state-directed 

resources.145 Other state commissions 

and state representatives express their 

support for scenario planning as 

necessary to identify system needs and 

transmission facilities to address 

them.146 A few state commissions do 

not support the Commission imposing 

specific scenario planning requirements, 

or only support the Commission 

providing guardrails, because they 

believe state regulatory officials in 

collaboration with public utility 

transmission providers are in the best 

position to evaluate the needs of each 

region or because they believe the 

current processes work sufficiently 

well.147 The PJM Market Monitor and 

Potomac Economics do not comment 

specifically on use of scenarios, but 

acknowledge the uncertainty associated 

with transmission planning and 

accuracy of inputs into the transmission 

planning process.148 The SPP Market 

Monitor states that one of its biggest 

challenges related to the transmission 

planning process has been persuading 

stakeholders to adopt an additional 

scenario as part of SPP’s 10-year 

Integrated Transmission Planning 

Assessment.149

83. Several consumer and trade 

organizations support scenario planning 

to assess uncertainty about future 


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150E.g., ACEG Comments at 5; ACPA and ESA 

Comments at 46; AEE Comments at 36; APPA 

Comments at 4; Business Council for Sustainable 

Energy Comments at 4; Union of Concerned 

Scientists Comments at 42–44; Consumers Council 

Comments at 8–9; Iowa Consumer Advocate 

Comments at 32; Nature Conservancy Comments at 

3; WIRES Comments at 7. 

151See, e.g., NARUC Comments at 17; PIOs 

Comments at 103; Policy Integrity Comments 29– 

40; U.S. DOE Comments at 33. 

152Supra Need for Reform: Potential Benefits of 

Long-Term Regional Transmission Planning and 

Cost Allocation to Identify and Plan for 

Transmission Needs Driven by Changes in the 

Resource Mix and Demand. 

153Supra Need for Reform: Deficiencies in the 

Commission’s Existing Regional Transmission 

Planning and Cost Allocation Requirements. 

transmission needs.150 Some 

commenters call for a national uniform 

framework for scenario planning.151

(b) Proposed Reform 

84. We propose to require that public 

utility transmission providers develop 

and use Long-Term Scenarios as part of 

Long-Term Regional Transmission 

Planning. We propose to define LongTerm Scenarios as a tool to identify 

transmission needs driven by changes in 

the resource mix and demand—and 

enable the evaluation of transmission 

facilities to meet such transmission 

needs—across multiple scenarios that 

incorporate different assumptions about 

the future electric power system over a 

sufficiently long-term, forward-looking 

transmission planning horizon. A 

scenario is a hypothetical sequence of 

events that includes assumptions used 

to forecast transmission needs. 

Assumptions used to forecast 

transmission needs driven by changes in 

the resource mix and demand include: 

Forecasts of the level and pattern (i.e., 

hourly and seasonal variability) of 

future electricity demand; the quantity, 

location, and type of resource additions 

and retirements; and other relevant 

forecasts about the electric power 

system that are used as inputs to the 

transmission model and determine the 

need for new transmission facilities over 

the transmission planning horizon. 

Other relevant assumptions might 

include forecasts for natural gas prices, 

increasing outage trends due to extreme 

weather and climatic trends, and other 

future events. We also propose to 

require that public utility transmission 

providers use Long-Term Scenarios to 

evaluate potential regional transmission 

facilities needed to meet transmission 

needs driven by changes in the resource 

mix and demand to identify the more 

efficient or cost-effective regional 

transmission facilities. 

85. In the next section of this NOPR, 

we propose specific requirements that 

public utility transmission providers 

would need to meet in developing LongTerm Scenarios. We propose to require 

each public utility transmission 

provider to amend the regional 

transmission planning process in its 

OATT to explicitly describe the open 

and transparent process that it will use 

to develop Long-Term Scenarios that 

meet these requirements. 

86. We preliminarily find that 

requiring public utility transmission 

providers to develop and utilize 

multiple Long-Term Scenarios, as 

further specified below, as part of LongTerm Regional Transmission Planning 

will allow public utility transmission 

providers to identify and plan to more 

efficiently or cost-effectively meet 

transmission needs driven by changes in 

the resource mix and demand. 

Specifically, we believe that using LongTerm Scenarios in the regional 

transmission planning process will help 

public utility transmission providers to 

account for the inherent uncertainty 

involved in identifying transmission 

needs driven by changes in the resource 

mix and demand and evaluating more 

efficient or cost-effective transmission 

facilities needed to meet those needs. 

87. As discussed above, Long-Term 

Regional Transmission Planning is 

critical to ensuring more efficient or 

cost-effective transmission development 

to meet transmission needs driven by 

changes in the resource mix and 

demand.152 However, such transmission 

planning necessarily relies on forecasts 

of future system conditions, such as the 

state of the resource mix and the level 

of demand. These conditions may be 

reasonably predictable in the near term, 

but as the transmission planning 

horizon extends further into the future, 

they become increasingly imprecise. By 

utilizing multiple Long-Term Scenarios, 

public utility transmission providers 

will have a better understanding of 

potential future transmission needs 

under multiple reasonably likely 

scenarios, allowing them to assess the 

implications of changing market 

conditions and policies. They can also 

manage uncertainties about future 

system conditions and better identify 

more efficient or cost-effective regional 

transmission facilities by evaluating 

which transmission facilities are 

beneficial under multiple scenarios. 

Doing so will mitigate the risks of 

under-building or over-building 

transmission facilities that are identified 

through Long-Term Regional 

Transmission Planning. 

88. We preliminarily find that the 

development of Long-Term Scenarios as 

part of the regional transmission 

planning process will ensure that public 

utility transmission providers 

adequately assess the potential benefits 

of regional transmission facilities that 

may meet the needs of a transmission 

planning region more efficiently or costeffectively than transmission planning 

without Long-Term Scenarios. We 

preliminarily find that a regional 

transmission planning process that does 

not develop Long-Term Scenarios that 

meet the requirements described below 

fails to properly identify transmission 

needs driven by changes in the resource 

mix and demand, which may lead to 

piecemeal and inefficient development 

of new transmission facilities. In 

addition, we preliminarily find that 

failing to develop Long-Term Scenarios 

means that transmission facilities 

needed to meet transmission needs 

driven by changes in the resource mix 

and demand are more likely to be 

identified in the generator 

interconnection process instead of the 

regional transmission planning process, 

similarly leading to the increased 

potential for piecemeal and inefficient 

transmission development, as described 

above.153 For these reasons, we 

preliminarily find that requiring public 

utility transmission providers to 

develop Long-Term Scenarios that meet 

the requirements described below will 

ensure that Commission-jurisdictional 

rates are just and reasonable and not 

unduly discriminatory or preferential. 

89. We clarify that we do not propose 

to require that public utility 

transmission providers use Long-Term 

Scenarios in their regional transmission 

planning processes to address near-term 

reliability and economic transmission 

needs. In other words, we do not 

propose to require that public utility 

transmission providers modify their 

existing regional transmission planning 

processes that plan for reliability and 

economic transmission needs to 

incorporate Long-Term Scenarios. 

90. We seek comment on the 

requirements proposed in this section of 

the NOPR. In particular, we seek 

comment on whether public utility 

transmission providers should be 

required to incorporate some form of 

scenario analysis into their existing 

reliability and economic regional 

transmission planning processes to 

identify more efficient or cost-effective 

transmission facilities than are 

identified through those processes 

today. 

(1) Long-Term Scenarios Requirements 

91. We propose to require that public 

utility transmission providers comply 

with specified minimum requirements 

in developing Long-Term Scenarios, 


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154CAISO Comments at 44–46. 

155NYISO Comments at 10, 36–37. The Outlook 

is a report by which NYISO summarizes the current 

assessments, evaluations, and plans in its biennial 

Comprehensive System Planning Process; produces 

a 20-year projection of congestion on the New York 

State Transmission System; identifies, ranks, and 

groups congested elements; and assesses the 

potential benefits of addressing the identified 

congestion. See id. at 10. 

156SPP Comments at 3; SPP, OATT, attach. O, 

§ IV.2 (4.0.0), § IV.2.a. 

157MISO Comments at 36. 

158PJM Comments at 41. 

159E.g., Southeastern Regional Transmission 

Planning, 2021 Regional Transmission Planning 

Analyses, at 2 (Nov. 17, 2021), https://www.south

easternrtp.com/docs/general/2021/2021-SERTPRegional-Transmission-Planning-AnalysesSummary-Final.pdf; WestConnect Regional 

Transmission Planning, 2020–21 Planning Cycle 

Final Regional Study Plan, at 7 (Mar. 18, 2020), 

https://doc.westconnect.com/Documents.aspx?

NID=18668&dl=1; NorthernGrid, Regional 

Transmission Plan for the 2020–2021 NorthernGrid 

Planning Cycle, at 5 (Dec. 8, 2021), https://

www.northerngrid.net/private-media/documents/ 

2020-2021_Regional_Transmission_Plan.pdf. 

160See NERC, Glossary of Terms Used in NERC 

Reliability Standards (June 28, 2021), https://

www.nerc.com/files/glossary_of_terms.pdf (defining 

Long-Term Transmission Planning Horizon as the 

‘‘[t]ransmission planning period that covers years 

six through ten or beyond when required to 

accommodate any known longer lead time projects 

that may take longer than ten years to complete’’). 

161 ISO–NE Comments at 13–17. 

which we preliminarily find will help to 

ensure Long-Term Regional 

Transmission Planning results in 

Commission-jurisdictional rates that are 

just and reasonable and not unduly 

discriminatory or preferential. We 

expect these proposed minimum 

requirements will allow public utility 

transmission providers to better identify 

transmission needs driven by changes in 

the resource mix and demand and 

evaluate regional transmission facilities 

to more efficiently or cost-effectively 

meet those needs. Specifically, as 

discussed further below, we propose to 

require that public utility transmission 

providers: (1) Use a transmission 

planning horizon no less than 20 years 

into the future in developing Long-Term 

Scenarios and reassess and revise those 

scenarios at least once every three years; 

(2) incorporate a set of Commissionidentified categories of factors that may 

affect transmission needs driven by 

changes in the resource mix and 

demand into their Long-Term Scenarios; 

(3) develop a plausible and diverse set 

of at least four Long-Term Scenarios; (4) 

use ‘‘best available data’’ (as defined in 

the Specificity of Data Inputs section 

below) in developing their Long-Term 

Scenarios; and (5) consider whether to 

identify geographic zones with the 

potential for development of large 

amounts of new generation. 

(i) Transmission Planning Horizon and 

Frequency 

92. The transmission planning 

horizon is the number of years into the 

future that public utility transmission 

providers look when developing LongTerm Scenarios. For example, a 

transmission planning horizon of 20 

years means that the public utility 

transmission provider develops LongTerm Scenarios to identify and plan to 

meet transmission needs that will 

materialize up to 20 years in the future. 

We believe that, to be just and 

reasonable, the transmission planning 

horizon used in Long-Term Regional 

Transmission Planning should extend 

far enough into the future that public 

utility transmission providers can 

identify transmission needs that could 

be met with more efficient or costeffective regional transmission facilities, 

i.e., the transmission planning horizon 

should capture the longer-term benefits 

of addressing transmission needs driven 

by changes in the resource mix and 

demand. 

93. In addition, we believe that the 

Long-Term Scenarios used in LongTerm Regional Transmission Planning 

should not remain static over time. 

Instead, they should be periodically reevaluated and re-developed to ensure 

that they reflect recent forecasts of 

future system conditions. Frequency is 

how often public utility transmission 

providers reassess whether the data 

inputs and factors included in their 

previously developed Long-Term 

Scenarios need to be updated and then 

revise their Long-Term Scenarios as 

needed to reflect updated data inputs 

and factors. Reassessing and revising 

scenarios is appropriate as technology, 

markets, and factors that affect the 

future resource mix and demand 

change. Frequent scenario reassessment 

and revision could help address some of 

the uncertainty and risks associated 

with under-building or over-building 

transmission facilities over a long-term 

transmission planning horizon. 

However, developing scenarios can be 

costly and time-consuming for both 

public utility transmission providers 

and their stakeholders. Frequent 

scenario reassessment and revision 

might also be unnecessary if the data 

inputs and factors into scenario 

development do not change much over 

the time period between studies. Thus, 

we believe that there may be a need to 

balance the benefits of updating LongTerm Scenarios with the burdens 

associated with such updates when 

deciding how frequently to do so. In 

order to prevent overlap of Long-Term 

Scenarios that are developed every three 

years, we also propose to require that 

the development of Long-Term 

Scenarios be completed within three 

years—i.e., before the next three-year 

assessment commences. 

94. Based on our review of public 

information and ANOPR comments, our 

understanding is that some transmission 

planning regions currently use longerterm transmission planning horizons for 

regional transmission planning. For 

instance, CAISO selects transmission 

facilities in its regional transmission 

plan for purposes of cost allocation 

based on a 10-year transmission 

planning horizon and recently initiated 

an effort to conduct informational highlevel technical studies with a 20-year 

horizon as part of its regional 

transmission planning process.154

NYISO uses a 20-year transmission 

planning horizon to evaluate scenarios 

in its regional transmission planning 

process for transmission needs driven 

by Public Policy Requirements and for 

its Outlook.155 However, NYISO uses a 

10-year or shorter transmission planning 

horizon for its regional transmission 

planning process for reliability and 

economic needs. SPP conducts its 

Integrated Transmission Planning 

Assessment with a 10-year transmission 

planning horizon and conducts an 

informational 20-year assessment using 

scenarios every five years.156 MISO’s 

current Long Range Transmission 

Planning effort uses a 20-year 

transmission planning horizon.157 PJM 

uses a 15-year transmission planning 

horizon for its long-term analysis as part 

of its regional transmission planning 

processes.158 All other transmission 

planning regions currently use a 10-year 

transmission planning horizon for their 

regional transmission planning 

processes,159 consistent with NERC’s 

definition of the Long-Term 

Transmission Planning Horizon.160

ISO–NE has stated that it plans to use 

a longer transmission planning horizon 

in future transmission planning 

studies.161 We understand that 

transmission planning regions that 

currently use scenarios with longer-term 

transmission planning horizons (longer 

than 10 years) typically do so only for 

informational purposes or in a limited 

application and not commonly to select 

transmission facilities in regional 

transmission plans for purposes of cost 

allocation. 

(01) Comments 

95. Comments in response to the 

ANOPR support a range of possible 

transmission planning horizons, from 

five years to beyond 30 years. Some 

commenters claim that a transmission 

planning horizon of 10 years is 

sufficient because that is typically 


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162E.g., Exelon Comments at 16–17; NRECA 

Comments at 19–20. Similarly, ITC supports a 5 to 

10-year transmission planning horizon. ITC 

Comments at 12–13. 

163For example, BP supports a 15-year 

transmission planning horizon. BP Comments at 4. 

Public Systems supports a 15- to 20-year 

transmission planning horizon. Public Systems 

Comments at 18–22. NextEra, AEP, Northwest and 

Intermountain, and the Oregon Commission 

support a 20-year transmission planning horizon. 

NextEra Comments at 70; Northwest and 

Intermountain Comments at 4, 16; Oregon 

Commission Comments at 8–9. NYISO supports the 

Commission granting discretion, up to 20 years. 

NYISO Comments at 34–37. ACPA and ESA, AEE, 

U.S. DOE, Competitive Energy, District of 

Columbia’s Office of the People’s Counsel, 

Massachusetts Attorney General, and VEIR support 

a transmission planning horizon longer than 20 

years. ACPA and ESA Comments at 43–45; AEE 

Comments at 32; U.S. DOE Comments at 12–15, 27– 

28; Competitive Energy Comments at 37–40; District 

of Columbia’s Office of the People’s Counsel 

Comments at 22–25; Massachusetts Attorney 

General Comments at 5–15; VEIR Comments at 13– 

17. 

164November 2021 Technical Conference 

Transcript (Tr.) at 129–137. 

165 Id. at 129–137. 

166For example, NextEra supports every two 

years, ITC supports every three to five years, Exelon 

and Competitive Energy support every five to seven 

years, AEP supports at least every three years, and 

the SPP Market Monitor supports a 10-year study 

every year. NextEra Comments at 79; ITC Comments 

at 12; Exelon Comments at 17; Competitive Energy 

Comments at 37–40; SPP Market Monitor 

Comments at 3–4. 

167AEP Comments at 10–11. 

168November 2021 Technical Conference Tr. at 

138–140. 

169The time needed to plan, obtain siting and 

permitting approval for, and construct regional 

transmission facilities takes an average of 10 years. 

See, e.g., MISO, 2021 MISO Transmission 

Expansion Planning, at 12 (2021) (‘‘Transmission 

facilities take an average of 10 years to go from 

planning to in-service.’’). Larger-scale and 

greenfield transmission facilities may take longer to 

go from planning to in-service. 

170As indicated above in this NOPR, NERC 

defines the long-term transmission planning 

horizon as covering year six through year 10 and 

beyond. 

171For example, the annual capacity of new 

interconnection requests grew 42% from 2017 to 

2020, and 123% since 2015. See Lawrence Berkeley 

National Lab, Generation, Storage, and Hybrid 

Capacity in Interconnection Queues Interactive 

Visualization (May 2021), https://emp.lbl.gov/ 

generation-storage-and-hybrid-capacity. 

enough time to identify, design, and 

build needed transmission facilities or 

because it is consistent with NERC 

standards and some state integrated 

resource plans.162 Other commenters 

claim that a longer transmission 

planning horizon, most frequently 20 

years, is needed to appropriately 

identify and plan for future 

transmission needs.163 Commenters that 

support a longer transmission planning 

horizon commonly also support shorterterm interim assessments. Panelists at 

the November 2021 Technical 

Conference that supported a specific 

transmission planning horizon 

contended that a 20-year transmission 

planning horizon is appropriate because 

that transmission planning horizon may 

be needed for siting, permitting, and 

construction of transmission facilities or 

because states have longer-term policy 

goals.164 Some panelists stated that such 

a transmission planning horizon should 

be used in informational studies and 

that a shorter transmission planning 

horizon (e.g., 10 years) should be used 

to select transmission facilities, while 

other panelists stated that public utility 

transmission providers should use a 20- 

year or greater transmission planning 

horizon to select transmission 

facilities.165

96. Commenters discussing frequency 

generally support the Commission 

requiring that scenarios be reassessed 

and revised between every two to five 

years, and up to seven years, to balance 

the benefits and costs of revisiting the 

scenarios.166 AEP recommends that the 

Commission require all public utility 

transmission providers to reassess 

scenarios at the same time to promote 

consistent results and comparability 

among regions.167 Panelists at the 

November 2021 Technical Conference, 

including PJM, MISO, and AEP, 

supported a frequency of at least every 

three years.168

(02) Proposed Requirement 

97. We propose to require that public 

utility transmission providers develop 

Long-Term Scenarios as part of LongTerm Regional Transmission Planning 

using no less than a 20-year 

transmission planning horizon. In 

addition, we propose to require that 

public utility transmission providers 

develop Long-Term Scenarios at least 

every three years, by reassessing 

whether the data inputs and factors 

incorporated in their previously 

developed Long-Term Scenarios need to 

be updated and then revising their 

Long-Term Scenarios as needed to 

reflect updated data inputs and factors. 

We also propose to require that the 

development of Long-Term Scenarios be 

completed within three years, before the 

next three-year assessment commences. 

98. We preliminarily find that a 20- 

year transmission planning horizon 

requirement strikes a reasonable balance 

between the current near-term 

transmission planning horizons used in 

many transmission planning regions 

and the 30-year or longer transmission 

planning horizon proposed by some 

commenters. The 30-year or longer 

transmission planning horizon is 

criticized by other commenters as 

speculative or too uncertain. We also 

believe that a 20-year transmission 

planning horizon requirement may be 

reasonable because some public utility 

transmission providers use a 20-year 

transmission planning horizon in 

existing regional transmission planning 

processes. In addition, we believe that a 

20-year planning horizon would allow 

for sufficient time to identify, plan, and 

obtain siting and permitting approval 

and to construct regional transmission 

facilities to meet long-term regional 

transmission needs including those that 

may take longer than the average 

amount of time to go from planning to 

in-service.169 Finally, we believe that a 

20-year transmission planning horizon 

would allow public utility transmission 

providers to better leverage economies 

of scale by sizing transmission facilities 

to meet not only nearer-term needs but 

also longer-term transmission needs 

driven by changes in the resource mix 

and demand over time. By assessing 

transmission needs over a longer time 

horizon—for example, starting in year 

six 170 through year 20 of the 

transmission planning horizon—LongTerm Regional Transmission Planning 

should be able to identify more efficient 

or cost-effective regional transmission 

facilities to address these needs. 

99. We preliminarily find that a threeyear frequency requirement balances the 

need of public utility transmission 

providers to reassess changes in the 

resource mix and demand as 

technology, markets, and policies have 

the potential to rapidly change,171 with 

the burden of developing Long-Term 

Scenarios that can take a year or longer. 

We believe that this three-year 

frequency requirement will allow public 

utility transmission providers to 

identify new transmission needs driven 

by changes in the resource mix and 

demand during the interim years of the 

transmission planning period, and 

update previously identified 

transmission needs, if warranted. 

100. We seek comment on whether 

using a 20-year transmission planning 

horizon for Long-Term Scenarios is 

appropriate to allow public utility 

transmission providers to identify 

transmission needs driven by changes in 

the resource mix and demand and to 

evaluate regional transmission facilities 

to more efficiently or cost-effectively 

meet such transmission needs. We also 

seek comment on whether a frequency 

of no less than three years for 

reassessing and revising, as necessary, 

the data inputs and factors incorporated 

in previously developed Long-Term 

Scenarios appropriately balances the 

benefits and burdens of such updates. In 

addition, we seek comment on whether 

a three-year frequency requirement for 


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172MISO Comments at 41–43. 

173ANOPR, 176 FERC ¶ 61,024 at P 46. 

174E.g., EEI Comments at 13–14; ACPA and ESA 

Comments at 28–29; Competitive Energy Comments 

at 38; City of New York Comments at 7–9; Union 

of Concerned Scientists Comments at 41–44; 

Minnesota Commission Comments at 4; National 

Grid Comments at 4–9; New Jersey Commission 

Comments at 13–15; NRECA Comments at 17–19; 

Indicated PJM TOs Comments at 25–26; SDG&E 

Comments at 3–4; VEIR Comments at 13–14; WIRES 

Comments at 8; SEIA Comments at 5. 

175E.g., ACPA and ESA Comments at 43–45; 

Amazon Comments at 3; Competitive Energy 

Comments at 38; City of New York Comments at 7– 

9; Minnesota Commission Comments at 4; PIOs 

Comments at 80; RMI Comments at 2–3; SDG&E 

Comments at 3–4; VEIR Comments at 13–14. 

176E.g., ACPA and ESA Comments at 43–45; 

Ameren Comments at 5–8; Competitive Energy 

Comments at 38; Union of Concerned Scientists 

Comments at 41–44; EEI Comments at 13–14; 

NARUC Comments at 10; Northern Virginia 

Cooperative Comments at 7–8; NRECA Comments 

at 17–19; NYISO Comments at 27–31; Rail 

Electrification Comments at 12–13; SEIA Comments 

at 5. 

177E.g., EEI Comments at 13–14; NARUC 

Comments at 10; PG&E Comments at 6; U.S. DOE 

Comments at 12–15; SEIA Comments at 5. 

178E.g., ACPA and ESA Comments at 43–45; 

Entergy Comments at 14–15; NRECA Comments at 

11, 17–19; Union of Concerned Scientists 

Comments at 41–44; Minnesota Commission 

Comments at 4; OMS Comments at 5–6; Rail 

Electrification Comments at 12–13. 

179E.g., AEP Comments at 7–11; AES Ohio 

Comments at 2–4; Oregon Commission Comments 

at 9–10; District of Columbia’s Office of the People’s 

Counsel Comments at 22–25; East Kentucky 

Comments at 8; Exelon Comments at 12, 15–16; LS 

Power Oct. 12 Comments at 41–46; Massachusetts 

Attorney General Comments at 13–21; PIOs 

Comments at 80; PJM Comments at 25–26; REBA 

Comments at 19–26, 33. 

180E.g., Ameren Comments at 5–8; EEI Comments 

at 13–14; PIOs Comments at 80–81; PJM Comments 

at 25–26; Rail Electrification Comments at 12–13; 

REBA Comments at 19–26, 33; SEIA Comments at 

5; Massachusetts Attorney General Comments at 5– 

15; U.S. DOE Comments at 12–18; see also 

November Joint Task Force Tr. 112:1–10 (Andrew 

French) (asserting that anything that indicates there 

is demand should be considered within the 

transmission planning process). 

181 Duke Comments at 5–7; PJM Comments at 9; 

ISO–NE Comments at 20–21; MISO Comments at 

41. 

182City of New York Comments at 6–7. 

183Exelon Comments at 12, 15–16. 

184ACPA and ESA Comments at 46. 

185Southern Comments at 3–5; Berkshire 

Comments at 12–13. 

186 Industrial Customers Comments at 20–33. 

reassessing and revising, as necessary, 

the data inputs and factors incorporated 

in previously developed Long-Term 

Scenarios allows for public utility 

transmission providers to update their 

assumptions in time to assess 

transmission needs driven by changes in 

the resource mix and demand, and 

whether this requirement helps to 

balance the risks of under-building or 

over-building regional transmission 

facilities. Finally, we also seek comment 

on the proposal to require that the 

development of Long-Term Scenarios be 

completed within three years, and 

whether this proposed requirement 

prevents the overlap of the three-year 

assessments. 

(ii) Factors 

101. Factors shaping the electric 

power system are used as inputs to 

develop scenarios for regional 

transmission planning. Factors 

represent long-term drivers and trends 

that inform the expected composition of 

the future resource mix and demand 

that may not be captured by the inputs 

of a basic model of the transmission 

system. Factors inform changes in the 

data inputs of models of the 

transmission system but are not direct 

data inputs of such models. For 

example, a state energy law driving 

procurement of generation is a factor, 

and technology changes driving a longterm trend towards certain resource 

types is also a factor, whereas the 

estimated impact that these factors will 

have on the future resource mix and 

demand is a data input of a model of the 

transmission system. Incorporating the 

appropriate set of factors to forecast the 

future resource mix and demand when 

developing Long-Term Scenarios is 

essential to ensuring that Long-Term 

Regional Transmission Planning can 

identify more efficient or cost-effective 

regional transmission facilities to meet 

transmission needs driven by changes in 

the resource mix and demand. 

Importantly, incorporating more 

accurate inputs into Long-Term 

Scenarios enables a better 

understanding of transmission needs 

driven by changes in the resource mix 

and demand, which in turn allows 

public utility transmission providers to 

better evaluate the benefits of regional 

transmission facilities that would meet 

those needs. Currently, public utility 

transmission providers consider 

different sets of factors in the 

development of scenarios as part of their 

regional transmission planning 

processes, to the extent that they 

develop scenarios. For example, MISO’s 

Futures study includes federal and state 

climate and clean energy laws and 

regulations, federal and state climate 

and clean energy goals that have not 

been enacted into law, utility energy 

and climate goals, assumptions on the 

potential to electrify various types of 

technologies/loads, data and forecasts 

developed by various national labs or 

U.S. agencies, and assumptions on 

resource retirements.172

102. The ANOPR sought comment on 

what factors shaping the resource 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 enacted or promulgated into 

law or regulation; (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.173

(01) Comments 

103. Commenters in response to the 

ANOPR generally support the factors 

that the Commission listed in the 

ANOPR as shaping the resource mix. 

Such commenters highlight the 

importance of: Public policies; 174

decarbonization commitments; 175

resource retirements; 176 the scale, 

location, and adoption rate of 

distributed energy resources (including 

batteries); 177 state-approved utility 

integrated resource plans; 178 weather 

trends; climate risk; and reliability or 

resilience against extreme weather 179 as 

factors shaping future transmission 

needs that public utility transmission 

providers should model in developing 

scenarios. Additionally, some 

commenters argue that scenarios should 

explicitly account for additional load 

from electrification of transportation 

and buildings and include an estimation 

of clean energy demand preferences 

from transmission customers in the 

region.180 Some commenters request 

that the Commission allow for regional 

flexibility and not be overly prescriptive 

on factors for scenario planning.181 City 

of New York proposes that New York 

State’s statutory goals should be part of 

the baseline scenario, rather than an 

informational scenario or treated as a 

mere consideration.182 Exelon states 

that a state policy ‘‘not enshrined into 

law’’ by the legislature should be one of 

the possible futures that should be 

considered, even if somewhat 

‘‘discounted’’ for being aspirational.183

ACPA and ESA recommend that the 

‘‘business-as-usual’’ base case include 

existing future resource plans of the 

utilities in the planning area and any 

local, state, or federal policy 

requirements,184 and Berkshire states 

that many of the factors listed in the 

ANOPR are already under consideration 

in states where integrated resource 

plans are required.185 Industrial 

Customers states that transmission 

investment should not be based on 

speculative factors.186 Similarly, 

Potomac Economics expresses concern 

with mandating long-term planning 

studies involving speculation on a 


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187Potomac Economics Comments at 4. 

188PJM Market Monitor Comments at 2–3; see 

also November Joint Task Force Tr. at 69:18–22 

(Jason Stanek) (discussing the need to account for 

the fact that there will be some uncertainty if 

planning on a longer term horizon). 

189For example, consistent with the Governor’s 

executive order, the New Jersey Board of Public 

Utilities has developed a solicitation schedule to 

procure 7,500 MW of offshore wind resources by 

2035. See New Jersey Commission Comments at 1. 

New York State Department of Environmental 

Conservation has promulgated emissions 

regulations that will cause many of the peaking 

generating facilities in New York City to retire. See 

City of New York Comments at 8. By ‘‘state or 

federal laws or regulations,’’ we mean enacted 

statutes (i.e., passed by the legislature and signed 

by the executive) and regulations promulgated by 

a relevant jurisdiction, whether within a state, 

municipality, or at the federal level. 

190For example, five of the six New England 

states are statutorily required to reduce economywide greenhouse gas emissions by at least 80% 

below 1990 levels by 2050. NESCOE Comments at 

8. New York law requires all new passenger cars 

and trucks in the state to be zero-emissions vehicles 

by 2035. City of New York Comments at 8. 

191For example, North Carolina’s verticallyintegrated investor-owned electric utilities 

participate in a biennial integrated resource plan 

process, in which they develop and file with the 

North Carolina Commission a forecast of load, 

supply-side resources, and demand-side resources 

over a 15-year period. North Carolina Commission 

Reply Comments at 17. 

192For example, MISO’s latest Futures Report 

included assumptions on the potential to electrify 

various types of technologies/loads and data on 

technology costs from the National Renewable 

Energy Laboratory (NREL) Annual Technology 

Baseline dataset, the EIA, and DOE. MISO 

Comments at 43 (citing MISO, MISO Futures 

Report, at 30–38 (Dec. 2021)). 

193For example, CAISO evaluates potential 

generation capacity retirements when developing 

the unified planning assumptions and study plan 

during phase one of its regional transmission 

planning process. CAISO Comments at 18. 

194For example, in 2019, approximately 4.75 of 

5 GW of generator interconnection requests that had 

been a part of the MISO West 2017 study group 

withdrew from the generator interconnection 

queue. ACORE Comments, Ex. 2 at 17. 

195For example, two-thirds of Fortune 100 

companies and roughly half of Fortune 500 

companies have set renewable energy or related 

sustainability targets. ACPA and ESA Comments at 

28. By ‘‘goal,’’ we mean any commitment or 

statement expressed in writing that is not a law or 

regulation. 

variety of factors.187 The PJM Market 

Monitor acknowledges the uncertainty 

associated with transmission planning 

and accuracy of inputs and expresses 

concern with planning for anticipated 

new generation.188

(02) Proposed Requirement 

104. We propose to require that public 

utility transmission providers 

incorporate specific categories of factors 

in the development of Long-Term 

Scenarios as part of Long-Term Regional 

Transmission Planning. Specifically, we 

propose to require that public utility 

transmission providers incorporate, at a 

minimum, the following categories of 

factors into the development of LongTerm Scenarios: (1) Federal, state, and 

local laws and regulations that affect the 

future resource mix and demand; 189 (2) 

federal, state, and local laws and 

regulations on decarbonization and 

electrification; 190 (3) state-approved 

utility integrated resource plans and 

expected supply obligations for load 

serving entities; 191 (4) trends in 

technology and fuel costs within and 

outside of the electricity supply 

industry, including shifts toward 

electrification of buildings and 

transportation; 192 (5) resource 

retirements; 193 (6) generator 

interconnection requests and 

withdrawals; 194 and (7) utility and 

corporate commitments and federal, 

state, and local goals that affect the 

future resource mix and demand.195

105. We preliminarily find that 

incorporating, at a minimum, these 

categories of factors in the development 

of Long-Term Scenarios is appropriate 

because these categories of factors affect 

the future resource mix and demand, 

and their incorporation in Long-Term 

Scenarios is therefore essential to 

identifying transmission needs driven 

by changes in the resource mix and 

demand through Long-Term Regional 

Transmission Planning. Directly below, 

we discuss our proposed requirements 

governing how public utility 

transmission providers must incorporate 

each category of factors into Long-Term 

Scenarios. We note that we are 

proposing to require that public utility 

transmission providers incorporate, at a 

minimum, these categories of factors 

into the development of Long-Term 

Scenarios. To the extent public utility 

transmission providers would like to 

incorporate additional categories of 

factors into the development of LongTerm Scenarios, we propose to require 

that they demonstrate that the 

incorporation of more than the 

minimum is consistent with or superior 

to any final rule in this proceeding. 

106. First, we propose to require that 

each Long-Term Scenario that public 

utility transmission providers use in 

Long-Term Regional Transmission 

Planning incorporate and be consistent 

with federal, state, and local laws and 

regulations that affect the future 

resource mix and demand; federal, state, 

and local laws and regulations on 

decarbonization and electrification; and 

state-approved integrated resource plans 

and expected supply obligations for 

load serving entities. We preliminarily 

find that it is reasonable to require 

public utility transmission providers to 

assume legally binding obligations and 

state utility regulator-approved plans 

are followed and expected supply 

obligations for load serving entities are 

fully met. Public utility transmission 

providers may not discount the factors 

included in the categories of federal, 

state, and local laws and regulations 

that affect the future resource mix; 

federal, state, and local laws and 

regulations on decarbonization and 

electrification; and state-approved 

integrated resource plans and expected 

supply obligations for load serving 

entities. 

107. Second, we propose to require 

that each Long-Term Scenario that 

public utility transmission providers 

use in Long-Term Regional 

Transmission Planning include trends 

in technology and fuel costs within and 

outside of the electricity supply 

industry, including shifts toward 

electrification of buildings and 

transportation; resource retirements; 

and generator interconnection requests 

and withdrawals. For these particular 

categories of factors, we propose to grant 

public utility transmission factors 

flexibility in how they incorporate each 

factor into Long-Term Scenarios so long 

as public utility transmission providers 

identify and publish specific factors for 

each of these categories as further 

described below. As discussed in the 

Coordination of Regional Transmission 

Planning and Generator Interconnection 

Processes section below, we propose to 

require that public utility transmission 

providers consider in their Long-Term 

Regional Transmission Planning 

regional transmission facilities that 

address interconnection-related 

transmission needs that the public 

utility transmission provider has 

identified multiple times in the 

generator interconnection process but 

that have never been constructed due to 

the withdrawal of the underlying 

interconnection request(s). We propose 

to require that public utility 

transmission providers must incorporate 

the specific interconnection-related 

needs identified through that reform, in 

addition to one or more factors that 

more generally characterize generator 

interconnection withdrawals, as a factor 

in the generator interconnection 

requests and withdrawals category of 

factors in their development of LongTerm Scenarios. 

108. Finally, we propose to require 

that each Long-Term Scenario 

incorporate utility and corporate goals 

and federal, state, and local goals that 

affect the future resource mix. However, 

we acknowledge that these categories of 

factors are less binding and more likely 

to change over time, and therefore their 

impact on the future resource mix and 

demand are less certain. For this reason, 

we preliminarily find that it may be 


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196See NARUC Comments at 5–6 (‘‘NARUC . . . 

supports exploring reforms that will better align 

regional transmission planning with state needs and 

ensure meaningful opportunities for the state to 

provide direction and inputs or otherwise have 

their law and policies appropriately reflected 

through the transmission planning process—all 

while benefitting electricity consumers.’’). 

197Order No. 1000, 136 FERC ¶ 61,051 at PP 206– 

207; Order No. 1000–A, 139 FERC ¶ 61,132 at P 335. 

198MISO Comments at 8, 80. 

199MISO, MISO Futures Report, at 4 (Dec. 2021). 

200CAISO Comments at 45. 

201SPP, 2020 Integrated Transmission Planning 

Assessment Report, at 8 (Oct. 2020); SPP Market 

Monitor Comments at 3–4; SPP, 2022 20-Year 

Assessment Scope, at 2–4 (Feb. 2, 2021). 

202NYISO Comments at 28–29. 

203ANOPR, 176 FERC ¶ 61,024 at P 48. 

appropriate for public utility 

transmission providers to discount such 

goals to account for this uncertainty. In 

other words, public utility transmission 

providers would not be required to 

assume that utility and corporate goals 

and federal, state, and local goals that 

affect the future resource mix will be 

fully met. 

109. We propose to require that public 

utility transmission providers identify 

and publish on an Open Access SameTime Information System (OASIS) or 

other public website a list of the factors 

that fall into each of the required 

categories of factors that they will 

incorporate in their development of 

Long-Term Scenarios. That is, public 

utility transmission providers would be 

responsible for identifying all the factors 

they know of and are considering 

incorporating in the development of 

Long-Term Scenarios as part of LongTerm Regional Transmission Planning. 

We also propose to require that public 

utility transmission providers revise the 

regional transmission planning 

processes in their OATTs to outline an 

open and transparent process that 

provides stakeholders, including 

states,196 with a meaningful opportunity 

to propose potential factors that public 

utility transmission providers must 

incorporate in their development of 

Long-Term Scenarios, such as specific 

laws, regulations, goals, and 

commitments, and to provide input on 

how to appropriately discount factors 

that are less certain. 

110. We note that, under Order No. 

1000, public utility transmission 

providers must already have procedures 

in their OATTs that give stakeholders a 

meaningful opportunity to submit 

proposed transmission needs driven by 

Public Policy Requirements and that 

allow public utility transmission 

providers to identify, out of the larger 

set of potential transmission needs 

driven by Public Policy Requirements 

that stakeholders propose, those needs 

for which transmission facilities will be 

evaluated.197 Therefore, public utility 

transmission providers may be able to 

modify and expand these existing 

procedures for identifying transmission 

needs driven by Public Policy 

Requirements to meet these proposed 

requirements regarding the 

identification of factors for 

incorporation into Long-Term 

Scenarios. 

111. We propose this reform because 

we believe that incorporation of the 

categories of factors set forth above in 

developing Long-Term Scenarios would 

help facilitate the identification of 

transmission needs driven by changes in 

the resource mix and demand, which 

we preliminarily find is necessary to 

ensure just and reasonable and not 

unduly discriminatory or preferential 

Commission-jurisdictional rates. Absent 

a requirement to incorporate these 

categories of factors into the 

development of Long-Term Scenarios, 

public utility transmission providers 

may not incorporate known inputs that 

will likely affect the future resource mix 

and demand. Additionally, public 

utility transmission providers may not 

adequately identify transmission needs 

driven by changes in the resource mix 

and demand and evaluate the potential 

benefits of regional transmission 

facilities that may more efficiently or 

cost-effectively meet such needs. As an 

additional benefit, this requirement 

would provide clarity to public utility 

transmission providers and stakeholders 

on what factors must be considered in 

scenario development. 

112. We seek comment on whether 

and how the categories of factors listed 

above adequately capture factors 

expected to drive changes in the 

resource mix and demand. 

(iii) Number and Range of Long-Term 

Scenarios 

113. In Long-Term Regional 

Transmission Planning, the number and 

range of Long-Term Scenarios 

developed determines the scope of 

possible future conditions for the 

electric power system and allows public 

utility transmission providers to 

identify the transmission needs for each 

possible future reflected in the 

scenarios. Developing a range of 

scenarios with different assumptions 

allows public utility transmission 

providers to consider a variety of 

potential scenarios and associated 

transmission needs driven by changes in 

the resource mix and demand and, in 

turn, possibly different regional 

transmission facilities to more 

efficiently or cost-effectively meet those 

needs. However, modeling multiple 

scenarios requires additional time and 

effort, and may add to the costs of LongTerm Regional Transmission Planning. 

We are cognizant of these tradeoffs in 

developing our proposed reforms. 

114. In developing scenarios, it is 

possible to create a base case scenario 

that is a business-as-usual scenario, or a 

most likely scenario, and compare that 

to alternative scenarios that are 

considered to be less likely to occur. 

These alternative scenarios typically 

depart from the base case by considering 

different assumptions. For example, an 

alternative scenario might differ from a 

base case in how it considers the 

location and quantity of resource 

additions or retirements. In addition, it 

is possible to develop specific scenarios 

to determine potential transmission 

needs. For example, it is possible to 

develop a scenario that assumes a 

greater amount of distributed energy 

resource additions compared to a 

business-as-usual case, a scenario that 

assesses conditions associated with 

extreme weather events, or a scenario 

that explores the possibility of 

additional resource development in an 

identified geographic zone, as well as a 

scenario that combines these 

assumptions. 

115. Currently, MISO developed three 

scenarios, called futures, that it intends 

to use as part of its Long-Range 

Transmission Planning.198 MISO makes 

a different assumption about load 

growth, the extent to which state and 

utility goals that are not legislated are 

met, and the future resource mix for 

each future.199 CAISO creates a base 

case scenario reflecting the assumptions 

about resource locations that are most 

likely to occur and one or more stress 

scenarios to compare to the base case 

scenario.200 SPP currently develops a 

base reliability scenario and two 

scenarios as part of its 10-year 

Integrated Transmission Planning 

assessment and four scenarios as part of 

its 20-year Integrated Transmission 

Planning assessment.201 NYISO 

currently develops multiple scenarios 

(high/low load, high/low natural gas 

price, 70% zero-emissions by 2030) for 

its regional transmission planning 

process.202

116. The ANOPR sought comment on 

whether consideration should be given 

to multiple future scenarios and 

whether and how public utility 

transmission providers should account 

for an array of different future scenarios 

when identifying more efficient or costeffective transmission facilities in 

regional transmission plans.203

117. The ANOPR also sought 

comment on how the regional 


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204 Id. 

205Stochastic models are frameworks for 

addressing optimization problems that involve 

uncertainty. 

206ANOPR, 176 FERC ¶ 61,024 at P 49. 

207U.S. DOE Comments at 12–15. 

208ACPA and ESA Comments at 46. 

209Oregon Commission Comments at 8–9. 

210Eversource Comments at 9. 

211Nebraska Commission Comments at 3–4. 

212ACPA and ESA Comments at 46. 

213AEP Comments at 11–12. 

214NextEra Comments at 71–71, 75–77. 

215Nature Conservancy Comments at 3. 

216Avangrid Comments at 12–14. 

217LS Power Oct. 12 Comments at 33–36. 

218E.g., California Commission Comments at 71; 

NARUC Comments at 11 (stating that probabilistic 

approaches can provide ‘‘more insight into the 

benefits and risks of different decisions; and the 

importance and relationship between various 

uncertainties’’); MISO Comments at 36 (stating that 

‘‘probabilistic planning has many benefits and 

should be explored’’); PG&E Comments at 3 (stating 

that probabilistic planning ‘‘appropriately reflect[s] 

the variable nature of the resource mix and other 

uncertainties in the forecast’’). 

219AES Ohio Comments at 2–3; PIOs Comments 

at 79; California Commission Comments at 66; VEIR 

Comments at 15–16. 

220PG&E Comments at 3. 

221U.S. DOE Comments at 20. 

222EEI Comments at 25; NARUC Comments at 10 

(‘‘[P]robabilistic analysis should be used, where 

feasible without significantly burdening the 

planning process.’’); WIRES Comments at 8–9; 

National Grid Comments at 71; see also Joint Fed.- 

State Task Force on Elec. Transmission, Technical 

Conference, Docket No. AD21–15–000, Tr. 71:12– 

72:5 (Clifford Rechtschaffen) (Feb. 16, 2022) 

(February Joint Task Force Tr.) (supporting 

increasing use of probabilistic and other analytical 

approaches where feasible to account for 

uncertainty in quantification of benefits and 

effectively plan for the longer term). 

223PJM Comments at 64–66; MISO Comments at 

46–47; CAISO Comments at 48. 

224Minnesota Commission Comments at 4. 

transmission planning process should 

consider the probabilities of 

scenarios.204 The Commission also 

asked ‘‘whether greater use of 

probabilistic transmission planning 

approaches may better assess the 

benefits of regional transmission 

facilities’’ and whether ‘‘more advanced 

approaches, such as stochastic 205

techniques, may provide an opportunity 

to consider a broader array of potential 

future conditions.’’ 206

(01) Comments 

118. Some commenters responding to 

the ANOPR discuss the number and 

range of scenarios that should be used 

in regional transmission planning. U.S. 

DOE recommends a national standard 

set of scenarios, including business-asusual, high/medium/low load growth, 

high/medium/low reliance on 

distributed energy resources and 

demand response, and high 

decarbonization.207 ACPA and ESA 

recommend a business-as-usual base 

case and alternative scenarios with 

adjusted assumptions on increased 

commitments to decarbonization, 

increased electrification of 

transportation and other uses such as 

home heating, and increased fuel 

prices.208 Oregon Commission 

recommends that the Commission 

require study of a scenario in which 

there is a federal-level climate/clean 

energy policy.209 Eversource states that 

regions should have flexibility in 

defining scenarios, and that states 

should have a major role in defining 

scenarios.210 Nebraska Commission 

generally opposes the Commission 

specifying scenario requirements.211

119. In terms of the number of 

scenarios, ACPA and ESA argue that the 

Commission should require public 

utility transmission providers to use 

three to four scenarios, including a 

business-as-usual case.212 AEP 

recommends at least three robust and 

standardized scenarios.213 NextEra also 

recommends that the Commission 

require public utility transmission 

providers to consider at least three 

scenarios ranging from a business-asusual case to a transformative scenario 

featuring economy-wide national net 

zero emissions.214 And Nature 

Conservancy contends that the 

Commission should require at least 

four.215 Avangrid proposes the number 

of scenarios should be sufficient to 

support reasoned decision-making but 

not so exhaustive to complicate and 

slow down planning.216 LS Power 

asserts that there is a need for a plan 

that uses a broad range of plausible 

scenarios.217

120. In terms of probabilistic planning 

methods in developing scenarios, 

commenters to the ANOPR identify the 

benefits of probabilistic planning, which 

can include the ability to recognize 

multiple facility outages at a single time, 

to prepare for and recover from extreme 

weather events, and to address 

uncertainties about operational 

outcomes (like variable generation) and 

over a long time horizon.218 In light of 

these benefits, some commenters 

recommend that the Commission 

require public utility transmission 

providers to adopt probabilistic 

planning methods.219 PG&E states that 

the planning toolkit must now evolve to 

include more probabilistic tools that 

appropriately reflect the variable nature 

of the resource mix and other 

uncertainties in the forecast.220 U.S. 

DOE states that probabilistic planning, 

along with other factors, is likely to 

contribute to the development of a 

transmission system that reliably meets 

system needs at just and reasonable 

rates.221 Other commenters support the 

use of probabilistic planning methods 

where feasible or appropriate and do not 

recommend the Commission require 

public utility transmission providers to 

adopt probabilistic planning methods at 

this time.222 PJM, CAISO, and MISO 

identify the value of probabilistic 

planning methods yet acknowledge that 

complex issues remain involving data 

availability, computational intensity, 

and stakeholder consensus.223

Minnesota Commission states that 

probabilistic approaches are likely to be 

problematic in the stakeholder process 

because of the uncertainty and wideranging stakeholder opinions about the 

future.224

(02) Proposed Requirement 

121. We propose to require that public 

utility transmission providers develop 

at least four distinct Long-Term 

Scenarios as part of Long-Term Regional 

Transmission Planning. We propose to 

require that each of these Long-Term 

Scenarios incorporate, at a minimum, 

the categories of factors listed in the 

requirement above. As discussed in the 

Factors section above, we propose that 

each Long-Term Scenario must be 

consistent with federal, state, and local 

laws and regulations that affect the 

future resource mix; federal, state, and 

local laws and regulations on 

decarbonization and electrification; and 

state-approved integrated resource 

plans. However, each Long-Term 

Scenario may vary according to 

assumptions about the remaining 

categories of factors described above, as 

well as with respect to other 

characteristics of the future electric 

power system. We do not propose to 

require the development of a specific 

Long-Term Scenario or specific set of 

Long-Term Scenarios, nor do we 

propose to require that public utility 

transmission providers identify the 

relative likelihood of different LongTerm Scenarios except where a public 

utility transmission provider develops a 

base case scenario, as described more 

fully below. 

122. We preliminarily find that using 

at least four distinct Long-Term 

Scenarios is a reasonable lower bound 

for the number of Long-Term Scenarios 

that public utility transmission 

providers must evaluate in Long-Term 

Regional Transmission Planning. This 

minimum number of Long-Term 

Scenarios will help ensure that public 

utility transmission providers conduct 

Long-Term Regional Transmission 

Planning that identifies more efficient or 

cost-effective regional transmission 

facilities to meet transmission needs 


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225We note that different assumptions about the 

factors and data inputs used to develop Long-Term 

Scenarios and other characteristics of the future 

electric power system determine whether the set of 

Long-Term Scenarios are plausible and diverse. 

226The transparency transmission planning 

principle requires public utility transmission 

providers to reduce to writing and make available 

the basic methodology, criteria, and processes used 

to develop transmission plans. Public utility 

transmission providers must make sufficient 

information available to enable customers and other 

stakeholders to replicate the results of transmission 

planning studies. Order No. 890, 118 FERC ¶ 61,119 

at P 471. Order No. 1000 applied this and other 

Order No. 890 transmission planning principles to 

regional transmission planning processes. Order 

No. 1000, 136 FERC ¶ 61,051 at P 151. 

227The coordination transmission planning 

principle requires public utility transmission 

providers to provide customers and other 

stakeholders with the opportunity to participate 

fully in the transmission planning process. The 

transmission planning process must provide for the 

timely and meaningful input and participation of 

customers and other stakeholders regarding the 

development of transmission plans, allowing 

customers and other stakeholders to participate in 

the early stages of development. Order No. 890, 118 

FERC ¶ 61,119 at PP 451–454. 

228For the purpose of an improved record, we 

clarify that we consider probabilistic transmission 

planning approaches to include any transmission 

planning approach that uses a probability 

distribution to assign probabilities to one or more 

inputs to the transmission model. These inputs can 

include shorter-term operational inputs (like wind 

generation or generation outages). See, e.g., Li, W., 

Probabilistic Planning of Transmission Systems: 

Why, How and an Actual Example, at 1, 2008 IEEE 

Power and Energy Society General Meeting— 

Conversion and Delivery of Electrical Energy in the 

21st Century (2008). Stochastic techniques include 

adaptive transmission planning techniques that 

identify transmission facilities that optimize 

transmission net-benefits over a time horizon under 

market and regulatory uncertainty about the future. 

See, e.g., Ho, J., et al., Planning transmission for 

uncertainty: Applications and lessons for the 

western interconnection, at 21, The Western 

Electricity Coordinating Council (2016) (answering 

‘‘What is stochastic transmission planning?’’). 

229See, e.g., SPP, 2020 Integrated Transmission 

Planning Assessment Report, at 146–154 (Oct. 

2020), https://www.spp.org/documents/63434/ 

2020%20integrated%20transmission

%20plan%20report%20v1.0.pdf; NYISO, 2020 

Reliability Needs Assessment, at 89–92 (Nov. 2020), 

https://www.nyiso.com/documents/20142/2248793/ 

2020-RNAReport-Nov2020.pdf. A sensitivity 

represents a single assumption about a short-term 

input or factor (some input with a value that may 

change throughout a day or year). A scenario 

represents an assumption about a longer-term input 

or factor (e.g., resource retirements and additions or 

public policies). See, e.g., Brattle-Grid Strategies 

Oct. 2021 Report at 64. 

driven by changes in the resource mix 

and demand. For example, public utility 

transmission providers could develop a 

base case and three alternatives or a 

low-, medium-, and high-level 

assumption for the factors that public 

utility transmission providers (and their 

stakeholders) believe to be important to 

conduct Long-Term Regional 

Transmission Planning to more 

efficiently or cost-effectively meet 

transmission needs driven by changes in 

the resource mix and demand, along 

with a scenario that accounts for a highimpact, low-frequency event (as 

discussed below). 

123. Furthermore, we propose to 

require that public utility transmission 

providers in each transmission planning 

region develop a plausible and diverse 

set of Long-Term Scenarios.225 That is to 

say, the set of at least four Long-Term 

Scenarios must be: (1) Plausible, that is 

they must reasonably capture probable 

future outcomes, and (2) diverse in the 

sense that public utility transmission 

providers can distinguish distinct 

transmission facilities or distinct 

benefits of similar transmission facilities 

in each scenario. If a public utility 

transmission provider produces a base 

case scenario, that scenario should be 

consistent with what the public utility 

transmission provider determines to be 

the most likely scenario to occur. 

Consistent with the Order No. 890 

transparency transmission planning 

principle,226 we propose to require that 

public utility transmission providers in 

each transmission planning region 

publicly disclose (subject to any 

applicable confidentiality protections) 

information and data inputs they use to 

create each Long-Term Scenario. This 

transparency requirement will allow 

stakeholders to understand how each 

scenario differs. Similarly, consistent 

with the Order Nos. 890 and 1000 

coordination transmission planning 

principle,227 we propose to require that 

public utility transmission providers in 

each transmission planning region give 

stakeholders the opportunity to provide 

timely and meaningful input into the 

identification of which Long-Term 

Scenarios are developed. We propose to 

require that public utility transmission 

providers revise the regional 

transmission planning processes in their 

OATTs to outline an open and 

transparent process that provides 

stakeholders, including states, with a 

meaningful opportunity to propose 

which future outcomes are probable and 

can be captured through assumptions 

made in the development of Long-Term 

Scenarios. We further propose to require 

that public utility transmission 

providers explain on compliance how 

their process will identify a plausible 

and diverse set of Long-Term Scenarios. 

124. We propose to require that at 

least one of the four distinct Long-Term 

Scenarios that public utility 

transmission providers in each 

transmission planning region use in 

Long-Term Regional Transmission 

Planning must account for uncertain 

operational outcomes that determine the 

benefits of or need for transmission 

facilities during high-impact, lowfrequency events. We propose to allow 

public utility transmission providers to 

determine which high-impact, lowfrequency event should be modeled in 

this Long-Term Scenario as part of 

Long-Term Regional Transmission 

Planning based on our understanding 

that each transmission planning region 

may see a need to evaluate a different 

type of high-impact, low-frequency 

event. High-impact, low-frequency 

events may include extreme weather 

events or events associated with 

potential cyber attacks. This Long-Term 

Scenario accounting for a high-impact, 

low-frequency event can be developed, 

for example, by assuming greater-thanexpected electricity demand and 

greater-than-expected generation or 

transmission outages. We propose that 

the use of probabilistic transmission 

planning or stochastic techniques would 

satisfy this requirement, but do not 

propose to require either approach at 

this time.228

125. We note that public utility 

transmission providers can develop 

sensitivities for every Long-Term 

Scenario to assess how outcomes 

modeled in Long-Term Scenarios may 

depend on an assumption about electric 

power system model inputs that does 

not vary across scenarios (e.g., higher 

natural gas prices).229 Such sensitivities 

can provide valuable information about 

the need for and benefits of potential 

transmission facilities; however, they 

can be burdensome to develop if 

applied to every scenario. 

126. We seek comment on whether 

four Long-Term Scenarios will provide 

public utility transmission providers 

with enough information to identify 

transmission needs driven by changes in 

the resource mix and demand and 

evaluate transmission facilities for 

potential selection in the regional 

transmission plan for purposes of cost 

allocation that may more efficiently or 

cost-effectively meet those needs or 

whether additional Long-Term 

Scenarios should be required. In 

addition, we seek comment on whether 

public utility transmission providers 

should be required to develop 

sensitivities for each Long-Term 

Scenario to identify more efficient or 

cost-effective transmission facilities for 

selection in the regional transmission 

plan for purposes of cost allocation as 

part of Long-Term Regional 

Transmission Planning. 

(iv) Specificity of Data Inputs 

127. Data inputs are numbers that 

characterize assumptions about future 

conditions of the transmission system 

under each scenario over the 


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230ANOPR, 176 FERC ¶ 61,024 at P 48. 

231 Id. P 50. 

232As examples, CAISO and PJM mention 

generation retirements, MISO mentions forced 

outage rates, and CAISO, NYISO, and SPP mention 

load and capacity forecasts. CAISO Comments at 

18; MISO Comments at 47; NYISO Comments at 6; 

PJM Comments at 42; SPP Comments at 3. 

233PJM Comments, attach. K at 4. 

234ACEG Comments, attach. C at 10; AEE Reply 

Comments at 4; PIOs Reply Comments at 43–44. 

235Rail Electrification Comments at 13. 

236Union of Concerned Scientists Comments at 

31. 

237U.S. DOE Comments at 12–13. 

238 Id. at attach. B. 

239NARUC Comments at 42. 

240RMI Comments at 3. 

241NERC Comments at 10. 

242Entergy Comments at 17. 

243Certain TDUs Comment at 11. 

244PJM Market Monitor Comments at 6. 

245Timely data inputs are based on the most 

current information. 

246See supra note 226. 

247See, e.g., U.S. DOE Comments, attach. B at 79, 

94 (discussing NREL’s Renewable Energy Potential 

model and Distributed Generation Market Demand 

model). We note that such granular data may be 

useful to public utility transmission providers to 

the extent public utility transmission providers do 

not already have such granular data that meet this 

requirement. 

transmission planning horizon. Using 

reasonable data inputs is key to effective 

Long-Term Regional Transmission 

Planning because data inputs can drive 

the results of transmission planning 

models, both in terms of the 

transmission needs identified and the 

more efficient or cost-effective 

transmission facilities to address those 

needs. For example, the long-term load 

forecast can lead to more planned 

transmission if the assumed growth rate 

is increased. Similarly, the assumed 

dates of generation retirements can be a 

critical factor in determining when new 

transmission will be needed. Given how 

sensitive transmission planning models 

can be to changes in assumptions, using 

robust data inputs is critical to 

identifying more efficient or costeffective regional transmission facilities. 

128. In the ANOPR, the Commission 

asked what inputs should be considered 

in modeling anticipated future 

generation.230 More specifically, the 

Commission asked which data inputs 

public utility transmission providers 

would need to model to represent new 

generation sources, such as renewable 

resources, in order to reflect their actual 

performance.231

(01) Comments 

129. In response to the ANOPR, 

several public utility transmission 

providers commented on the data inputs 

used in their existing regional 

transmission planning processes.232 PJM 

recommends that the Commission 

require disclosure of data inputs and 

their assumptions.233 ACEG, AEE, and 

PIOs advocate for a new rule that 

specifies that public utility transmission 

providers use best available data inputs 

and best practices for load forecasts.234

Rail Electrification recommends that the 

Commission insist on best available data 

and most plausible futures.235 Union of 

Concerned Scientists states that the 

failure to use the best available data will 

lead to the failure to identify more 

efficient and cost-effective transmission 

alternatives.236 U.S. DOE recommends 

the Commission consider the need to 

standardize modeling inputs to increase 

consistency and comparability across 

planning processes and lists the 

potential inputs it thinks the 

Commission should consider.237 U.S. 

DOE also provides information on the 

array of tools and data developed by 

national laboratories which can be used 

as inputs in transmission planning.238

NARUC states that better sharing of data 

between states and the RTOs/ISOs 

would be beneficial.239 RMI states that 

state-of-the-art cost data and forecasts 

are of paramount importance in 

planning for new transmission.240 NERC 

says that improved transmission 

planning for reliability requires better 

data collection especially 

electromagnetic transient data.241

Entergy believes that the transmission 

models used should incorporate 

realistic and objectively reasonable 

future assumptions.242 Certain TDUs 

believes public utility transmission 

providers should regularly update 

planning models with the most recent 

integrated resource plan data 

available.243 The PJM Market Monitor 

asserts that decisions made about the 

transmission grid must reflect accurate 

information while remaining flexible 

enough to incorporate new information 

as it becomes available.244

(02) Proposed Requirement 

130. We propose to require that public 

utility transmission providers use ‘‘best 

available data inputs’’ when developing 

Long-Term Scenarios. By ‘‘best 

available,’’ we do not imply that there 

is a single ‘‘best’’ value for each data 

input that public utility transmission 

providers must use, but rather that best 

practices are used to develop that data 

input. 

131. We propose to define ‘‘best 

available data inputs’’ as data inputs 

that are timely 245 and developed using 

diverse and expert perspectives, 

adopted via a process that satisfies the 

transparency planning principle 

described above,246 and that reflect the 

list of factors that public utility 

transmission providers must incorporate 

into Long-Term Scenarios. An example 

of data inputs that could meet this 

requirement are the long-term load 

forecasts of demand that RTOs/ISOs 

currently use for predicting long-term 

resource adequacy. Another example of 

data inputs that could meet this 

requirement are the most recent data on 

renewable energy potential and 

distributed energy resources developed 

by national labs.247

132. We propose to require that public 

utility transmission providers in each 

transmission planning region update all 

data inputs each time they reassess and 

revise, as necessary, their Long-Term 

Scenarios, which, as explained above, 

we propose to require they do at least 

every three years. As indicated in the 

Long-Term Regional Transmission 

Planning section above, we also propose 

to require that the Order Nos. 890 and 

1000 transmission planning principles 

apply to the process through which 

public utility transmission providers 

determine which data inputs to use in 

their Long-Term Scenarios. For 

example, consistent with the 

coordination transmission planning 

principle in Order Nos. 890 and 1000, 

we propose to require that public utility 

transmission providers in each 

transmission planning region give 

stakeholders the opportunity to provide 

timely and meaningful input concerning 

which data inputs to use in Long-Term 

Scenarios. 

133. We preliminarily find that a 

requirement to use the best available 

data inputs is necessary to ensure that 

public utility transmission providers are 

regularly updating data inputs and then 

using timely and accurate data inputs to 

inform Long-Term Scenarios. As stated 

above, data inputs can drive the results 

of Long-Term Regional Transmission 

Planning, and as a result, directly affect 

which transmission facilities may be 

selected in the regional transmission 

plan for purposes of cost allocation and, 

in turn, Commission-jurisdictional rates. 

134. We seek comment on whether 

the proposed definition of best available 

data inputs will allow for public utility 

transmission providers to identify the 

more efficient or cost-effective 

transmission facilities for selection in 

the regional transmission plan for 

purposes of cost allocation using LongTerm Scenarios. We seek comment on 

whether the proposed definition of best 

available data inputs should be 

expanded to include an evaluation of 

the data source entities’ historical 

accuracy in identifying and projecting 

trends that impact the resource mix and 

demand. We also seek comment as to 


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248 Id. at 12–14 (arguing the Commission should 

standardize modeling input assumptions and 

establish core scenarios); Harvard ELI Comments at 

34 (stating the Commission could work with the 

U.S. DOE to develop industry-wide standards for 

scenario planning which would include data 

inputs). 

249ANOPR, 176 FERC ¶ 61,024 at P 57. 

250 Id. PP 55–56. 

251CAISO Comments at 49–54. 

252NYISO Comments at 31–33. 

253 ISO–NE Comments at 21–25 (citing Cal. Indep. 

Sys. Operator, 118 FERC ¶ 61,226, order on 

clarification, 120 FERC ¶ 61,180 (2007) (granting 

request for waiver to conduct a ‘‘targeted’’ cluster 

study to identify the significant transmission 

infrastructure necessary to interconnect 

approximately 4,500 MW of primarily wind 

resources in the remote Tehachapi Wind Resource 

Area of the system)). 

254PJM Comments at 12–13. 

255 Id. at 41–42. 

256MISO Comments at 53–56. 

257 Id. at 56–58. 

258U.S. DOI Comments at 1–3. 

259U.S. DOE Comments at 24, 74; see also 

November Joint Task Force Tr 108:23–109:8, 

110:13–18 (Gladys Brown-Dutrieuille) (suggesting 

identification of geographic zones as one long-term 

transmission planning principle FERC could work 

with states to develop to ‘‘facilitate integration of 

optimal resources in transmission’’). 

260Consumer Organizations Comments at 21. 

261East Kentucky Comments at 8–9. 

262APPA Comments at 17. 

263OMS Comments at 8–9; NESCOE Comments at 

46–47. 

264WIRES Comments at 41–42. 

265 Xcel Comments at 5–10. 

266Ohio Commission Comments at 6–10. 

whether stakeholders and public utility 

transmission providers would find 

value in or believe it is necessary for the 

Commission to facilitate the 

development of data inputs that meet 

this proposed requirement by 

identifying or standardizing the best 

available data inputs that meet this 

proposed requirement.248

(v) Identification of Geographic Zones 

135. In the ANOPR, the Commission 

sought comment on whether it should 

require public utility transmission 

providers to establish, as part of their 

regional transmission planning 

processes, a process that identifies 

geographic zones that have the potential 

for the development of large amounts of 

new generation, particularly renewable 

resources. The Commission also sought 

comment on whether and how such a 

process might interrelate with existing 

regional transmission planning and cost 

allocation processes, and how long-term 

scenario planning may be used in this 

process or other relevant regional 

transmission planning and cost 

allocation processes.249 The 

Commission also noted that the Texas’ 

CREZ initiative, MISO’s MVPs, and a 

Commission-approved CAISO proposal 

are examples of such identification of 

geographic zones in transmission 

planning and development 

initiatives.250

(01) Comments 

136. Several commenters responded 

to the Commission’s request for 

comments related to the identification 

of geographic zones. Starting with the 

RTOs/ISOs, CAISO states that, while it 

supports the idea of finding zones of 

renewable energy, there are many ways 

to do this, and each region should be 

allowed to find its own solution. CAISO 

states that active involvement and buyin of state regulators in identifying 

zones of renewable energy is critical to 

mitigate the risk of over-building 

transmission and to facilitate state siting 

approvals for transmission facilities. 

CAISO suggests that an open season 

could be used to identify interest in a 

new transmission line.251

137. NYISO supports the 

identification of pockets where future 

generation would be developed and 

where new transmission is needed. 

NYISO states that it already has such an 

identification process.252

138. ISO–NE states that it has a 

process in place to identify regions of 

renewable energy that it calls ISO–NE 

Clustering, which it says is similar to 

the process CAISO used in its 

Tehachapi approach. ISO–NE states that 

long-term planning for transmission to 

renewable-rich areas should not replace 

the generator interconnection 

process.253

139. PJM argues that if the 

Commission creates a geographic zone 

requirement, the RTOs/ISOs should 

have the flexibility to establish a process 

for their region.254 Additionally, PJM 

suggests that sub-zones of renewable 

energy could be visualized in a heat 

map.255

140. MISO opposes prescriptive 

requirements to identify zones of 

renewable energy because it argues that 

the regions should have the flexibility to 

work with stakeholders to identify 

zones. MISO also argues that there are 

potential problems in identifying 

regions of renewable energy because (1) 

what counts as renewable energy is not 

clear, and (2) where the zones of 

renewable energy resources are not 

clear, in part because a state’s desire to 

develop resources may force generation 

development in other states with lower 

resource potential. MISO states that the 

MVP process was a success, in part, due 

to the Regional Generation Outlet Study, 

which was a successful collaboration 

between MISO and the states within the 

MISO region that might not have 

worked as well if MISO and the states 

had not had the flexibility to develop it 

the way that they did.256 MISO states 

that the MISO MVPs, ERCOT’s CREZ, 

and the CAISO examples all reflect local 

solutions based on unique factors in 

each location. MISO points out that 

ERCOT and CAISO are each single-state 

RTOs/ISOs, which makes their 

experience not directly comparable to 

MISO’s.257

141. U.S. DOI supports the creation of 

geographic zones as a means to improve 

the efficiency of transmission planning 

overall but cautions that any 

requirement must consider 

environmental impacts and habitats of 

species that are of conservation 

concern.258 Similarly, U.S. DOE argues 

that while the creation of geographic 

zones is a step in the right direction, 

additional agreement is needed on 

which generation resources would 

actually be developed, which market 

areas need to be served, and which 

transmission facilities are needed to 

connect them reliably and efficiently.259

However, U.S. DOE states that Texas’ 

CREZ model has worked well since it 

establishes clear regulatory pathways 

and cost allocation en masse. 

142. Some commenters oppose a 

geographic zone requirement. Consumer 

Organizations assert that a ‘‘top down’’ 

approach from the Commission has the 

potential to saddle customers with 

unnecessary costs from constructing 

‘‘roads to nowhere’’ that may never be 

utilized.260 East Kentucky argues that a 

Commission-required geographic zone 

requirement would create an uneven 

playing field for generation resources 

that seek to interconnect outside a 

designated geographic zone.261 APPA 

argues that instead of requiring 

geographic zones, the Commission 

should permit load-serving entities to 

identify geographic zones when 

developing their resource plans, which 

is more of a ‘‘bottom up’’ approach.262

OMS and NESCOE both assert that each 

region already has an existing process to 

identify zones of renewable resource 

potential and that the Commission 

should not require anything further.263

WIRES states that a requirement to 

identify zones of renewable energy is 

not needed and regions should have the 

flexibility to find their own solutions.264

Xcel notes that such a requirement 

exceeds the Commission’s authority 

under the FPA because states have the 

final say over construction of new 

generation, as well as transmission 

facility siting and permitting.265

143. Ohio Commission states that the 

Commission lacks jurisdiction to require 

the creation of new zones.266 Michigan 


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267Michigan Commission Comments at 12–14. 268NRECA Comments at 21–23 269LPPC Comments at 14–15. 270SoCal Edison Comments at 10. 271Shell Comments at 8–9. 

272Orsted Comments at 8. 

273Union of Concerned Scientists Comments at 

32–37. 

274We note that, while we refer to multiple 

‘‘zones,’’ subsequent to stakeholder feedback, the 

final list may contain only one designated 

geographic zone. 

Commission cautions that if the 

Commission requires a geographic zone 

concept, the notion that geographic 

zones must be ‘‘rich in renewable 

resources’’ would unreasonably shift 

costs to consumers that do not receive 

commensurate benefits.267 NRECA 

states that the decision to establish 

geographic zones should be left to the 

regional transmission planning 

processes to resolve, subject to input 

from state and local governing bodies 

and to ultimate Commission oversight 

and approval on a case-by-case basis to 

ensure that zone selection and cost 

allocations are consistent with Order 

No. 1000.268

144. LPPC argues that a geographic 

zone requirement should consider 

guardrails that will assist in limiting 

undue risk and financial exposure for 

those customers that may not use the 

planned facilities.269 SoCal Edison 

argues that geographic zones should 

entail providing federal funds to 

disproportionally burdened 

communities.270 Shell argues that 

coastal public utility transmission 

providers should be required to explain 

how their transmission planning 

processes accommodate the unique 

obstacles impeding offshore wind 

transmission and generation.271 Orsted 

states that the scale and location of 

future offshore wind generation is well 

known, and RTOs/ISOs should be 

required to plan cost-effective 

transmission to bring offshore wind 

power to market.272 Union of Concerned 

Scientists argue that if the Commission 

requires geographic zones, it should 

revise Order No. 1000’s provision for 

local and regional transmission 

planning processes to explicitly provide 

for the recognition of Public Policy 

Requirements established by state or 

federal laws or regulations, including 

federal leasing for the development of 

generation, that will drive transmission 

and interconnection in resource-rich 

zones.273

(02) Proposed Requirement 

145. We propose to require each 

public utility transmission provider, as 

part of its regional transmission 

planning process, to consider whether 

to: (1) Identify, with stakeholder input, 

specific geographic zones within the 

transmission planning region that have 

the potential for development of large 

amounts of new generation; (2) assess 

generation developers’ commercial 

interest in developing generation within 

the identified geographic zones; and (3) 

incorporate designated zones, and the 

identified commercial interest in each 

zone, into Long-Term Scenarios. 

146. We preliminarily find that 

requiring the consideration and 

potential identification of geographic 

zones within Long-Term Scenarios 

assists public utility transmission 

providers, transmission developers, and 

generation developers to coordinate 

their activities. We believe that public 

utility transmission providers would be 

able to better identify transmission 

needs driven by changes in the resource 

mix and demand by considering 

geographic zones that have the potential 

for the development of large amounts of 

new generation and where developers 

have already shown commercial 

interest. Using the information gained 

through the process described below to 

identify such geographic zones, public 

utility transmission providers in each 

transmission planning region could then 

plan transmission facilities that would 

serve large concentrations of new 

generation in a more efficient or costeffective manner. 

147. As step one of the geographic 

zone process, we propose to require that 

public utility transmission providers 

consider whether to establish and 

include in the regional transmission 

planning process outlined in their 

OATTs the method that they will use to 

identify geographic zones within the 

transmission planning region. We 

propose to require that this method use 

best available data, including 

atmospheric, meteorological, 

geophysical, and other surveys, to 

identify geographic zones with potential 

for development of large amounts of 

new generation. We also propose to 

require that public utility transmission 

providers in each transmission planning 

region use this information to create a 

set of draft geographic zones, and that 

they post on their OASIS or other public 

websites maps of the draft geographic 

zones, as well the information used to 

create the draft geographic zones, for 

stakeholders’ input. 

148. As part of proposed step one, 

after the public utility transmission 

providers in each transmission planning 

region identify and post any draft 

geographic zones and related 

information, we propose to require them 

to provide all stakeholders, including 

relevant federal and state siting 

authorities, with a meaningful 

opportunity to provide input on the 

draft geographic zones. We believe that 

input from federal and state siting 

authorities is particularly important 

because we also propose to require that 

public utility transmission providers in 

each transmission planning region use 

this stakeholder engagement to identify 

known siting, permitting, or other 

anticipated development challenges or 

opportunities associated with the draft 

geographic zones. We believe that 

obtaining information related to siting 

and permitting early in the geographic 

zone development process will help 

public utility transmission providers to 

identify draft zones where the 

anticipated generation resources are 

most likely to materialize. 

149. In addition, we propose to 

require that public utility transmission 

providers in each transmission planning 

region consider this stakeholder 

feedback and modify the draft 

geographic zones as appropriate to 

produce a final list of designated 

geographic zones within the 

transmission planning region.274 As the 

final part of proposed step one, we 

propose to require that public utility 

transmission providers in each 

transmission planning region post on 

their OASIS or other public websites 

maps of the designated geographic 

zones and information related to the 

designation of those zones, including 

the explanation of changes from the 

draft to final list. 

150. In step two of the geographic 

zone process, we propose to require that 

public utility transmission providers in 

each transmission planning region 

assess generation developers’ 

commercial interest in developing 

generation within each designated 

geographic zone. Specifically, we 

propose to require that public utility 

transmission providers include in their 

OATTs as part of their regional 

transmission planning process a method 

to assess generation developers’ 

commercial interest in developing 

generation within each designated 

geographic zone that considers the 

following: (1) The generation 

developer’s existing energy resources 

within the zone; (2) the number and size 

of any interconnection requests from 

developers with completed facilities 

study agreements for generation located 

within the zone; (3) a generation 

developer’s leasing agreements with 

landowners within the zone; (4) a 

generation developer’s letters of credit 

associated with generation it may 

develop in the zone; (5) any merchant 

or other entity commitments to build 


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275ANOPR, 176 FERC ¶ 61,024 at P 23. 

276ANOPR, 176 FERC ¶ 61,024 at P 23. Id. 

277ANOPR, 176 FERC ¶ 61,024 atId. P 65. 

278ANOPR, 176 FERC ¶ 61,024 atId. P 66. 

279ANOPR, 176 FERC ¶ 61,024 at P 66. Id. 

280CAISO Comments at 71–72. 

281PJM Comments at 17–18. 

282 ISO–NE Comments at 25–26. 

(including deposits or payments to 

secure or fund) transmission facilities 

that would serve generation within the 

zone; (6) a generation developer’s power 

purchase agreements with a creditworthy counterparty associated with 

generation within the zone; and (7) any 

other factors for which generation 

developers have provided evidence as 

indications of commercial interest in 

developing generation within the zone. 

We propose this step two requirement 

because we believe it will indicate how 

much of the geographic zone’s resource 

hosting potential generation developers 

are interested in pursuing, which is 

useful for improving the accuracy of 

Long-Term Scenarios as public utility 

transmission providers in each 

transmission planning region 

incorporate information about 

designated geographic zones into such 

scenarios as part of step three. 

151. In step three of the geographic 

zone process, we propose to require that 

public utility transmission providers in 

each transmission planning region 

incorporate the information from step 

one and step two regarding the 

designated geographic zones into their 

Long-Term Scenarios. We believe this 

information will be useful to public 

utility transmission providers in each 

transmission planning region as they 

identify and run different Long-Term 

Scenarios as part of the requirement to 

conduct Long-Term Regional 

Transmission Planning to address 

transmission needs driven by changes in 

the resource mix and demand. 

Specifically, we propose to require that 

public utility transmission providers 

revise the regional transmission 

planning process in their OATTs to 

describe how the designated geographic 

zones, the information they used to 

designate the geographic zones, and the 

information about generation 

developers’ commercial interest in 

developing generation within each zone 

are integrated into their Long-Term 

Scenarios. We believe that integrating 

this information into Long-Term 

Scenarios will allow public utility 

transmission providers in each 

transmission planning region to better 

identify transmission needs driven by 

changes in the resource mix and 

demand, as well as more efficient or 

cost-effective regional transmission 

facilities to meet those needs. 

152. We acknowledge that public 

utility transmission providers in multistate transmission planning regions may 

face unique challenges and differing 

energy policy interests or preferences in 

complying with this proposed 

requirement. 

153. We seek comment on how public 

utility transmission providers in multistate transmission planning regions may 

reconcile or account for differing energy 

policy interests or preferences in 

implementing this proposed 

requirement, while respecting and not 

overriding those state preferences. 

ii. Coordination of Regional 

Transmission Planning and Generator 

Interconnection Processes 

154. As discussed above, we 

preliminarily find that current regional 

transmission planning processes fail to 

plan for transmission needs driven by 

changes in the resource mix and 

demand. Instead, public utility 

transmission providers typically 

account for such transmission needs 

through interconnection-related 

network upgrades identified through the 

generator interconnection process. 

Based on the comments received in 

response to the ANOPR, we believe that 

there may be a need for better 

coordination between the regional 

transmission planning and cost 

allocation and generator interconnection 

processes. To this end, we propose to 

require that public utility transmission 

providers consider as part of their LongTerm Regional Transmission Planning 

regional transmission facilities that 

address interconnection-related needs 

that the public utility transmission 

provider identified multiple times in the 

generator interconnection process but 

that have never been constructed due to 

the withdrawal of the underlying 

interconnection request(s). 

(a) ANOPR 

155. In the ANOPR, the Commission 

asserted that the interaction between a 

public utility transmission provider’s 

current generator interconnection 

process and its regional transmission 

planning and cost allocation processes 

appears to be limited.275 The 

Commission also observed that the 

primary interaction between a public 

utility transmission provider’s current 

generator interconnection process and 

its regional transmission planning and 

cost allocation processes is that the 

baseline regional transmission planning 

models generally only incorporate 

interconnection projects that are near 

the end of the generator interconnection 

process and have completed an 

interconnection facilities study.276

156. The ANOPR sought comment on 

whether reforms are necessary to 

improve coordination between the 

regional transmission planning and cost 

allocation and generator interconnection 

processes.277 In particular, the ANOPR 

sought comment on whether 

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 

in coordination with the regional 

transmission planning process.278 The 

ANOPR also sought comment on 

whether it may be possible and 

beneficial to combine certain aspects of 

the regional transmission planning and 

generator interconnection processes.279

(b) Comments 

157. Each of the RTOs/ISOs filed 

comments in response to the ANOPR 

related to the coordination of their 

regional transmission planning and cost 

allocation and generator interconnection 

processes. CAISO states that it includes 

interconnection-related network 

upgrades identified during its 

interconnection study process and that 

meet specific voltage and/or capital cost 

thresholds as an input into the regional 

transmission planning process. CAISO 

asserts that it does so to ensure that it 

identifies and approves all major 

transmission additions and upgrades 

under a single comprehensive process 

and allocates the available amount of 

transmission capacity to the proposed 

generating facilities in each area.280 PJM 

states that it leverages opportunities to 

address supplemental projects and new 

interconnection service requests 

through its baseline transmission 

projects. For instance, when increasing 

the capabilities of a regional 

transmission facility would obviate the 

need for an interconnection-related 

network upgrade, PJM factors the 

interconnection customer’s incremental 

need into the transmission project and 

the interconnection customer is only 

responsible for the costs of the 

incremental portion of the transmission 

facility.281 ISO–NE explains how its 

regional transmission planning and 

generator interconnection processes are 

coordinated presently but acknowledges 

that improvements may be necessary to 

optimize transmission solutions.282

NYISO and SPP each identify an 

ongoing or potential stakeholder process 

to improve the coordination of the 

generator interconnection and regional 


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283NYISO Comments at 41; SPP Comments at 9– 

11. 

284MISO Comments at 75–76. 

285See, e.g., AEP Comments at 30–31; APPA 

Comments at 22; Certain TDUs Comments at 18; 

NARUC Comments at 6, 11, 18; NERC Comments 

at 17–18; NewSun Comments at 24; Northwest and 

Intermountain Comments at 33; OMS Comments at 

11–13; Indicated PJM TOs Comments at 27; REBA 

Comments at 2–3; SDG&E Comments at 5. 

286Anbaric Comments at 23; Public System 

Comments at 6–7, 19. 

287 Duke Comments at 8–9. 

288Enel Comments at 3. 

289Enel Comments, Id. attach. 1 (Plugging In) at 

12. Enel proposes that the Transfer Distribution 

Factor is a good metric for determining electrical 

distance from a generation facility and what 

constitutes ‘‘local.’’ See Enel Comments, attach. 1 

(Plugging In) id. at 6. 

290AEE Comments at 52–53. 

291Southern Comments at 38–39; US Chamber of 

Commerce Comments at 4; see also ACORE 

Comments at 26–27; APPA Comments at 22–23; 

Berkshire Comments at 10–11; CAISO Comments at 

70; LPPC Comments at 18; ITC Comments at 31. 

292 Industrial Customers Comments at 25; 

Consumer Organizations Comments at 26. 

293EEI Comments at 37; Exelon Comments at 33– 

34; Policy Integrity Comments at 27–28; Indicated 

PJM TOs Comments at 27. 

294ANOPR, 176 FERC ¶ 61,024 at P 23. 

295Supra sectionl

and Unreasonable and Unduly Discriminatory and 

Preferential Commission-Jurisdictional Rates 

(detailing the sharp rise in total investment in 

interconnection-related network upgrades along 

with the jump in the cost per kW for newly 

interconnecting generators to interconnect). 

296ACEG Jan. 2021 Interconnection Report at 17. 

297 Id. (naming the high cost of interconnectionrelated network upgrades as the fundamental 

problem that interconnection queue reform has 

failed to address thus far). 

transmission planning processes.283

MISO explains how its generator 

interconnection and regional 

transmission planning processes are 

currently related to each other and 

contends that the regional transmission 

planning process is the right avenue to 

determine more holistic transmission 

needs but considers the generator 

interconnection process more 

appropriate to focus on the specific 

needs associated with interconnecting 

new generation.284

158. Several commenters support 

better coordination between the regional 

transmission planning and cost 

allocation and generator interconnection 

processes, including the need for similar 

timelines and assumptions.285 Anbaric 

and Public Systems ask the Commission 

to require a regional transmission 

planning assessment if an 

interconnection study identifies 

significant interconnection-related 

network upgrades beyond the 

interconnection facility line needed to 

reach a substation and any directly 

interconnected substation upgrades to 

‘‘shift the evaluation of development of 

needed upgrades to the [regional 

transmission] planning process.’’ 286

Anbaric and Public Systems state that 

the needed upgrades could be eligible 

for competitive bidding as part of the 

regional transmission planning process. 

Similarly, Duke suggests that public 

utility transmission providers can 

identify an ex ante measure, such as the 

change in the levelized cost of a 

transmission network upgrade, to 

determine whether an interconnectionrelated network upgrade should be 

incorporated into its regional 

transmission plan for purposes of cost 

allocation according to a defined cost 

allocation method.287

159. Enel outlines a detailed proposal 

for consolidating the generator 

interconnection and regional 

transmission planning processes to limit 

generator interconnection studies to 

focus on direct, localized impacts of 

new generation and directly assign costs 

for interconnection-related network 

upgrades to generators when the cost 

causation relationship is ‘‘strong and 

justified.’’ 288 Under Enel’s proposal, 

interconnection requests that meet 

significant readiness criteria required by 

the public utility transmission provider, 

such as a non-refundable cash deposit 

or letter of credit in the amount of 100% 

of the costs of the ‘‘local’’ 

interconnection-related network 

upgrades, would be included in the 

regional transmission planning process 

after the public utility transmission 

provider conducts a basic 

interconnection study (e.g., Energy 

Resource Interconnection Study).289

AEE states that implementing Enel’s 

proposal would help resolve the cost 

allocation and market entry barrier 

problems associated with the current 

funding paradigm for interconnectionrelated network upgrades and could also 

help unburden constrained and 

backlogged interconnection queues that 

are creating barriers to entry.290

160. Other commenters oppose 

further coordination of the generator 

interconnection and regional 

transmission planning processes.291

Some consumer groups express a 

general concern that coordination 

reforms would shift costs of generator 

interconnection to consumers.292

Finally, some commenters expect that a 

regional transmission planning process 

that better accounts for anticipated 

future generation would address 

generator interconnection issues that are 

due to a lack of coordination, or cooptimization, of the two processes.293

(c) Need for Reform 

161. For the reasons set forth below, 

we believe that there may be a need for 

better coordination between regional 

transmission planning and cost 

allocation and generator interconnection 

processes to ensure just and reasonable 

and not unduly discriminatory or 

preferential Commission-jurisdictional 

rates. As the Commission explained in 

the ANOPR, the interaction between 

regional transmission planning and cost 

allocation processes on the one hand 

and the generator interconnection 

process on the other appears limited— 

the baseline regional transmission 

planning models generally only 

incorporate interconnection projects 

that have completed an interconnection 

facilities study, and are therefore near 

the end of the generator interconnection 

process.294 But where transmission 

system needs are repeatedly identified 

through generator interconnection 

processes, we believe that more efficient 

or cost-effective transmission expansion 

could be achieved through regional 

transmission planning and cost 

allocation that allocates costs in a 

manner that is at least roughly 

commensurate with estimated benefits 

and eliminates a potential barrier to 

entry for new generation resources. 

162. We are most concerned with the 

prevalence of interconnection-related 

network upgrades being repeatedly 

identified in the generator 

interconnection process in multiple 

interconnection queue cycles in a short 

period of time (e.g., five years) but not 

being developed because the 

interconnection request(s) driving the 

need for the upgrade are all withdrawn. 

As explained above, there has been a 

dramatic increase in recent years in the 

level of spending on interconnectionrelated network upgrades, driving the 

cost of interconnecting new generation 

to the transmission system higher and 

higher.295 The evidence suggests that 

this trend is leading to more and more 

interconnection customers withdrawing 

their interconnection requests in the 

face of significant costs associated with 

interconnection-related network 

upgrades. According to a January 2021 

report, ‘‘the high cost of interconnection 

is increasing the rate at which 

generators drop out of the 

interconnection queue.’’ 296 For 

example, between January 2016 and July 

2020, 245 generation projects in 

advanced stages in the MISO generator 

interconnection process withdrew from 

the queue, with the project developers 

citing high interconnection-related 

network upgrade costs as the primary 

reason for their withdrawal.297 While 

interconnection customers may choose 

to withdraw from the interconnection 

queue for a number of reasons, in recent 


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298See ACORE Comments at 12. 

299 ICF Sept. 2021 Report at 25–26. 

300See, e.g., CAISO Comments at 52–53 (stating 

that in CAISO ‘‘transmission facilities at 200 kV and 

above are eligible for regional cost allocation,’’ 

including location-constrained resources 

interconnection facilities, because ‘‘this voltage 

threshold . . . recognizes that high voltage 

transmission facilities support and provide benefits 

to all customers to the CAISO grid’’); Order No. 

2003, 104 FERC ¶ 61,103 at P 65 (stating that 

‘‘[f]acilities beyond the Point of Interconnection 

[(i.e., interconnection-related network upgrades)] 

are part of the Transmission Provider’s 

Transmission System and benefit all users’’); 

ACORE Comments, Ex. 5, at 4–7. 

years, the deciding factor has become 

the interconnection customer’s ‘‘sticker 

shock’’ at its cost responsibility for 

interconnection-related network 

upgrades.298

163. When interconnection customers 

withdraw from the interconnection 

queue, the identified interconnectionrelated network upgrades associated 

with those interconnection customers 

remain unbuilt and the underlying 

interconnection-related needs go 

unaddressed. In many cases, when the 

interconnection-related need is not 

addressed via development of 

interconnection-related network 

upgrades in one interconnection queue 

cycle, the same interconnection-related 

need—and oftentimes the same or a 

substantially similarly interconnectionrelated network upgrade—will appear in 

interconnection studies for different 

interconnection requests or clusters in 

subsequent interconnection queue 

cycles. This scenario can occur even if 

subsequent interconnection requests or 

clusters vary considerably from 

previous interconnection requests or 

clusters in terms of size, fuel type, 

technical specifications, or location. 

One study, which analyzed 12 specific 

interconnection-related network 

upgrades identified by MISO and SPP, 

found that SPP identified three of the 

upgrades in two interconnection queue 

cycles and one in three interconnection 

queue cycles, and MISO identified three 

of the upgrades in two interconnection 

queue cycles and two in three 

interconnection queue cycles.299 In 

other words, both SPP and MISO were 

repeatedly identifying the same 

interconnection-related network 

upgrades as interconnection customers 

withdrew from the interconnection 

queue, leaving next-in-line 

interconnection customers to address 

the same interconnection-related needs. 

164. Where interconnection-related 

needs are repeatedly identified in 

interconnection studies, the implication 

may be that the area, despite the 

potentially prohibitive interconnection 

costs, is otherwise desirable for 

generators to locate (e.g., it is located 

close to fuel sources). At the same time, 

the recurrent need for an 

interconnection-related network 

upgrade is unlikely to go away without 

someone investing in the transmission 

system in that location. As 

interconnection customers that have 

invested time and resources in 

proposing a project, entering the 

interconnection queue, and engaging in 

the generator interconnection process 

choose to withdraw rather than fund the 

interconnection-related network 

upgrades, it becomes more and more 

likely that it will never be economic for 

an interconnection customer (or small 

cluster of interconnection customers) to 

resolve the interconnection-related 

need. 

165. At the same time, 

interconnection-related network 

upgrades can provide widespread 

transmission benefits that extend 

beyond the interconnection 

customer.300 As a result, planning these 

transmission upgrades exclusively 

through the generator interconnection 

process may result in a mismatch 

between the beneficiaries of the 

transmission upgrade and those to 

whom the costs are allocated. In other 

words, by upgrading the transmission 

system in a piecemeal fashion through 

the generator interconnection process, 

the current transmission planning 

paradigm appears to impose costs on 

interconnection customers for 

transmission facilities that would 

provide benefits beyond those received 

by the interconnection customer. This 

paradigm can present a potential barrier 

to entry for new generation resources 

that might otherwise be economic if not 

for the cost of interconnection-related 

network upgrades. We believe that 

reforms may be necessary to allow for 

the consideration of transmission 

facilities to meet interconnection-related 

needs repeatedly identified in the 

generator interconnection process 

through Long-Term Regional 

Transmission Planning and Cost 

Allocation process instead, which we 

believe would result in more efficient or 

cost-effective transmission expansion, 

cost allocation for such transmission 

facilities that is at least roughly 

commensurate with estimated benefits, 

and elimination of a barrier to entry for 

new generation resources. In turn, we 

expect that these reforms would ensure 

just and reasonable and not unduly 

discriminatory or preferential 

Commission-jurisdictional rates. 

(d) Proposed Reform 

166. We propose to require that public 

utility transmission providers consider 

in their Long-Term Regional 

Transmission Planning regional 

transmission facilities that address 

certain interconnection-related needs 

that the public utility transmission 

provider has identified multiple times 

in the generator interconnection process 

but that have never been constructed 

due to the withdrawal of the underlying 

interconnection request(s). In particular, 

we propose to require that public utility 

transmission providers evaluate for 

selection in the regional transmission 

plan for purposes of cost allocation 

regional transmission facilities to 

address interconnection-related needs 

that have been identified in the 

generator interconnection process as 

requiring interconnection-related 

network upgrades where: (1) The public 

utility transmission provider has 

identified interconnection-related 

network upgrades in interconnection 

studies to address those 

interconnection-related needs in at least 

two interconnection queue cycles 

during the preceding five years 

(beginning at the time of the withdrawal 

of the first underlying interconnection 

request); (2) the interconnection-related 

network upgrade identified to meet 

those interconnection-related needs has 

a voltage of at least 200 kV and/or an 

estimated cost of at least $30 million; (3) 

those interconnection-related network 

upgrades have not been developed and 

are not currently planned to be 

developed because the interconnection 

request(s) driving the need for the 

upgrade has been withdrawn; and (4) 

the public utility transmission provider 

has not identified an interconnectionrelated network upgrade to address the 

relevant interconnection-related need in 

an executed generator interconnection 

agreement or in a generator 

interconnection agreement that the 

interconnection customer requested that 

the public utility transmission provider 

file unexecuted with the Commission. 

167. We propose to require that public 

utility transmission providers in each 

transmission planning region consider 

regional transmission facilities to 

address interconnection-related needs 

pursuant to this reform through the 

proposed Long-Term Regional 

Transmission Planning. We recognize 

that the Long-Term Regional 

Transmission Planning proposal 

requires that public utility transmission 

providers incorporate interconnection 

queue withdrawals into Long-Term 

Scenario development. Consequently, 

we propose to require that public utility 

transmission providers in each 

transmission planning region 

incorporate the specific 


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301We propose that when an interconnectionrelated network upgrade is identified for the 

interconnection of more than one interconnection 

customer in an interconnection queue cycle, the 

withdrawal of all interconnection customers 

assigned to that interconnection-related network 

upgrade qualifies as one withdrawal. The 

withdrawal of a single interconnection customer 

when other interconnection customers assigned to 

the interconnection-related network upgrade 

remain in the interconnection queue cycle does not 

qualify as a withdrawal of an interconnection queue 

interconnection request for the purposes of this 

reform. 

302Section 24.4.6.5 of CAISO’s Comprehensive 

Transmission Planning Process provides that 

interconnection-related network upgrades 

identified in the generator interconnection process 

that are not already included in a signed LGIA may 

be assessed in the Comprehensive Transmission 

Planning Process if they ‘‘consist of new 

transmission lines 200 kV or above, and have 

capital costs of $100 million or greater; . . . [are] 

a new 500 kV substation that has capital costs of 

$100 million or greater; or, . . . have a capital cost 

interconnection-related needs identified 

through this reform as a factor used to 

develop Long-Term Scenarios. 

168. We preliminarily find that this 

requirement will support the 

establishment of just and reasonable and 

not unduly discriminatory or 

preferential Commission-jurisdictional 

rates by addressing a potential barrier to 

integrating new sources of generation 

that may otherwise continue to exist 

absent such requirements in the regional 

transmission planning process. 

Additionally, to the extent that such 

transmission facilities are selected in 

the regional transmission plan for 

purposes of cost allocation, this 

proposal would provide an avenue to 

allocate these regional transmission 

facilities’ costs more broadly in 

recognition of their more widespread 

benefits (as identified through the 

regional transmission planning process), 

helping to ensure that their costs are 

allocated in a manner that is at least 

roughly commensurate with the 

estimated benefits that they provide. We 

believe that the criteria proposed above 

that the public utility transmission 

provider must use to identify the 

interconnection-related needs that 

should be considered in the regional 

transmission planning process will help 

to ensure that the associated 

interconnection-related network 

upgrades are likely to have produced 

benefits beyond those provided to the 

interconnection customers whose 

interconnection requests the 

interconnection-related network 

upgrades are needed to accommodate. It 

is important to note that we are not 

proposing that all interconnectionrelated needs that satisfy the above 

criteria must result in transmission 

facilities being selected in the regional 

transmission plan for purposes of cost 

allocation; rather, those regional 

transmission facilities would have to 

independently satisfy the criteria for 

such selection in Long-Term Regional 

Transmission Planning as the more 

efficient or cost-effective transmission 

facility. 

169. As noted above, we propose that 

the first qualifying criterion for this 

potential reform is that the public utility 

transmission provider has identified a 

needed interconnection-related network 

upgrade in generator interconnection 

studies to address the same 

interconnection-related need in at least 

two interconnection queue cycles 

during the preceding five years. The 

five-year look-back for each 

interconnection-related need would 

begin on the date that an 

interconnection customer with an 

interconnection study that identifies an 

interconnection-related network 

upgrade that meets the voltage or cost 

estimate threshold withdraws its 

interconnection request.301 We propose 

to choose this starting point because, 

arguably, this is the earliest point at 

which the transmission provider will 

have notice that the costs associated 

with an identified interconnectionrelated network upgrade may have 

caused a withdrawal. We also believe 

that this criterion appropriately limits 

the scope of this requirement to those 

interconnection-related needs that are 

likely to persist, are not unique to a 

single interconnection customer’s 

request, and have the potential, if 

evaluated through the regional 

transmission planning process, to 

provide more widespread benefits to 

transmission customers. 

170. We propose that the initial fiveyear time period begin five calendar 

years prior to the initial effective date of 

the accepted tariff provisions proposed 

to comply with this reform. Thus, upon 

the acceptance of such tariff provisions 

in a Commission or delegated letter 

order, the public utility transmission 

provider would consider 

interconnection-related network 

upgrades identified to address the same 

interconnection-related need in at least 

two interconnection queue cycles in the 

five calendar years prior to the effective 

date established in the order accepting 

those tariff revisions. Thus, if the 

Commission adopts this proposal, the 

public utility transmission provider 

should not look back to a point earlier 

than that date and, going forward, this 

requirement would apply to any repeat 

identification of an interconnectionrelated need identified in at least two 

interconnection queue cycles in the 

immediately preceding five calendar 

years. We believe that such a limitation 

would prevent consideration of regional 

transmission facilities (more 

specifically, interconnection-related 

network upgrades) identified using data 

that may be stale by the time the public 

utility transmission providers in a 

transmission planning region consider 

regional transmission facilities to 

address the identified interconnectionrelated needs in their regional 

transmission planning process. We 

believe that five years is short enough to 

provide public utility transmission 

providers with accurate information on 

interconnection-related needs and also 

long enough for public utility 

transmission providers to identify the 

same interconnection-related need, 

which is likely to persist, in at least two 

interconnection queue cycles. 

171. We do not propose to limit this 

reform to interconnection-related 

network upgrades that are identical to 

those identified in prior interconnection 

queue cycles. Instead, we propose to 

focus on the relevant interconnectionrelated needs that those upgrades are 

intended to address. To this point, we 

propose to require that public utility 

transmission providers in each 

transmission planning region consider 

whether the interconnection-related 

need for which the public utility 

transmission provider identified the 

interconnection-related network 

upgrade is the same in multiple 

interconnection queue cycles. That is, if 

an interconnection-related need is 

driving the identification of an 

interconnection-related network 

upgrade on the transmission system in 

one interconnection queue cycle and an 

interconnection-related network 

upgrade with, for example, a different 

voltage, starting point, or ending point 

is identified in the next interconnection 

queue cycle to address the same 

interconnection-related need, then the 

first criterion would be satisfied. We 

believe that this approach will 

appropriately account for differences in 

technology, study assumptions, system 

topology, and/or interconnection 

requests that may occur over time that 

may result in different interconnectionrelated network upgrades to address the 

same interconnection-related need. 

172. We also propose to limit the 

scope of this reform to those 

interconnection-related network 

upgrades that have a voltage of at least 

200 kV and/or an estimated cost of at 

least $30 million. We note that we have 

previously found a 200 kV voltage 

threshold to be just and reasonable in 

the context of an analogous provision in 

CAISO’s tariff.302 With respect to the 


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of $200 million or more.’’ CAISO, Tariff, 

section§ 24.4.6.5 (LGIP Network Upgrades) (1.0.0). 

303TheAn ACEG Reportreport notes that 3.5 of 5 

GW of renewable energy projects in the MISO West 

2017 study group dropped out because each project 

‘‘faced transmission costs in the range of tens to 

hundreds of millions of dollars.’’ ACEG ReportSee 

Americans for a Clean Energy Grid, Disconnected: 

The Need for New Generator Interconnection 

Policy, at 17. (Jan. 2021). We also note that thean 

ICF Report indicates that the Wichita-Benton 345 

kV line in SPP South, which has appeared in two 

different interconnection queue cycles and has not 

been constructed, has an estimated cost of $32.1 

million. See ICF ReportResources, LLC, Just & 

Reasonable? Transmission Upgrades Charged to 

Interconnection Generators are Delivering SystemWide Benefits, at 5, 26. (Sep. 2021). As a further 

reference point, wind and solar industry advocates 

claim that ‘‘the ‘implied cost threshold’ beyond 

which new generators are often no longer 

financially viable is . . . . . . an average of about 

$100,000 per megawatt of installed capacity.’’ See 

American Wind Energy Association, Clean Grid 

Alliance, and SEIA, Generator Contributions to 

Transmission Expansion, at 2 (AugustAug. 2020), 

https://cleangridalliance.org/_uploads/_media_

uploads/_source/Generator_Contrib_Xmission-V3aFINAL.pdf. 

304Order No. 1000, 136 FERC ¶ 61,051 at P 624. 

305 Id. PP 624–625. 

306 Id. P 622. 

307ANOPR, 176 FERC ¶ 61,024 at P 53. 

$30 million estimated cost threshold, 

evidence suggests that requiring 

interconnection customers to be 

responsible for this level of costs from 

a single interconnection-related network 

upgrade can lead to withdrawal from 

the interconnection queue, signaling 

that this level may be an appropriate 

dividing line for consideration in 

regional transmission planning 

processes.303

173. To avoid shifting costs 

inappropriately from generators in the 

generator interconnection process to 

transmission customers through the 

regional transmission planning process, 

we further propose to limit the scope of 

interconnection-related needs to be 

considered in the regional transmission 

planning process to those 

interconnection-related needs not 

addressed by interconnection-related 

network upgrades memorialized in an 

executed generator interconnection 

agreement (or in a generator 

interconnection agreement that the 

interconnection customer requested to 

be filed unexecuted with the 

Commission). This proposed limitation 

would ensure that public utility 

transmission providers only consider in 

their regional transmission planning 

process interconnection-related network 

upgrades that remain unconstructed 

despite the existence of a demonstrated 

interconnection-related need. We 

reiterate that regional transmission 

facilities identified through this process 

would have to independently satisfy the 

public utility transmission provider’s 

criteria for selection in the regional 

transmission plan for purposes of cost 

allocation as the more efficient or costeffective transmission solution. 

174. We seek comment on the 

requirements proposed in this section of 

the NOPR. In particular, we seek 

comment on whether this proposed 

reform could delay the processing of 

existing interconnection queues and 

what reforms, if any, would be 

necessary to ensure that the generator 

interconnection and regional 

transmission planning processes are not 

significantly delayed by this proposed 

reform. We also seek comment on the 

appropriateness of the criteria that we 

propose a public utility transmission 

provider must use to identify the 

interconnection-related needs that 

should be considered in the regional 

transmission planning process, and 

whether there are alternative criteria 

public utility transmissions providers 

may use to identify significant 

interconnection-related needs that 

warrant consideration in the regional 

transmission planning process. Finally, 

we seek comment on how this proposed 

reform should interact with existing 

regional transmission planning 

processes and the Long-Term Regional 

Transmission Planning proposed herein. 

iii. Evaluation of the Benefits of 

Regional Transmission Facilities 

175. As discussed above, we propose 

to require that public utility 

transmission providers in each 

transmission planning region identify 

transmission needs driven by changes in 

the resource mix and demand using 

Long-Term Scenarios that meet the 

requirements proposed above. As 

explained in this section, once the 

public utility transmission providers in 

a transmission planning region have 

identified the region’s transmission 

needs driven by changes in the resource 

mix and demand, we propose to require 

that, as part of public utility 

transmission providers’ identification 

and evaluation of more efficient or costeffective regional transmission facilities 

that may resolve those transmission 

needs in the regional transmission 

planning process, public utility 

transmission providers must: (1) 

Evaluate the benefits of regional 

transmission facilities to meet identified 

transmission needs driven by changes in 

the resource mix and demand, identify 

which benefits they will use in LongTerm Regional Transmission Planning, 

explain how they will calculate those 

benefits, and explain how the benefits 

will reasonably reflect the benefits of 

regional transmission facilities to meet 

identified transmission needs driven by 

changes in the resource mix and 

demand ; and (2) evaluate the benefits 

of regional transmission facilities over a 

time horizon that covers, at a minimum, 

20 years starting from the estimated inservice date of the transmission 

facilities. Further, we propose to allow 

(but not require) public utility 

transmission providers to evaluate the 

benefits of a portfolio of regional 

transmission facilities instead of doing 

so on a facility-by-facility basis. Finally, 

we identify and describe a broad set of 

benefits that we believe public utility 

transmission providers could consider 

using in Long-Term Regional 

Transmission Planning (Long-Term 

Regional Transmission Benefits) to 

reasonably capture the benefit of 

regional transmission facilities to meet 

identified transmission needs driven by 

changes in the resource mix and 

demand. 

(a) Evaluations of Long-Term Regional 

Transmission Benefits 

176. In Order No. 1000, the 

Commission neither prescribed a 

particular definition of ‘‘benefits’’ or 

‘‘beneficiaries,’’ nor required 

consideration of any specific benefits. 

Instead, the Commission stated that the 

proper context for consideration of such 

matters would be on review of 

compliance proposals.304 The 

Commission stated that allowing greater 

flexibility to accommodate a variety of 

approaches better advanced the goals of 

Order No. 1000.305 The Commission 

also stated that, in determining the 

beneficiaries of transmission facilities, a 

regional transmission planning process 

could consider benefits including, but 

not limited to, the extent to which 

transmission facilities, individually or 

in the aggregate, provide for maintaining 

reliability and sharing reserves, 

production cost savings and congestion 

relief, and/or meeting Public Policy 

Requirements.306 The result is that there 

are no specific requirements for public 

utility transmission providers to 

consider any particular benefit or set of 

benefits in evaluating transmission 

facilities for selection in the regional 

transmission plan for purposes of cost 

allocation as the more efficient or costeffective solution to a regional 

transmission need. 

177. In the ANOPR, the Commission 

sought comment on whether the 

Commission should require public 

utility transmission providers to use a 

minimum set of benefits to identify 

more efficient or cost-effective regional 

transmission facilities, and what those 

benefits should be.307 The Commission 


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308 Id. P 70. 309ACORE Comments at ii; AEE Comments at 31– 

32; ACEG Comments at 6–8; ACPA and ESA 

Comments at 75; AEP Comments at 14; Amazon 

Comments at 4; Anbaric Comments at 29; Avangrid 

Comments at 9; Business Council for Sustainable 

Energy Comments at 2; Citizens Energy Comments 

at 6–7; City of New York Comments at 3–4; Union 

of Concerned Scientists Comments at 66–75; 

Consumers Council Comments at 4, 16; Duke 

Comments at 12; EDF Comments at 8–10; EEI 

Comments at 33; ITC Comments at 28–34; 

Massachusetts Attorney General Comments at 24– 

25; New Jersey Commission at 13–14, 17–19; 

NextEra Comments at 83–88; Northwest and 

Intermountain Comments at 35–38; Orsted 

Comments at 6–7; PIOs Comments at 30, 60; Policy 

Integrity Comments at 43; PSEG Comments at 25– 

27; REBA Comments at 17; RMI Comments at 4; 

SEIA Comments at 9; Shell Comments at 18–20; 

State Agencies Comments at 21–22; State of 

Massachusetts Comments at 16–17; U.S. DOE 

Comments at 7–9, 23–24; WIRES Comments at 18; 

see also Joint Fed.-State Task Force on Elec. 

Transmission, Transcript of Feb. 16, 2022 Meeting, 

Docket No. AD21–15–000, at 19:15–18, 22:9–12 

(Comm’r Rechtschaffen) (supporting expanded list 

of benefits and arguing that a more comprehensive 

benefit-cost analysis would lead to better 

transmission planning). 

310City of New York Comments at 7; PIOs 

Comments at 81–82; EEI Comments at 24–25; PG&E 

Comments at 8–9; Anbaric Comments at 29; Union 

of Concerned Scientists Comments at 38; State of 

Massachusetts Comments at 16–19; Orsted 

Comments at 6–7; RMI Comments at 4. 

311See, e.g., ACEG Comments at 31–32 & app. A; 

ACORE Comments at 31–32 & Ex. 6; ACPA and ESA 

Comments at 24–27; NextEra Comments at 84–86; 

PIOs Comments at 82; PIOs Reply Comments at 55. 

312PIOs Comments at 30; see also Orsted 

Comments at 6. 

313See, e.g., ACEG Comments at 34 & app. A; 

ACORE Comments at 34 & Ex. 6; ACPA and ESA 

Comments at 24–26; EDF Comments at 9; NextEra 

Comments at 84–86; PIOs Comments at 34 & Ex. A; 

RMI Comments at 4; U.S. DOE Comments at 37; 

WIRES Comments at 2; ACEG Reply Comments at 

11; Enel Reply Comments at 3–4; PIOs Reply 

Comments at 55; see also February Joint Task Force 

Tr 49:8–13 (Ted Thomas) (stating that The Brattle 

Group list of benefits is ‘‘characterized by rigor’’). 

314Ameren Comments at 9–11. 

315Consumer Organizations Comments at 18–19; 

District of Columbia’s Office of the People’s 

Counsel Comments at 26–27. 

316Consumer Organizations Comments at 18; 

LPPC Comments at 20–23. 

317 District of Columbia’s Office of the People’s 

Counsel Comments at 3–4. 

318APPA Comments at 15–16. 319MISO Comments at 23–26. 320 Id. at 52–53; see also February Joint Task 

Force Tr 20:5–8, 21:4–12 (Clifford Rechtschaffen) 

(suggesting that the reliability category should be 

expanded to include resilience, particularly in light 

of extreme events in the West and increasingly 

intense hurricanes in the East), 51:10–15 (Matthew 

Nelson) (stating that having commonality in 

terminology for benefits and where they are 

considered would be valuable), 69:16–18 (Jason 

Stanek) (concluding that if there is a fourth category 

of benefits, it may be resilience), 73:1–4 (Riley 

Allen) (arguing for not ignoring difficult to quantify 

benefits but rather for finding sensible ways to 

quantify them). 

321NYISO Comments at 27–31, 34–37; see also 

February Joint Task Force Tr 20:9–12 (Clifford 

Rechtschaffen) (advocating for expanding the 

economic category to include improved 

connectivity to lower-cost generation). 

322PJM Market Monitor Comments at 10. 

sought comment as to whether the 

existing regional transmission planning 

and cost allocation processes fully 

accounted for the full suite of benefits, 

including hard-to-quantify benefits. 

Further, the Commission sought 

comment on the types of benefits 

provided by transmission facilities 

needed to meet the transmission needs 

of the changing resource mix, as well as 

the manner in which those benefits can 

be quantified, if at all. The Commission 

also sought comment on how public 

utility transmission providers can 

document and account for benefits if 

those benefits cannot be quantified, but 

are real.308

(1) Comments 

178. Many commenters support 

consideration of a wider set of benefits 

than those currently used to evaluate 

transmission facilities for potential 

selection in the regional transmission 

plan for purposes of cost allocation.309

Further, many commenters support the 

consideration of all possible benefits of 

regional transmission facilities when 

discussing benefits in the context of the 

current approach to separately consider 

reliability, economic, and public policy 

benefits—however, even some 

commenters that support maintaining 

the Order No. 1000 framework 

acknowledge that the benefits assessed 

could be expanded.310 Commenters that 

support requiring consideration of an 

expanded set of transmission benefits 

argue that existing regional transmission 

planning processes are unjust and 

unreasonable because they ignore the 

full range of transmission benefits and 

therefore fail to select net beneficial 

transmission facilities, leading to 

underinvestment in transmission and 

higher consumer costs in the long 

run.311 PIOs assert that the Commission 

should conduct a survey of all potential 

benefits that can result from multivalue, scenario-based planning and 

should require that public utility 

transmission providers consider those 

benefits for regional transmission 

planning.312 Numerous commenters 

point to a list of transmission benefits 

identified by The Brattle Group as 

providing a useful framework for 

delineating a minimum set of benefits 

that the Commission could require 

public utility transmission providers to 

consider when evaluating alternative 

regional transmission facilities.313

179. Many commenters generally 

request regional flexibility to consider 

benefits. Ameren opposes requiring a 

specific set of benefits, arguing that such 

a reform could lead to controversy and 

delays.314 Consumer Organizations and 

District of Columbia’s Office of the 

People’s Counsel express that, if 

additional benefits are added to the 

equation, additional costs to 

communities and landowners (for 

example, additional farm production 

costs, local road use, and local 

emergency services) should be, too.315

Consumer Organizations and LPPC 

assert that it is not within the 

Commission’s authority to create ‘‘new 

speculative benefits’’ in an effort to 

broaden cost allocation.316 District of 

Columbia’s Office of the People’s 

Counsel urges that greater specificity is 

needed regarding what is a benefit.317

APPA does not support considering 

environmental benefits associated with 

particular types of resources in planning 

transmission facilities and allocating 

costs.318

180. MISO states that it has adopted 

benefit metrics such as avoided/deferred 

reliability projects and reduced MISO– 

SPP settlement costs that go beyond 

adjusted production cost savings. 

However, MISO states that it has not 

been able to adopt other metrics 

explored in the stakeholder process, 

including: (1) Transmission outage and 

transmission energy losses; and (2) 

reduced capacity cost due to reduced 

peak load losses and future capacity 

expansion deferral due to increased 

capacity import and export limits.319

MISO seeks flexibility on benefits that 

are considered to reflect changing 

circumstances but calls for direction or 

guidance from the Commission on 

identification and quantification of 

challenging benefits like resilience.320

181. NYISO supports identifying 

economic benefits when studying 

reliability projects. NYISO states that 

the current economic calculation is 

based on net production cost savings 

and does not consider other economic 

benefits such as installed capacity cost 

savings to load-serving entities.321

182. The PJM Market Monitor claims 

that PJM incorrectly defines the benefits 

of proposed market efficiency 

transmission projects, resulting in 

uneconomic transmission upgrades. In 

particular, the PJM Market Monitor 

argues that PJM uses speculative 

transmission-related benefits over a 15- 

year period while limiting the analysis 

to the existing generation fleet and 

existing patterns of fuel costs and 

congestion, which eliminates the 

possibility that new generation could 

respond to market signals and meet the 

same needs.322 The PJM Market Monitor 

cautions against considering congestion 

reduction or localized locational 

marginal price reductions as an 

economic benefit to a potential 

transmission project without accurately 


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323 Id. at 11. 324See Order No. 1000, 136 FERC ¶ 61,051 at PP 

624–625. 

325See id. P 624. 

accounting for how the congestion 

dollars are or are not returned to load 

through the financial transmission 

rights (or their equivalent).323

(2) Proposed Reform 

183. At this time, consistent with 

Order No. 1000, we decline to propose 

to prescribe any particular definition of 

‘‘benefits’’ or ‘‘beneficiaries,’’ nor 

require use of any specific benefits.324

Instead, we continue to acknowledge 

the benefits of regional flexibility, and 

consistent with Order No. 1000, propose 

to consider such matters on review of 

compliance proposals.325 Nevertheless, 

we acknowledge the support for the 

adoption of a common set of minimum 

benefits, and we propose a list of LongTerm Regional Transmission Benefits 

described below that public utility 

transmission providers may consider in 

Long-Term Regional Transmission 

Planning and cost allocation processes. 

In addition, we propose to require that 

public utility transmission providers 

identify on compliance the benefits they 

will use in Long-Term Regional 

Transmission Planning, how they will 

calculate those benefits, and how the 

benefits will reasonably reflect the 

benefits of regional transmission 

facilities to meet identified transmission 

needs driven by changes in the resource 

mix and demand. As part of this 

compliance obligation, public utility 

transmission providers should explain 

the rationale for using the benefits 

identified. 

184. We believe that the Long-Term 

Regional Transmission Benefits 

discussed below account for many of 

the benefits that regional transmission 

facilities to address transmission needs 

driven by changes in the resource mix 

and demand identified as part of LongTerm Regional Transmission Planning 

are most likely to provide. However, we 

clarify that this list of potential benefits 

is not mandatory or exhaustive and 

public utility transmission providers 

would have flexibility to propose what 

benefits to use as part of their LongTerm Regional Transmission Planning. 

For example, public utility transmission 

providers may wish to use benefits 

previously accepted by the Commission 

for existing regional transmission 

planning processes that are not included 

in the Long-Term Regional 

Transmission Benefits discussed herein. 

185. We believe that the following set 

of Long-Term Regional Transmission 

Benefits may be useful in evaluating 

transmission facilities for selection in 

the regional transmission plan for 

purposes of cost allocation as the more 

efficient or cost-effective solutions to 

meet transmission needs driven by 

changes in the resource mix and 

demand: (1) Avoided or deferred 

reliability transmission projects and 

aging infrastructure replacement; (2) 

either reduced loss of load probability 

or reduced planning reserve margin; (3) 

production cost savings; (4) reduced 

transmission energy losses; (5) reduced 

congestion due to transmission outages; 

(6) mitigation of extreme events and 

system contingencies; (7) mitigation of 

weather and load uncertainty; (8) 

capacity cost benefits from reduced 

peak energy losses; (9) deferred 

generation capacity investments; (10) 

access to lower-cost generation; (11) 

increased competition; and (12) 

increased market liquidity. 

TABLE 1—LONG-TERM REGIONAL TRANSMISSION BENEFITS

Benefit Description 

Avoided or deferred reliability transmission facilities and aging transmission infrastructure replacement.Reduced costs of avoided or delayed transmission investment otherwise required to address reliability needs or replace aging transmission facilities. 

Reduced loss of load probability [OR next benefit] ................................. Reduced frequency of loss of load events by providing additional pathways for connecting generation resources with load (if planning reserve margin is constant), resulting in benefit of reduced expected 

unserved energy by customer value of lost load. 

Reduced planning reserve margin [OR prior benefit] .............................. While holding loss of load probabilities constant, system operators can 

reduce their resource adequacy requirements (i.e., planning reserve 

margins), resulting in a benefit of reduced capital cost of generation 

needed to meet resource adequacy requirements. 

Production cost savings ........................................................................... Reduction in production costs, including savings in fuel and other variable operating costs of power generation, that are realized when 

transmission facilities allow for the increased dispatch of suppliers 

that have lower incremental costs of production, displacing highercost supplies; also reduction in market prices as lower-cost suppliers 

set market clearing prices; when adjusted to account for purchases 

and sales outside the region, called adjusted production cost savings. 

Reduced transmission energy losses ...................................................... Reduced energy losses incurred in transmittal of power from generation to loads, thereby reducing total energy necessary to meet demand. 

Reduced congestion due to transmission outages .................................. Reduced production costs during transmission outages that significantly increase transmission congestion. 

Mitigation of extreme events and system contingencies ......................... Reduced production costs during extreme events, such as unusual 

weather conditions, fuel shortages, and multiple or sustained generation and transmission outages, through more robust transmission 

system reducing high-cost generation and emergency procurements 

necessary to support the system. 

Mitigation of weather and load uncertainty .............................................. Reduced production costs during higher than normal load conditions or 

significant shifts in regional weather patterns. 

Capacity cost benefits from reduced peak energy losses ....................... Reduced energy losses during peak load reduces generation capacity 

investment needed to meet the peak load and transmission losses. 

Deferred generation capacity investments ............................................... Reduced costs of needed generation capacity investments through expanded import capability into resource-constrained areas. 


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326Order No. 1000, 136 FERC ¶ 61,051 at P 81. 

327See, e.g., S.C. Elec. & Gas Co., 143 FERC 

¶ 61,058, at P 232 (2013). 

328Brattle-Grid Strategies Oct. 2021 Report at 37. 

TABLE 1—LONG-TERM REGIONAL TRANSMISSION BENEFITS—Continued 

Benefit Description 

Access to lower-cost generation .............................................................. Reduced total cost of generation due to ability to locate units in a more 

economically efficient location (e.g., low permitting costs, low-cost 

sites on which plants can be built, access to existing infrastructure, 

low labor costs, low fuel costs, access to valuable natural resources, 

locations with high-quality renewable energy resources). 

Increased competition .............................................................................. Reduced bid prices in wholesale electricity markets due to increased 

competition among generators and reduced overall market concentration/market power. 

Increased market liquidity ......................................................................... Reduced transaction costs (e.g., bid-ask spreads) of bilateral transactions, increased price transparency, increased efficiency of risk 

management, improved contracting, and better clarity for long-term 

transmission planning and investment decisions through increased 

number of buyers and sellers able to transact with each other as a 

result of transmission expansion. 

186. Below, we describe each benefit 

along with examples of how each 

benefit may be calculated. We clarify 

that these are just examples, and we are 

not proposing to require that public 

utility transmission providers use any 

specific benefits or calculate those 

benefits in a particular manner when 

conducting Long-Term Regional 

Transmission Planning. At this time, we 

are only proposing to require public 

utility transmission providers to 

identify what benefits they will use in 

Long-Term Regional Transmission 

Planning and explain how they will be 

calculated and how the benefits will 

reasonably reflect the benefits of 

regional transmission facilities to meet 

identified transmission needs driven by 

changes in the resource mix and 

demand. 

187. We seek comment on each of the 

Long-Term Regional Transmission 

Benefits discussed in this section of the 

NOPR. Additionally, we seek comment 

on how to ensure that each type of 

benefit is distinct such that the list of 

benefits does not ‘‘double count’’ 

benefits. We also seek comment on the 

application of the Long-Term Regional 

Transmission Benefits in non-RTO/ISO 

regions. 

188. Finally, we seek comment on 

whether public utility transmission 

providers should be required to use 

some or all of the Long-Term Regional 

Transmission Benefits as a minimum set 

of benefits for their Long-Term Regional 

Transmission Planning process. 

(3) Description of Long-Term Regional 

Transmission Benefits 

189. The benefits of transmission 

facilities identified in Long-Term 

Regional Transmission Planning may 

include a set of benefits related to 

avoided or deferred reliability 

transmission facilities and aging 

transmission infrastructure replacement, 

which we describe as reduced costs on 

avoided or delayed transmission 

investment otherwise required to 

address reliability needs or replace 

aging transmission facilities. The 

Commission has recognized that 

regional transmission planning could 

lead to the development of transmission 

facilities that span the service territories 

of multiple public utility transmission 

providers, which in turn would obviate 

the need for transmission facilities that 

would otherwise be identified in 

multiple local transmission plans.326

190. The Commission has accepted 

accounting for such ‘‘avoided costs’’ as 

part of a method for identifying 

beneficiaries and allocating costs in 

almost all the regional cost allocation 

methods in non-RTO/ISO regions. Using 

this method, public utility transmission 

providers in a transmission planning 

region determine the beneficiaries of a 

regional transmission facility or 

portfolio of facilities by identifying the 

local and regional transmission facilities 

that a new proposed regional 

transmission facility or portfolio of 

facilities would displace. The method 

defines the benefits of the regional 

transmission facility or facilities as the 

costs that public utility transmission 

providers in the transmission planning 

region ‘‘avoid’’ because they no longer 

need to build the displaced local and 

regional transmission facilities. The 

method allocates costs among public 

utility transmission providers whose 

local or regional transmission facilities 

the new proposed regional transmission 

facility or facilities would displace in 

proportion to their share of the total 

benefits (i.e., the total avoided costs). If 

the new proposed regional transmission 

facility or facilities do not displace any 

local or regional transmission facilities 

in existing local or regional 

transmission plans, the avoided cost 

method determines the benefits of the 

applicable facilities by considering the 

costs of local or regional transmission 

facilities that would otherwise be 

needed to meet the same need that the 

new proposed regional transmission 

facility will meet.327

191. In calculating this benefit, public 

utility transmission providers in each 

transmission planning region could first 

identify transmission facilities that 

could defer or replace an identified 

reliability transmission solution. 

Avoided cost benefits could be 

calculated by comparing the cost of 

transmission facilities required to 

address the reliability need without the 

proposed regional transmission facility 

to the cost of transmission facilities 

needed to address the reliability need 

assuming the regional transmission 

solution were in place.328

192. Similarly, this benefit could also 

include the separate benefits stream 

caused by a deferral of replacement of 

other transmission facilities through 

identification and selection for purposes 

of cost allocation in the regional 

transmission plan of a transmission 

facility or facilities. This could be 

measured through calculation of the 

present value savings for the period of 

deferral of additional replacement 

transmission facilities multiplied by 

their estimated capital cost. 

193. A number of public utility 

transmission providers already evaluate 

the avoided or deferred costs of 

reliability transmission projects. For 

example, SPP uses a power flow model 

to analyze the ability of potential 

economic and Public Policy 

transmission facilities to meet the same 

thermal reliability needs addressed by a 

potential reliability transmission 

facility. The costs of these avoided or 

delayed reliability transmission 


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329SPP Benefit Metrics Manual, SPP Engineering, 

at 15 (Nov. 6, 2020). 

330The Brattle Group, Benefit-Cost Analysis of 

Proposed New York AC Transmission Upgrades, 

The Brattle Group, at 114 (Sept. 15, 2015). 

331SPP, Benefits for the 2013 Regional Cost 

Allocation Review, at 25 (Sept. 13, 2012). 

332MISO, Proposed Multi Value Project Portfolio: 

Business Case Workshop, at 36–38 (Sept. 19 & 29, 

2011). 

333When this calculation is adjusted to account 

for purchases and sales outside the region, we 

propose to define this as adjusted production cost 

savings. 

334See MISO, FERC Electric Tariff, Attach. FF, 

Benefit Metrics § (I)(A)(1) (33.0.0). 

335See PJM Interconnection L.L.C.,142 FERC 

¶ 61,214, at P 416 (2013) (PJM First Regional 

Compliance Order); New York Independent System 

Operator Corp.,143 FERC ¶ 61,059 at PP 268, 269, 

n.516 (2013) (NYISO First Regional Compliance 

Order); NYISO, NYISO Tariffs, OATT, attach. Y, 

§ 31.5 (27.0.0), § 31.5.4.3.2. For high voltage 

economic transmission facilities, PJM allocates 50% 

of the costs in accordance with its economic 

analysis and allocates the other 50% of the costs on 

a load-ratio share basis. 

facilities are used to determine the 

reliability benefit of the potential 

economic or Public Policy Requirements 

transmission facilities.329 Public utility 

transmission providers could also use 

avoided costs to calculate the benefits of 

replacing aging transmission facilities. 

NYISO, for example, estimates the 

benefits associated with the replacement 

of aging transmission facilities by 

quantifying the savings of not having to 

refurbish the facilities in the future.330

194. Another potential benefit of 

regional transmission infrastructure is 

reduced frequency of loss of load events 

by providing additional pathways for 

connecting generation resources with 

load in regions that can be constrained 

by weather events and unplanned 

outages (if planning reserve margin is 

not changed despite lower loss of load 

events), as well as improved physical 

reliability benefits by reducing the 

likelihood of load shed events; or 

reduced planning reserve margin, which 

we propose to define as the reduction in 

capital costs of generation needed to 

meet resource adequacy requirements 

(i.e., planning reserve margins) while 

holding loss of load probability 

constant. There is an overlap between 

reduced loss of load probability benefits 

and reduced planning reserve margin 

benefits, such that a single transmission 

facility can either reduce loss of load 

events if the planning reserve margin is 

unchanged or allow for the reduction in 

planning reserve margins if loss of load 

events remain constant, but not both 

simultaneously. 

195. As for reduction in loss of load 

probability benefits, transmission 

investments, even those not made to 

satisfy a reliability need, generally 

enhance the reliability of the 

transmission system by increasing 

transfer capability, which, in turn, 

reduces the likelihood that a public 

utility transmission provider will be 

unable to serve its load due to a shortage 

of generation over a given period. This 

enhancement in reliability can be 

measured as a reduction in loss of load 

probability, or the likelihood of system 

demand exceeding generation over a 

given period. One example of how a 

reduction of loss of load probability 

benefit could be calculated can be found 

in a report by SPP’s Metrics Task Force. 

The report proposes quantifying the 

incremental increase in system 

reliability by determining the reduction 

in expected unserved energy between 

the base case and the change case, 

obtaining the value of lost load, and 

multiplying these two values to obtain 

the monetary benefit of enhanced 

reliability associated with a 

transmission expansion.331

196. A lower planning reserve margin 

requirement is another way to 

demonstrate a resource adequacy 

benefit. Investments in transmission 

capacity can reduce the system-wide 

planning reserve margin requirement of 

the system-wide or reserve margin 

requirement within individual resource 

adequacy zones of a transmission 

planning region, which can reduce the 

need for generation capital 

expenditures. It is important to note 

that, due to the overlap between the 

benefit obtained from a reduction in 

reserve margin requirements and the 

benefit associated with loss of load 

probability, only one of these benefits 

should be calculated for a transmission 

investment, but not both 

simultaneously. 

197. RTOs/ISOs have calculated the 

transmission benefits of reduced 

planning reserve margins. MISO, for 

example, calculated a reduction in 

planning reserves associated with its 

MVP portfolio, which reduced the need 

for future generation buildout to meet 

reserve requirements, by using loss of 

load expectation reliability simulations. 

MISO estimated that its MVP portfolio 

was expected to reduce the required 

planning reserve margin by up to one 

percentage point, which translated into 

a projected savings of $1.0 to $5.1 

billion in benefits over 10 years.332

198. Another potential benefit of 

regional transmission infrastructure is 

production cost savings, which we 

describe as savings in fuel and other 

variable operating costs of power 

generation that are realized when 

transmission facilities allow for 

displacement of higher-cost supplies 

through the increased dispatch of 

suppliers that have lower incremental 

costs of production, as well as a 

reduction in market prices as lower-cost 

suppliers set market clearing prices.333

199. Most regional transmission 

planning processes currently estimate 

production cost savings. Generally, 

within RTOs/ISOs, security-constrained 

production cost models simulate the 

hourly operations of the electric system 

and the wholesale electricity market by 

emulating how system operators would 

commit and dispatch generation 

resources to serve load at least cost, 

subject to transmission and operating 

constraints. The traditional method for 

estimating the changes in adjusted 

production costs associated with 

proposed transmission facilities (or 

portfolio of facilities) is to compare the 

adjusted production costs with and 

without those facilities. Analysts 

typically call the market simulations 

without the proposed transmission 

facilities the ‘‘Base Case’’ and the 

simulations with those facilities the 

‘‘Change Case.’’ 

200. Approaches used to calculate 

production cost savings vary. MISO uses 

production cost savings (adjusted for 

import costs and export revenues) to 

allocate the costs of its Market 

Efficiency Projects to cost allocation 

zones based on each zone’s share of the 

total adjusted production cost 

savings.334 NYISO and PJM, in contrast, 

use reductions to load energy payments 

(adjusted to reflect the reduced value of 

transmission congestion contracts) to 

allocate the costs of economic 

transmission facilities.335

201. Non-RTO/ISO regions, without 

centrally organized energy markets, rely 

on other tools to perform analyses of 

production cost savings. For example, 

WestConnect’s regional cost allocation 

method for regional transmission 

facilities driven by economic 

considerations identifies the benefits 

and beneficiaries of a proposed regional 

transmission facility or facilities by 

modeling the potential of the 

transmission facilities to support more 

economic bilateral transactions between 

generators and loads in the region. 

Specifically, WestConnect considers the 

transactions between loads and lowercost generation that a proposed regional 

transmission facilities could support 

and, accounting for the costs associated 

with transmission service, identifies the 

transactions that are likely to occur. 

WestConnect then estimates any 

resulting cost savings (in the form of 

reductions in production costs and 

reserve sharing requirements) and 


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336Pub. Serv. Co. of Colo., 142 FERC ¶ 61,206, at 

P 314 (2013). 

337PROMOD is a generator and portfolio 

modeling system. https://www.hitachienergy.com/ 

us/en/offering/product-and-system/energyplanning-trading/market-analysis/promod. 

338ATC explains that the marginal loss 

component for transmitting internal generation to 

load is the marginal loss charge differential between 

load and generation, and the loss refund returns 

half of that amount. ATC, Planning Analysis of the 

Paddock-Rockdale Project, Docket No. 137–CE–149, 

app. C, Ex. 1, at 34–38 (Wisc. Pub. Serv. Comm’n 

Apr. 5, 2007). 

339SPP, Regional Cost Allocation Review (RCAR 

II), at 5 (July 11, 2016), https://www.spp.org/ 

documents/46235/rcar%202%20report

%20final.pdf. 

340Brattle-Grid Strategies Oct. 2021 Report at 79. 

341SPP, Regional Cost Allocation Review (RCAR 

II), at 51–52. To estimate incremental savings 

associated with mitigation of transmission outage 

costs, SPP analyzed outage cases in PROMOD for 

the 2025 study year. SPP developed cases based on 

12 months of historical SPP transmission data. SPP 

said that because of the high volume of historical 

transmission outage data (approximately 7,000 

outage events) and based on the expectation that 

many outages would not lead to significant 

increases in congestion, SPP only modeled a subset 

of outage events. The events selected were those 

expected to create significant congestion and met at 

least one of three conditions. Id. at 51. 

342Opinion Granting Certificate of Public 

Convenience and Necessity, In the Matter of the 

Application of Southern California Edison 

Company (U 338–E) for a Certificate of Public 

Convenience and Necessity Concerning the DeversPalo Verde No. 2 Transmission Line Project, 

Application 05–04–015 (Cal. Comm’n Jan. 27, 

2007). 

343ATC, Planning Analysis of the PaddockRockdale Project, Docket No. 137–CE–149, app. C, 

Ex. 1, at 4, 50–53 (Wisc. Pub. Serv. Comm’n Apr. 

5, 2007). 

344M. Goggin, Grid Strategies, LLC, Transmission 

Makes the Power System Resilient to Extreme 

Weather (July 2020). 

allocates the costs of the regional 

transmission facilities on that basis.336

202. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to reduced transmission 

energy losses, which we describe as 

reduced total energy necessary to meet 

demand stemming from reduced energy 

losses incurred in transmittal of power 

from generation to loads. These benefits 

include the reduced energy losses 

incurred when transmitting power from 

generation to loads. 

203. Production cost savings metrics 

used today typically exclude reduced 

transmission energy losses and the other 

three production cost savings-related 

benefits in our proposed list described 

further below. Including these 

additional benefits can produce a more 

robust set of congestion and production 

cost benefits that can be quantified and 

integrated into the method for 

calculating production cost savings, 

and, therefore, help to ensure that the 

more efficient or cost-effective 

transmission facilities are selected in 

the regional transmission plan for 

purposes of cost allocation through 

Long-Term Regional Transmission 

Planning. 

204. To measure reduced 

transmission energy losses, public 

utility transmission providers could: (1) 

Simulate losses in production cost 

models; (2) estimate changes in losses 

with power flow models for a range of 

hours; or (3) estimate how the cost of 

supplying losses will likely change with 

marginal loss charges. For example, 

American Transmission Company 

(ATC) measured reduced transmission 

energy losses based on changes in 

marginal loss charges and loss refund 

estimates using the marginal loss 

component from the PROMOD 337

electric market simulation software 

simulations for the Paddock-Rockdale 

345 kV Access Project,338 which 

produced cost reduction benefits using 

adjusted production cost analysis. Also, 

SPP’s analysis for its Regional Cost 

Allocation Review (RCAR) process 

estimated energy loss reductions 

through post-processing the marginal 

loss component of the locational 

marginal prices in PROMOD simulation 

results.339

205. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to reduced congestion 

due to transmission outages, which we 

describe as reduced production costs 

resulting from avoided congestion 

during transmission outages. Such 

benefits include reduced production 

costs during transmission outages that 

significantly increase transmission 

congestion. Production cost simulations 

typically consider planned generation 

outages and, in most cases, a random 

distribution of unplanned generation 

outages. In contrast, they do not 

generally reflect transmission outages, 

planned or unplanned.340 Public utility 

transmission providers could measure 

this benefit, for example, by either 

building a data set of a normalized 

outage schedule (not including extreme 

events) that can be introduced into 

simulations or by inducing system 

constraints more frequently. In its RCAR 

process, SPP measured the benefits of 

reducing congestion resulting from 

transmission outages. There, SPP 

modeled outage events and new 

constraints based on these outages in 

PROMOD for a 2025 case year, and then 

conducted PROMOD simulations to 

calculate adjusted production cost 

savings for a base case and the change 

case including the transmission line.341

In another example, SPP calculated the 

financial value of reducing congestion 

caused by outages based on a rerun of 

its entire day-ahead and real-time 

market. 

206. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to mitigation of extreme 

events and system contingencies, which 

we describe as reductions in production 

costs resulting from reduced high-cost 

generation and emergency procurements 

necessary to support the transmission 

system during extreme events (such as 

unusual weather conditions, fuel 

shortages, or multiple or sustained 

generation and transmission outages) 

and system contingencies. These 

benefits include reduced production 

costs during extreme events facilitated 

by a more robust transmission system 

that reduces high-cost generation and 

emergency procurements necessary to 

support the system. 

207. Public utility transmission 

providers can measure benefits from the 

mitigation of extreme events and system 

contingencies by calculating the 

probability-weighted production cost 

savings through production cost 

simulation for a set of extreme historical 

market conditions. One example is 

CAISO’s analysis of Devers-Palo Verde 

Line No. 2 (PVD2), where CAISO 

modeled several contingencies to 

determine the value of the line during 

high-impact, low-probability events.342

Another example is ATC’s production 

cost simulation analysis of insurance 

benefits for the ATC Paddock-Rockdale 

transmission line. ATC found that 

probability-weighted savings from 

reducing production and power 

purchase costs during a number of 

simulated extreme events offset 20% of 

total project costs.343 Finally, a Grid 

Strategies study found development of 

an additional 1,000 MW of transmission 

capacity into Texas would have fully 

paid for itself over four days during 

Winter Storm Uri and the same into 

MISO would have saved $100 million 

during the same time period.344

208. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to mitigation of weather 

and load uncertainty, which we 

describe as reduced production costs 

during higher-than-normal load 

conditions or significant shifts in 

regional weather patterns. This is 

beyond the effects of extreme weather 

described above and may account for, 

for example, regional and sub-regional 

load variances that will occur due to 

changing weather patterns. This ignores 

the potential benefit of transmission 

expansions under more normal system 

operating conditions, such as when the 

system experiences higher-than-normal 

load conditions or significant shifts in 


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345ERCOT, Economic Planning Criteria: Question 

1: 1/7/2011 Joint CMWG/PLWG Meeting, at 10 (Mar. 

4, 2011). The $57.8 million probability-weighted 

estimate is calculated based on ERCOT’s simulation 

results for three load scenarios and Luminant 

Energy estimated probabilities for the same 

scenarios. 346 ITC Holdings Co., Joint Application, Docket 

No. EC12–145–000, at Ex. ITC–600, 77–78 (Test. of 

Pfeifenberger) (filed Sept. 24, 2012). 

347 Id. 

348 Id. at 58–59. 

349Opinion Granting Certificate of Public 

Convenience and Necessity, In the Matter of the 

Application of Southern California Edison 

Company (U 338–E) for a Certificate of Public 

Convenience and Necessity Concerning the DeversPalo Verde No. 2 Transmission Line Project, 

Application 05–04–015 (Cal. Comm’n Jan. 27, 

2007). 

regional weather patterns that change 

the relative power consumption levels 

across multiple regions or sub-regions. 

209. One example of the mitigation of 

weather and load uncertainty benefits is 

the simulations that ERCOT performed 

for normal loads, higher-than-normal 

loads, and lower-than-normal loads for 

a Houston import project, which 

showed increased benefits with a 

probability-weighted average for all 

three simulated load conditions.345 To 

measure this benefit, production cost 

model inputs under high and low load 

conditions can be used to develop 

regional variations of relative benefits 

under these conditions. Production cost 

benefits can then be modeled based 

upon a probability weighted average 

anticipating varying load conditions, 

with the increment over a base case 

representing additional production cost 

savings. 

210. Another set of potential benefits 

of regional transmission infrastructure is 

capacity cost benefits related to reduced 

peak energy losses, which we describe 

as reduced generation capacity 

investment needed to meet peak load. 

211. Capacity cost savings from 

reduced peak energy losses benefits 

refer to the ability of proposed 

transmission facilities to lessen the 

amount of transmission system energy 

losses during peak-load conditions 

which, over time, would decrease the 

need for new generation capacity 

installations or purchases. To the extent 

that new transmission facilities result in 

changes to generation dispatch and 

flows, transmission system energy 

losses will also change. If transmission 

system losses are reduced via the new 

transmission facilities, public utility 

transmission providers will not have to 

construct or procure additional 

generation to satisfy installed capacity 

requirements for peak-load conditions. 

If there is a reduction in energy losses 

during peak conditions, this would 

result in, presumably, lowered 

investments for generation capacity 

resources to meet the peak load. For 

example, Entergy found that potential 

transmission facilities in its footprint 

could reduce peak-load transmission 

losses and associated needed generation 

investment by 2% of total transmission 

facility costs.346 We note that capacity 

cost savings from reduced peak energy 

losses only attempt to evaluate benefits 

for peak-load conditions. 

212. One potential way to calculate 

capacity cost savings from reduced peak 

energy losses is to calculate the present 

value of capital cost savings associated 

with the reduction in installed 

generation requirements.347 To arrive at 

the value of capital cost savings 

associated with these savings, the 

estimated net cost of new entry (Net 

CONE) (i.e., the cost of new peaking 

generating capacity net of operating 

margins earned in energy and ancillary 

services markets when the region is 

resource constrained) would be 

multiplied by the reduction in installed 

generation capacity requirements. The 

resulting value would represent the 

avoided cost of procuring more 

generation to cover transmission system 

losses during peak-load conditions that 

would be passed on to consumers via 

lowered generation capacity costs. 

213. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to deferred generation 

capacity investments, which we 

describe as reduced costs of needed 

generation capacity investments 

realized through expanded import 

capability into resource-constrained 

areas. 

214. Deferred generation capacity 

investments benefits reflect the value of 

increased transfer capability, provided 

by new transmission facilities, that 

either defers or negates the need to 

invest in generation capacity resources 

within a transmission planning region 

by increasing import capability from 

neighboring regions into resourceconstrained areas. By expanding the 

transmission system’s capacity to 

deliver energy to load centers, public 

utility transmission providers may 

avoid additional generation capacity 

investments closer to load centers. We 

note, for example, an ITC study 

examining transmission facilities 

between the eastern, non-ERCOT region 

of Texas that can import energy from 

Arkansas and Louisiana. The study 

highlighted that, by enabling imports of 

surplus energy from Arkansas and 

Louisiana, additional generation 

capacity investments were not needed 

in the eastern, non-ERCOT region of 

Texas.348

215. One potential manner of 

calculating deferred generation capacity 

investments is to calculate the present 

value of generation capacity cost savings 

resulting from deferred generation 

investments, based on Net CONE. 

Specifically, the total value of deferred 

generation investments could be 

determined by multiplying the change 

in the public utility transmission 

provider’s installed capacity 

requirement by Net CONE. The value of 

deferred generation capacity 

investments would ultimately benefit 

consumers through lower generation 

capacity costs. 

216. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to access to lower-cost 

generation, which we describe as 

reduced total cost of needed generation 

due to the ability to locate generating 

units in a more economically efficient 

location (e.g., low permitting costs, lowcost sites on which plants can be built, 

access to existing infrastructure, low 

labor costs, low fuel costs, access to 

valuable natural resources). In other 

words, this refers to the value of savings 

that may accrue to consumers who, 

because of a new regional transmission 

facility or portfolio of facilities, are able 

to access lower cost generation 

resources that they would have been 

unable to otherwise. For example, if the 

new regional transmission facilities 

extend to generation located farther 

from load centers that may be lower-cost 

compared to generation located closer to 

load centers that may be higher-priced, 

the new regional transmission facilities 

will provide savings to consumers via 

increased access lower-cost generation. 

We note, for example, that CAISO found 

that its proposed PVD2 transmission 

project, which provided an additional 

link between Arizona and California, 

permitted CAISO to meet reliability 

requirements through imports of lowercost, new generation in Arizona.349

217. One potential way to calculate 

benefits from access to lower-cost 

generation enabled by a regional 

transmission facility or portfolio of 

facilities would be calculating them 

akin to how production cost savings are 

calculated. Specifically, public utility 

transmission providers could calculate 

the reduction in total generation 

investment costs by comparing the 

status quo (i.e., higher-cost local 

generation) to a future (i.e., lower-cost 

distant generation) where the proposed 

new regional transmission facilities 

allow for the import of those lower-cost 

generation. By allowing for the import 

of lower-cost generation, consumers 


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26544 Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 

350TC Holdings, Joint Application, Docket No. 

EC12–145–000, Ex. No. ITC–600, at 54–55 (filed 

Sept. 24, 2012) (Pfeifenberger, Direct Testimony on 

behalf of ITC Holdings). 

351Brattle-Grid Strategies Oct. 2021 Report at 46– 

47. 

352F.A. Wolak, Managing Unilateral Market 

Power in Electricity, Policy Research Working 

Paper; No. 3691. World Bank, Washington, DC, at 

8 (2005). 

353Opinion Granting Certificate of Public 

Convenience and Necessity, In the Matter of the 

Application of Southern California Edison 

Company (U 338–E) for a Certificate of Public 

Convenience and Necessity Concerning the DeversPalo Verde No. 2 Transmission Line Project, 

Application 05–04–015 (Cal. Comm’n Jan. 27, 

2007); CAISO, Transmission Economic Assessment 

Methodology, Chapter 4 (Jun. 2004); ATC, Planning 

Analysis of the Paddock-Rockdale Project, at 44–49 

(Apr. 5, 2007). 

354The Residual Supplier Index is calculated as 

the ratio of residual supply (i.e., total supply minus 

the capacity of the largest supplier in the market) 

to the total demand. If the Residual Supplier Index 

is less than 1.0, it means the largest supplier is 

‘‘pivotal,’’ meaning that a load cannot be served 

without the largest supplier making available at 

least some of its capacity. With inelastic demand, 

a pivotal supplier theoretically would be able to set 

the market price at any desired level above the 

competitive price. See von der Fehr, Nils-Henrik & 

David Harbord, Spot Market Competition in the UK 

Electricity Industry, Economic Journal, at 103, 531– 

46 (1993); ATC, Planning Analysis of the PaddockRockdale Project, Docket No. 137–CE–149, app. C, 

Ex. 1, at 44 & n.11 (Wisc. Pub. Serv. Comm’n Apr. 

5, 2007). 

355 In the case of the Paddock-Rockdale Project, 

the MISO independent market monitor had 

designated the area as a ‘‘Narrow Constrained Area’’ 

and estimated that, whenever a resource became 

pivotal in that area its offer would exceed its 

marginal costs by up to $36/MWh. While the MISO 

independent market monitor provided such an 

estimate for the Paddock-Rockdale Project, we do 

not suggest that any specific entity conduct the 

necessary study deriving this estimate (e.g., the 

public utility transmission providers in a 

transmission planning region could also conduct 

such a study). 

356This assumption is based on a study analyzing 

summer 2000 peak hourly data from the California 

Power Exchange. Sheffrin, A., (2002), ‘‘Predicting 

Market Power Using the Residual Supplier Index,’’ 

Mimeo, Department of Market Analysis, CAISO. 

would benefit via reduced total cost of 

generation. 

218. While we acknowledge 

calculating benefits from access to 

lower-cost generation may be similar to 

methodologies for calculating 

production cost savings, we believe that 

calculating production cost savings 

using traditionally used methodologies 

would not adequately capture benefits 

associated with capacity cost savings. 

Such methodologies do not account for 

capacity cost savings since they do not 

consider load variances during hotter or 

colder than normal weather conditions; 

do not consider transmission system 

outages or other situations where less 

than the full transfer capability of the 

transmission facility is available; do not 

consider extreme events like multiple 

generator outages; and do not capture 

‘‘real-world’’ operational issues such as 

forecasting errors or unexpected loop 

flows.350 Additionally, we believe that 

calculating access to lower-cost 

generation benefits, as Brattle Group 

explains, may require additional or 

separate analysis by public utility 

transmission providers since accurately 

capturing the aforementioned benefits 

may require a different generation mix 

than specified in the production cost 

simulations between the Base Case (e.g., 

with generation located in lower-quality 

or higher-cost locations) and the Change 

Case (e.g., with more generation located 

in higher-quality or lower-cost 

locations).351

219. Another set of potential benefits 

of regional transmission infrastructure is 

benefits related to increased 

competition. We describe increased 

competition as reduced bid prices in 

wholesale electricity markets due to 

increased competition among generators 

and reduced overall market 

concentration. Regional transmission 

facilities can increase competition in, 

and the liquidity of, wholesale electric 

power markets by increasing the 

number of wholesale electricity 

suppliers that are able to compete to 

supply electricity at locations in the 

transmission network served by the 

transmission facility,352 which helps to 

ensure just and reasonable Commissionjurisdictional rates. 

220. More specifically, to the extent 

that certain portions of a transmission 

planning region remain importconstrained, such that a single resource, 

or even a small number of resources, 

can have an outsized influence on the 

price of energy paid by load by 

increasing the price in their offer to sell 

energy, additional transmission capacity 

may reduce such influence, and thereby 

create benefits to transmission 

customers in the form of reduced energy 

prices. 

221. Some public utility transmission 

providers have considered this benefit 

for certain transmission facilities. For 

example, CAISO evaluated the PVD2 

and Path 26 Upgrade projects, and ATC 

evaluated its Paddock-Rockdale project, 

for increased competition benefits.353

We highlight three possible methods to 

calculate increased competition 

benefits, all of which ATC employed in 

evaluating the benefits of the PaddockRockdale Project, as examples of how 

public utility transmission providers 

could calculate this benefit. The first 

two methods that ATC employed are 

similar in that ATC estimated the 

change in a measure of market 

concentration (i.e., the extent to which 

the largest supplier is pivotal)—called 

the Residual Supplier Index 354—which 

assumes a certain percentage of load is 

subject to market-based pricing, and 

measured the subsequent effect on 

generators’ ability to offer above their 

marginal costs (measured as a price-cost 

markup) and related energy prices. ATC 

calculated the change in the Residual 

Supplier Index using an assumed 

change in import capability to the area 

served by the new transmission facility. 

222. The first method ATC employed 

to calculate the increased competition 

benefit, called the ‘‘Modified MISO 

IMM Method,’’ draws from two key 

assumptions to determine price markups. First, the Modified MISO IMM 

Method requires an estimate of the 

pivotal supplier’s price-cost markup for 

the area served by the transmission 

facility for all times when the supplier 

is pivotal.355 Second, this method 

assumes that the price-cost markup 

increases linearly as the Residual 

Supplier Index falls below 1.2,356 such 

that there is no price-cost markup where 

the Residual Supplier Index for an hour 

is above 1.2 (i.e., no improved 

competition benefit) and the price 

markup is half the estimated price-cost 

markup from the first assumption where 

the Residual Supplier Index for an hour 

is less than 1.0. Finally, this method 

assumes that the pivotal supplier is the 

marginal resource that sets the energy 

price when the Residual Supplier Index 

is below 1.2. The difference in pricecost markup for hours when the 

Residual Supplier Index is below 1.2 

provides the benefits from increased 

competition. 

223. The second potential method to 

calculate increased competition benefits 

that ATC employed, the ‘‘Modified 

CAISO Method,’’ estimates the energy 

price impacts of a new transmission 

facility by using regression analysis to 

find the relationship between historical 

market structure and price-bid markups. 

CAISO first developed this regression 

equation and its coefficients in its 2004 

report evaluating the economic viability 

of certain transmission upgrades, 

including the PVD2 and Path 26 

Upgrade projects.357 CAISO’s study 

also used two binary indicator variables: 

One for the summer period in CAISO 

and another for peak hours. We note 

that public utility transmission 

providers using the Modified CAISO 

approach may find that coefficients 

developed using data specific to the 

transmission planning region where the 

public utility transmission provider is 

located are more appropriate and may 

also wish to include more independent 

variables specific to their respective 

transmission planning regions. 


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358See, e.g., F.A. Wolak, Measuring the 

competitiveness benefits of a transmission 

investment policy: The case of the Alberta 

electricity market 86 Energy Policy 426–444 (June 

2015); N. Ryan, The Competitive Effects of 

Transmission Infrastructure in the Indian Electricity 

Market, 13 American Economic Journal: 

Microeconomic 2, 202–42 (May 2021). 

359Brattle-Grid Strategies Oct. 2021 Report at 50. 

360 Id. 

361See, e.g., NYISO Comments at 34–37 (stating 

that NYISO limits consideration of benefits to 10 

years and recommending that the Commission grant 

public utility transmission providers discretion to 

plan for up to 20 years of needs and benefits); see 

also NextEra Comments at 79–80 (recommending a 

similar length of time for consideration of benefits 

as for scenario planning); see also February Joint 

Task Force Tr 20:23–25 (Clifford Rechtschaffen) 

(arguing that the Commission should extend the 

timeframe over which benefits are calculated to be 

15–20 years or longer), 24:4–8 (Matthew Allen) 

(advocating for recognizing benefits over at least a 

20-year timeframe given the long life of 

transmission assets). 

362ACPA and ESA Comments at 44–45; see also 

PIOs Comments at 121–122. 

363Entergy Comments at 10–11; see also EEI 

Comments at 30–31 (arguing for maintaining the 

Commission’s policies on abandoned plant recovery 

because of the additional uncertainty inherent in 

longer-term transmission planning); Minnesota 

Commerce Comments at 3 (stating that future 

uncertainty is compounded by the rapid pace of 

technological change). 

364 Xcel Comments at 20 n.52. 

365See MISO, LRTP Business Case, Long Range 

Transmission Planning Workshop, at slide 7 (Jan. 

21, 2022, Revised Feb. 2, 2022), https://

cdn.misoenergy.org/20220121%20LRTP

%20Workshop%20Item%2004

%20Business%20Case%20Presentation619895.pdf; 

CAISO, 20-Year Transmission Outlook (Draft Jan. 

31, 2022), https://www.caiso.com/Initiative

Documents/Draft20-YearTransmissionOutlook.pdf; 

SPP Engineering, 2021 SPP Transmission 

Expansion Plan Report (Jan. 11, 2021), https://

spp.org/documents/56611/ 

2021%20step%20report.pdf. 

224. The third potential method to 

calculate increased competition 

benefits, the ‘‘Bidding Behavior 

Method,’’ relies on a simulation model 

that optimizes bidding behavior from a 

supplier perspective given each 

supplier’s supply portfolio and load 

obligations. This model could be based 

on the theoretical incentive that 

suppliers have to increase price-cost 

markups in proportion to the absolute 

value of the slope of residual demand 

(i.e., total demand less the supply of all 

other resources serving the same 

load).358 Public utility transmission 

providers in a transmission planning 

region would develop a study 

estimating market prices for a future 

period matching the planning horizon 

as load, generation supply, transmission 

constraints, and import capability 

changed. Public utility transmission 

providers in a transmission planning 

region would also assume that a 

percentage of load was exposed to 

congestion. 

225. Finally, another set of potential 

benefits of regional transmission 

infrastructure is benefits related to 

increased market liquidity. We describe 

increased market liquidity as enabling a 

larger number of entities, both buyers 

and sellers, to participate in a market. 

By increasing the number of market 

participants, both buyers and sellers, 

transmission facilities may provide 

benefits through reduced transaction 

costs (e.g., bid-ask spreads) of bilateral 

transactions, increased pricing 

transparency, increased efficiency of 

risk management, improved contracting, 

and better clarity for long-term 

transmission planning and investment 

decisions.359 The primary increased 

market liquidity benefit to transmission 

customers is the decrease in energy 

prices. For example, bid-ask spreads for 

bilateral trades at less liquid hubs have 

been found to be between $0.50 to 

$1.50/MWh higher than the bid-ask 

spreads at more liquid hubs.360 Public 

utility transmission providers could 

quantify increased market liquidity 

benefits to transmission customers by 

estimating (1) how additional 

transmission facilities may increase 

liquidity and (2) how increased 

liquidity may reduce bid-asks spreads or 

energy prices. 

(b) Evaluation of Transmission Benefits 

Over Longer Time Horizon 

(1) Comments 

226. Several commenters responding 

to the ANOPR recommend that the 

Commission allow or require public 

utility transmission providers to 

evaluate the benefits of transmission 

facilities over a longer time horizon.361

For example, ACPA and ESA argue that 

proper economic analysis entails an 

analysis of the benefits of a proposed 

transmission facility over the asset’s life, 

which is at least 40 years for 

transmission lines.362 Other 

commenters, however, raise concerns 

with attempts to forecast future 

transmission system conditions in order 

to consider potential benefits on a 

longer time horizon.363 For example, 

Xcel argues that planning for the future 

is inherently uncertain, and that the 

benefits of transmission facilities can 

change over time.364

(2) Proposed Reform 

227. We propose to require that public 

utility transmission providers in each 

transmission planning region evaluate, 

as part of Long-Term Regional 

Transmission Planning, the benefits of 

regional transmission facilities over a 

time horizon that covers, at a minimum, 

20 years starting from the estimated inservice date of the transmission 

facilities. For example, if Long-Term 

Regional Transmission Planning 

identifies transmission facilities that are 

estimated to be in-service in year 10 of 

the 20-year long-term transmission 

planning horizon, then the estimate of 

benefits for those same transmission 

facilities will commence at year 10 and 

cover an additional 20 years. We believe 

that 20 years may strike an appropriate 

balance that reasonably illustrates the 

benefits a transmission facility is likely 

to provide over its useful life, which can 

exceed 40 years, while recognizing the 

inherent difficulties in attempting to 

predict system conditions too far into 

the future. Moreover, we note that some 

public utility transmission providers 

currently conduct long-term 

transmission planning over a 20-year 

horizon, and thus have some experience 

with modelling and making 

assumptions over this period, though 

such modelling is typically for 

informational purposes and not to select 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation.365

228. We propose to require that public 

utility transmission providers evaluate 

benefits over this time horizon in all 

stages of Long-Term Regional 

Transmission Planning, which includes 

evaluating regional transmission 

facilities, selecting more efficient or 

cost-effective regional transmission 

facilities in the regional transmission 

plan for purposes of cost allocation, and 

allocating the costs of such transmission 

facilities in a manner that is at least 

roughly commensurate with estimated 

benefits. We also note that for 

consistency and a matching comparison 

of benefits and costs over time, to the 

extent that public utility transmission 

providers estimate the costs of 

transmission facilities beyond the inservice date of the transmission 

facilities, we propose that they should 

estimate those future costs over the 

same time horizon as the estimated 

benefits. 

229. Finally, while we propose to 

establish a minimum requirement for 

the time horizon over which benefits 

must be evaluated, we clarify that 

public utility transmission providers 

may propose approaches that exceed 

this minimum requirement. In 

particular, while we believe that 20 

years may strike a reasonable balance, 

we also believe that a time horizon 

longer than 20 years for the evaluation 

of benefits may be consistent with the 

long life of transmission facilities— 


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366ACPA and ESA Comments at 44–45; see also 

WIRES Comments at 7–8 (recommending 

accounting for benefits of transmission facilities 

over their useful lives). 

367ANOPR, 176 FERC ¶ 61,024 at PP 53, 89, 91. 

368 ITC Comments at 11; State Agencies 

Comments at 21; ELCON Reply Comments at 3–4; 

see also Southern Comments at 13–14 (stating that 

vertically-integrated utilities already use a portfolio 

approach). 

369U.S. DOE Comments at 40–41. 

370PIOs Comments at 50–51. 

371ACEG Reply Comments at 5, 8; ITC Comments 

at 6, 11, 28. 372U.S. DOE Comments at 40–41; see also 

February Joint Task Force Tr 24:15–22 (Matthew 

Allen) (stating his belief that transmission planners 

should be looking at projects and benefits on a 

portfolio basis to identify synergies). 

373MISO, Multi Value Project Portfolio Results 

and Analyses at 1–6 (2012), https://

cdn.misoenergy.org/2011%20MVP%20Portfolio

%20Analysis%20Full%20Report117059.pdf. 

374See, e.g., February Joint Task Force Tr. 76:10– 

12 (Kimberly Duffley) (asking that the Commission 

recognize regional differences that may result in 

portfolio projects working for one region but not for 

all regions). 

375Order No. 1000, 136 FERC ¶ 61,051 at PP 328– 

331; Order No. 1000–A, 139 FERC ¶ 61,132 at P 452. 

376Order No. 1000, 136 FERC ¶ 61,051 at P 331. 

377See Order No. 1000–A, 139 FERC ¶ 61,132 at 

P 455. 

which generally exceeds 20 years by a 

substantial margin—and also consistent 

with the fact that transmission facilities 

provide significant benefits over their 

entire useful life.366 To the extent public 

utility transmission providers would 

like to evaluate transmission benefits 

beyond the proposed minimum time 

horizon, we propose to require that they 

demonstrate that their proposal is 

consistent with or superior to any final 

rule in this proceeding. 

230. We seek comment on the 

requirements proposed in this section of 

the NOPR. 

(c) Evaluation of the Benefits of 

Portfolios of Transmission Facilities 

231. In the ANOPR, the Commission 

sought comment on whether public 

utility transmission providers would 

identify more efficient or cost-effective 

transmission facilities in their regional 

transmission planning processes if they 

evaluated the benefits of a portfolio of 

transmission facilities collectively 

rather than individual transmission 

facilities separately.367

(1) Comments 

232. Many commenters recommend 

that the Commission permit or require 

public utility transmission providers to 

use a portfolio approach when 

evaluating the benefits of transmission 

facilities.368 Under such an approach, 

public utility transmission providers 

would evaluate multiple transmission 

facilities in an aggregated, integrated 

fashion rather than doing so on a 

facility-by-facility basis. For example, 

U.S. DOE argues that a portfolio 

approach is more likely to result in an 

accurate evaluation of the benefits of 

transmission facilities than would an 

approach requiring evaluation of each 

facility individually,369 while PIOs 

claim that facility-by-facility rather than 

portfolio-based evaluation 

underestimates the benefits of regional 

transmission facilities.370 Other 

commenters explain that public utility 

transmission providers could achieve 

administrative efficiencies using a 

portfolio approach, which can help 

avoid the necessity of running the same 

analyses on each facility.371

(2) Proposed Reform 

233. We propose to afford public 

utility transmission providers in each 

transmission planning region the 

flexibility to propose to use a portfolio 

approach in the evaluation of benefits of 

regional transmission facilities through 

their Long-Term Regional Transmission 

Planning. Evaluating the benefits of a 

portfolio of regional transmission 

facilities appears to contain several 

advantages compared to evaluating the 

benefits of each proposed regional 

transmission facility individually. 

Several commenters explain that future 

benefits may be more stable or evenly 

distributed over time if they are 

evaluated for a portfolio of transmission 

facilities.372 These comments are 

consistent with the fact that benefits 

from transmission facilities may change 

over time due to the inherent 

uncertainty in Long-Term Regional 

Transmission Planning and actual use of 

transmission facilities. An example of 

the evaluation of expanded benefits for 

a portfolio of transmission facilities is 

the MISO MVP Portfolio, which is a 

collection of 17 distinct transmission 

facilities, for which MISO evaluated a 

collective distribution of benefits.373

Given the suite of minimum benefits 

proposed above, we believe that 

evaluating these benefits across a 

portfolio of transmission facilities as 

opposed to each individual 

transmission facility may result in 

significant administrative efficiencies 

for public utility transmission 

providers. Moreover, we believe that a 

more stable or even distribution of 

benefits from a portfolio of transmission 

facilities may also facilitate agreement 

on regional cost allocation that is at 

least roughly commensurate with 

estimated benefits. 

234. Accordingly, we encourage this 

practice by public utility transmission 

providers. We clarify that public utility 

transmission providers that propose 

such an approach must include in their 

OATTs provisions describing how they 

would analyze the benefits of regional 

transmission facilities under a portfolio 

approach and whether the portfolio 

approach would be used for Long-Term 

Regional Transmission Planning 

universally to address transmission 

needs driven by changes in the resource 

mix and demand or would be used only 

in certain specified instances. 

235. We recognize that a variety of 

commenters request that we require the 

use of a portfolio approach. While we 

recognize the advantages to a portfolio 

approach, we also acknowledge that the 

transition to a portfolio approach may 

represent a significant change for many 

public utility transmission providers 

and that the potential benefits may not 

warrant such a change in all 

instances.374 We seek comment as to 

whether there are certain circumstances 

for which the Commission should 

require the use of a portfolio approach. 

iv. Selection of Regional Transmission 

Facilities 

236. Order No. 1000 requires public 

utility transmission providers to include 

in their OATTs a transparent and not 

unduly discriminatory process for 

evaluating whether to select a proposed 

regional transmission facility in the 

regional transmission plan for purposes 

of cost allocation.375 Order No. 1000 

does not mandate that public utility 

transmission providers select any 

transmission facility,376 and the 

Commission declined for the most part 

to set minimum standards for the 

criteria used to select a transmission 

facility in a regional transmission plan 

for purposes of cost allocation. 

However, the Commission required that 

a public utility transmission provider’s 

selection criteria be transparent and not 

unduly discriminatory.377

237. In the ANOPR, the Commission 

sought comment on whether and how 

public utility transmission providers 

should use information developed 

through long-term scenario planning to 

identify and select transmission 

facilities that meet future needs. In 

addition, the Commission sought 

comment on how public utility 

transmission providers should evaluate 

the benefits of proposed transmission 

facilities in their regional transmission 

planning processes, and whether the 

maximization of net benefits is an 

appropriate criterion for selecting 

transmission facilities in the regional 

transmission plan for purposes of cost 


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378ANOPR, 176 FERC ¶ 61,024 at P 53. 

379See id. PP 89, 91. 

380AEP Comments at 10; Ameren Reply 

Comments at 3; see also Anbaric Comments at 32 

(recommending that the Commission impose 

deadlines to ensure that transmission planning 

processes select offshore wind transmission 

facilities rather than allowing results to ‘‘languish 

in protracted stakeholder processes’’); AEE Reply 

Comments at 7–8 (requesting the adoption of 

transparency and enforcement mechanisms that 

would ensure the selection of transmission facilities 

that meet regional needs). 

381See PJM Comments at 44 (stating that PJM’s 

proposed long-term transmission planning process 

will ‘‘inform stakeholder discussions’’); see also 

Xcel Energy Comments at 20 (‘‘The Commission 

should not require all issues identified in the 

holistic planning process to result in planned 

projects.’’). 

382PJM Comments at 46; see also City of New 

York Comments at 11 (arguing that the Commission 

should adopt common project selection criteria); 

Policy Integrity Comments at 17 (recommending 

greater uniformity in selection criteria); 

Massachusetts Attorney General Comments at 25 

(arguing that consumer protection requires that 

selection criteria be ‘‘clear, real, and objective’’). 

383MISO Comments at 32; National Grid 

Comments at 14–15; American Municipal Power 

Comments at 15. 

384 ITC Comments at 9, 11, 33; NARUC Comments 

at 12; PIOs Comments at 50–51; State Agencies 

Comments at 21; AEP Reply Comments at 33; 

ELCON Reply Comments at 3–4; see also Southern 

Comments at 13–14 (stating that verticallyintegrated utilities already use a portfolio 

approach). 

385U.S. DOE Comments at 40–41. 

386 ITC Comments at 11; ACEG Comments at 5– 

6; Policy Integrity Comments at 44–46; AEP 

Comments at 16. 

387NARUC Comments at 12, 22–24 (advocating 

for maximizing benefit-cost ratio and retaining the 

benefit-cost ratio permitted by Order No. 1000); 

Entergy Comments at 18 (asking the Commission to 

retain the ability to have a benefit-cost ratio up to 

1.25); Mississippi Commission Comments at 13–14 

(arguing for a strict benefit-cost ratio of no less than 

1.25 for economic projects with the possibility of 

a higher benefit-cost ratio for specific projects); 

Entergy Reply Comments at 12–13 (asserting that a 

higher benefit-cost ratio may be appropriate for a 

longer-term planning horizon). 

388National Grid Comments at 16; American 

Municipal Power Comments at 32; PIOs Comments 

at 79; Chamber of Commerce Comments at 4; 

WIRES Comments at 7–8; AEP Comments at 9–10. 

389Order No. 1000, 136 FERC ¶ 61,051 at P 328. 

390We do not propose to change the Order No. 

1000 requirement that public utility transmission 

providers may not impose a benefit-cost ratio 

requirement higher than 1.25. See id. P 646. 

allocation.378 Finally, the Commission 

sought comment on whether public 

utility transmission providers would 

select more efficient or cost-effective 

transmission facilities in their regional 

transmission planning processes if they 

selected a portfolio of transmission 

facilities collectively.379

(a) Comments 

238. With respect to the selection of 

transmission facilities in a regional 

transmission plan for purposes of cost 

allocation, commenters responding to 

the ANOPR provided a wide range of 

feedback. Several commenters 

emphasize that scenario planning 

should ensure the selection of more 

efficient or cost-effective transmission 

facilities,380 while others argue that 

scenario planning should be solely for 

informational purposes.381 Certain 

commenters believe that Commission 

guidance on selection criteria is 

essential,382 while others argue that the 

Commission instead should provide 

flexibility for public utility transmission 

providers to adopt selection criteria.383

239. Many commenters also 

recommend that the Commission permit 

or require public utility transmission 

providers to use a portfolio approach 

when selecting transmission 

facilities.384 U.S. DOE explains that the 

benefits of individual transmission 

facilities typically are distributed 

unevenly across a region, whereas 

portfolios of transmission facilities 

generally would be expected to confer 

benefits more broadly and evenly.385

240. With respect to specific selection 

criteria or methods, several commenters 

support an approach that would select 

transmission facilities with the highest 

level of net benefits instead of facilities 

with the highest benefit-cost ratio,386

whereas other commenters support 

maintaining the maximum 1.25 benefitcost ratio permitted by Order No. 

1000.387 Other commenters recommend 

a ‘‘least-regrets’’ approach to selecting 

transmission facilities, in which public 

utility transmission providers would 

select a transmission facility identified 

through scenario planning as beneficial 

across many or all scenarios.388

(b) Proposed Reform 

241. We propose to require that public 

utility transmission providers, as part of 

the Long-Term Regional Transmission 

Planning that we propose to require in 

this NOPR, include in their OATTs: (1) 

Transparent and not unduly 

discriminatory criteria, which seek to 

maximize benefits to consumers over 

time without over-building transmission 

facilities, to identify and evaluate 

transmission facilities for potential 

selection in the regional transmission 

plan for purposes of cost allocation that 

address transmission needs driven by 

changes in the resource mix and 

demand, consistent with the discussion 

below; and (2) a process to coordinate 

with the relevant state entities in 

developing such criteria. 

242. Subject to certain minimum 

requirements, we propose to provide 

public utility transmission providers the 

flexibility to propose the selection 

criteria that they, in consultation with 

their stakeholders, believe will ensure 

that more efficient or cost-effective 

regional transmission facilities to 

address the region’s transmission needs 

driven by changes in the resource mix 

and demand ultimately are selected in 

the regional transmission plan for 

purposes of cost allocation. As stated in 

Order No. 1000, to comply with Order 

Nos. 890 and 1000 transmission 

planning principles, the evaluation 

process must result in a determination 

that is sufficiently detailed for 

stakeholders to understand why a 

particular transmission project was 

selected or not selected in the regional 

transmission plan for purposes of cost 

allocation to address transmission needs 

driven by changes in the resource mix 

and demand.389 Further, we propose 

that the evaluation process and, 

specifically, the selection criteria must 

seek to maximize benefits to consumers 

over time without over-building 

transmission facilities. 

243. We believe that this proposed 

flexibility would help accommodate the 

regional differences described in 

comments in response to the ANOPR, 

such as the different transmission needs 

each transmission planning region may 

have, the factors driving those needs, or 

market structures. We also believe that 

providing flexibility to public utility 

transmission providers in this regard 

would allow public utility transmission 

providers, in consultation with their 

stakeholders, to determine criteria for 

assessing the efficiency or costeffectiveness of various regional 

transmission facilities, whether by 

reference, for example, to a benefit-cost 

ratio or by aggregate net benefits.390

244. Further, we believe this proposed 

flexibility would allow public utility 

transmission providers in each 

transmission planning region to develop 

selection criteria that could sufficiently 

balance individual state interests within 

each transmission planning region. We 

believe that providing an opportunity 

for state involvement in regional 

transmission planning processes is 

becoming more important as states take 

a more active role in shaping the 

resource mix and demand, which, in 

turn, means that those state actions are 

increasingly affecting the long-term 

transmission needs for which we are 

proposing to require public utility 

transmission providers to plan in this 

NOPR. Given the important role states 

play and the wide variety of potential 

approaches to selection criteria, we 

propose, as part of this requirement, that 

public utility transmission providers 

must consult with and seek support 

from the relevant state entities, as 

defined below, within their 


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391Supra Need For Reform: The Transmission 

Investment Landscape Today (explaining in some 

transmission planning regions, regional 

transmission investment declined after issuance of 

Order No. 1000, while in other regions, regional 

transmission planning processes have not resulted 

in the selection of a single regional transmission 

facility); see also Minnesota Commerce Comments 

at 3 (arguing the risk of status quo is worse than 

the risk of over-building). 

392See, e.g., NASUCA Comments at 3–5; 

November 2021 Technical Conference Tr. at 29 

(testimony of Dr. Patton). 

393For example, if public utility transmission 

providers in a transmission planning region 

propose to use existing selection criteria, they 

should explain on compliance how those criteria 

also are just and reasonable with respect to the 

selection of regional transmission facilities 

identified to address transmission needs driven by 

changes in the resource mix and demand. 

394We note that the applicable cost allocation 

method for a Long-Term Regional Transmission 

Facility may not be ex ante, as discussed in the 

Regional Transmission Cost Allocation section 

below. 

395Order No. 1000–A, 139 FERC ¶ 61,132 at P 

442. The Commission also stated that, as part of the 

ongoing monitoring of the progress of a 

transmission facility once it is selected, the public 

utility transmission providers in a transmission 

planning region must establish a date by which 

state approvals to construct must have been 

achieved that is tied to when construction must 

begin to timely meet the need that the facility is 

selected to address. If such critical steps have not 

been achieved by that date, then the public utility 

transmission providers in a transmission planning 

region may ‘‘remove the transmission facility from 

the selected category and proceed with reevaluating 

the regional transmission plan to seek an alternative 

solution.’’ Id. 

396 Infra P 302 (describing cost allocation 

requirements for Long-Term Regional Transmission 

Planning). 

transmission planning region’s footprint 

to develop the selection criteria. These 

selection criteria would be used in 

Long-Term Regional Transmission 

Planning to evaluate a transmission 

facility (or a portfolio of regional 

transmission facilities) for potential 

selection in the regional transmission 

plan for purposes of cost allocation. 

245. While we propose significant 

flexibility in the development of 

selection criteria, we believe that certain 

minimum requirements must be in 

place for public utility transmission 

providers, their stakeholders, and states. 

The selection criteria must be 

transparent and not unduly 

discriminatory, and must aim to ensure 

that more efficient or cost-effective 

transmission facilities are selected in 

the regional transmission plan for 

purposes of cost allocation to address 

transmission needs driven by changes in 

the resource mix and demand. Public 

utility transmission providers should 

seek to maximize benefits to consumers 

over time without over-building 

transmission facilities. Public utility 

transmission providers should propose 

specific selection criteria to achieve this 

balance over time. We note, as 

discussed above, that regional 

transmission planning and cost 

allocation processes generally have 

resulted in few regionally planned 

transmission facilities being selected 

and ultimately built.391 However, the 

reforms proposed in this NOPR seek to 

better ensure that the more efficient or 

cost-effective regional transmission 

facilities are identified through LongTerm Regional Transmission Planning 

and acknowledge commenters’ concerns 

about over-building due to uncertainties 

of future transmission system 

conditions.392 We acknowledge the 

inherent uncertainty involved in 

predicting future transmission needs 

and emphasize that we are not 

proposing to require public utility 

transmission providers to achieve, ex 

post, any particular outcome but rather 

to adopt an evaluation process that, ex 

ante, aims to maximize consumer 

benefits over time without over-building 

transmission facilities. 

246. Public utility transmission 

providers would bear the burden on 

compliance of demonstrating that their 

proposed selection criteria satisfy the 

Order Nos. 890 and 1000 transmission 

planning principles in the context of 

Long-Term Regional Transmission 

Planning, even if public utility 

transmission providers propose to use 

selection criteria that they also use in 

their existing regional transmission 

planning process.393 Likewise, public 

utility transmission providers would 

bear the burden on compliance of 

demonstrating that their proposed 

selection criteria seek to maximize 

benefits to consumers over time without 

over-building transmission facilities. 

Moreover, we propose to require that 

public utility transmission providers 

demonstrate on compliance that they 

developed their proposed selection 

criteria in consultation with the relevant 

state entities in their transmission 

planning region’s footprint. 

247. We propose that, consistent with 

Order No. 1000, the developer of a 

transmission facility selected in the 

regional transmission plan for purposes 

of cost allocation through Long-Term 

Regional Transmission Planning to 

address transmission needs driven by 

changes in the resource mix and 

demand would be eligible to use the 

applicable cost allocation method for 

the Long-Term Regional Transmission 

Facility.394 We also propose that the 

existing transmission developer 

requirements would apply, including 

that the developer of the selected 

regional transmission facility must 

submit a development schedule that 

indicates the required steps, such as the 

granting of state approvals necessary to 

develop and construct the transmission 

facility such that it meets the 

transmission needs of the transmission 

planning region.395 To the extent the 

relevant state entities in a transmission 

planning region agree to a State 

Agreement Process, as described in the 

Regional Transmission Cost Allocation 

section below, the development 

schedule should also include relevant 

steps related to that process.396

248. Given the longer-term nature of 

transmission needs driven by changes in 

the resource mix and demand, we note 

that the required development schedule 

may make it unnecessary for the 

developer of a transmission facility 

selected in the regional transmission 

plan for purposes of cost allocation to 

take actions or incur expenses in the 

near-term if the transmission facility 

will not need to be in service in the 

near-term. We also note that, with 

respect to a transmission facility 

selected in the regional transmission 

plan for purposes of cost allocation to 

meet transmission needs driven by 

changes in the resource mix and 

demand, public utility transmission 

providers may make its selection status 

subject to the outcomes of subsequent 

Long-Term Regional Transmission 

Planning cycles, such that a previously 

selected transmission facility is no 

longer needed. Public utility 

transmission providers should include 

in their selection criteria how they will 

address the selection status of a 

previously selected transmission facility 

based on the outcomes of subsequent 

Long-Term Regional Transmission 

Planning cycles. 

249. Consistent with our approach to 

benefits analysis, we clarify that public 

utility transmission providers would 

have the flexibility to propose to use a 

portfolio approach in selecting regional 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation that address transmission 

needs driven by changes in the resource 

mix and demand. Public utility 

transmission providers that propose 

such an approach would have to 

include in their OATTs provisions 

describing whether the selection criteria 

would apply to one proposed regional 

transmission facility or to a portfolio of 

regional transmission facilities; and 

whether the portfolio approach would 

be used for Long-Term Regional 

Transmission Planning universally to 

address transmission needs driven by 

changes in the resource mix and 


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397Brattle-Grid Strategies Oct. 2021 Report at 59– 

60. 

398As noted infra note 507, we propose to define 

a Long-Term Regional Transmission Facility as a 

transmission facility identified as part of Long-Term 

Regional Transmission Planning and selected in the 

regional transmission plan for purposes of cost 

allocation to address transmission needs driven by 

changes in the resource mix and demand. 

399For Long-Term Regional Transmission 

Facilities, such an opportunity for the relevant state 

entities could enable them to assign a value to 

achieving of their particular policy goals while 

ensuring that their customers bear the 

corresponding costs. As the New Jersey 

Commission suggests, ‘‘some states ascribe 

additional ‘value’ to the achievement of public 

policy goals, backed by a willingness to bear the 

costs associated with those benefits.’’ NJ 

Commission, Comments, Docket No. AD21–15–000, 

at 4 (filed Apr. 1, 2022). See also Maryland Energy 

Admin Comments at 8–9; Maryland Commission 

Reply Comments at 2. 

400We note that some commenters have suggested 

that interconnection customers similarly be 

afforded an opportunity to voluntarily contribute 

funds to a Long-Term Regional Transmission 

Facility so as to facilitate its selection. Enel 

Comments at 12–14; ACPA and ESA Comments at 

75–79. 

demand or would be used only in 

certain specified instances. 

250. We preliminarily find that the 

development and analysis of Long-Term 

Scenarios cannot remedy the 

deficiencies in the Commission’s 

existing regional transmission planning 

requirements without the inclusion of 

transparent and not unduly 

discriminatory selection criteria that are 

used to evaluate transmission facilities 

(or portfolios of transmission facilities) 

for potential selection in the regional 

transmission plan for purposes of cost 

allocation. Absent such criteria, public 

utility transmission providers’ 

Commission-jurisdictional rates may be 

unjust and unreasonable and unduly 

discriminatory and preferential. 

251. As noted above, we recognize the 

inherent uncertainty involved in 

predicting future transmission needs, 

including those driven by changes in 

the resource mix and demand, and 

many commenters express concern that 

imperfect information may lead to 

selecting transmission facilities in the 

regional transmission plan for purposes 

of cost allocation that become stranded 

assets. However, we believe that there 

are selection criteria that public utility 

transmission providers could adopt, 

following consultation with 

stakeholders and with relevant state 

entities in their transmission planning 

region’s footprint, to minimize these 

risks while allowing for investment in 

transmission facilities that more 

efficiently or cost-effectively meet 

transmission needs driven by changes in 

the resource mix and demand. For 

example, under a least-regrets approach, 

public utility transmission providers in 

a transmission planning region would 

select a transmission facility (or 

portfolio of transmission facilities) in 

their regional transmission plan for 

purposes of cost allocation that is netbeneficial in most or all Long-Term 

Scenarios, even if other transmission 

facilities have more net benefits or a 

higher benefit-cost ratio in a single 

Long-Term Scenario. Another approach 

is a weighted-benefits approach, in 

accordance with which public utility 

transmission providers in a 

transmission planning region would 

select a transmission facility (or 

portfolio of regional transmission 

facilities) in their regional transmission 

plan for purposes of cost allocation 

based on its probability-weighted 

average benefits, where probabilities 

have been assigned to each Long-Term 

Scenario studied.397

252. We seek comment on the 

requirements proposed in this section of 

the NOPR. In addition, we seek 

comment on whether relevant state 

entities should have the opportunity to 

voluntarily fund the cost of, or a portion 

of the cost of, a Long-Term Regional 

Transmission Facility 398 to enable such 

facility to satisfy the public utility 

transmission provider’s selection 

criteria (e.g., any benefit-cost threshold), 

and if so, whether the Commission’s 

final rule in this proceeding should 

include requirements to facilitate such 

an opportunity for the relevant state 

entities.399 Commenters on this issue 

should also address preferred 

approaches to implement such a 

voluntary funding opportunity for 

relevant state entities for Long-Term 

Regional Transmission Facilities. For 

example, we seek comment on what 

mechanism would be appropriate to 

document agreement from the relevant 

state entities to voluntarily fund (e.g., 

commit customers within the state to 

fund) the cost of, or a portion of the cost 

of, a Long-term Regional Transmission 

Facility to enable such facility to satisfy 

the public utility transmission 

provider’s selection criteria; whether a 

public utility transmission provider 

should be required to include a pro 

forma agreement for such an 

opportunity in its OATT for facilitation 

purposes; how the Commission and the 

public utility transmission providers 

would be assured that the commitment 

by the relevant state entity is 

sufficiently binding; and whether 

another manner for relevant state 

entities to make and fulfill such a 

commitment would be preferable. We 

also seek comment on what stage in the 

regional transmission planning process 

is the most appropriate point for such 

an opportunity for the relevant state 

entities. We also seek comment on 

whether such opportunity for the 

relevant state entities to voluntarily 

fund the cost of, or the portion of the 

cost of, a Long-Term Regional 

Transmission Facility should be limited 

to relevant state entities or should be 

expanded to include interconnection 

customers.400

c. Implementation of Long-Term 

Regional Transmission Planning 

253. We recognize that the timing of 

the proposed Long-Term Regional 

Transmission Planning requirement has 

the potential to overlap with public 

utility transmission providers’ near-term 

assessment of transmission needs 

captured by existing regional 

transmission planning processes. We 

propose that public utility transmission 

providers must explain on compliance 

how the initial timing sequence for 

Long-Term Regional Transmission 

Planning interacts with existing regional 

transmission planning efforts. We 

recognize the possibility that there may 

be overlap in the time horizon for the 

proposed Long-Term Regional 

Transmission Planning and existing 

near-term regional transmission 

planning processes and that they will 

likely inform each other. It is also 

possible that, in some cases, 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation to address 

transmission needs driven by changes in 

the resource mix and demand may 

provide near-term reliability or 

economic benefits and thus potentially 

displace regional transmission facilities 

that are under consideration as part of 

existing regional transmission planning 

processes. 

254. We seek comment on the 

requirement proposed in this section of 

the NOPR. In particular, we seek 

comment on whether there is a need to 

coordinate the initial timing sequences 

between Long-Term Regional 

Transmission Planning and the existing 

near-term regional transmission 

planning processes. 

255. We also seek comment on 

whether the Commission should host a 

periodic forum for public utility 

transmission providers, transmission 

experts, relevant federal and state 

agencies, and other stakeholders to 

share best practices in implementing 

Long-Term Regional Transmission 

Planning as proposed herein. The 

Commission could, for example, host a 

tri-annual technical conference focused 

on topics such as choice of best 


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401For purposes of a prior workshop, 

Commission staff stated that GETs increase the 

capacity, efficiency, or reliability of transmission 

facilities. Commission staff further stated that 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. 

Grid-Enhancing Technologies, Notice of Workshop, 

Docket No. AD19–19–000 (issued Sept. 9, 2019). 

402ANOPR, 176 FERC ¶ 61,024 at P 48. 

403 Id. P 158. 

404See, e.g., National Grid Comments at 32; PJM 

Comments at 59–62; State of Massachusetts 

Comments at 20; see also Joint Fed.-State Task 

Force on Elec. Transmission, Transcript of Nov. 10, 

2021 Meeting, Docket No. AD21–15–000, at 97:5– 

11 (Chair Scripps) (supporting consideration of 

GETs in regional transmission planning). 

405NARUC Comments at 9. 

406 Duke Comments at 13; EEI Comments at 7; 

MISO TOs Comments at 46–47. 

407AEP Comments at 15. 

408A dynamic line rating is ‘‘a transmission line 

rating that applies to a time period of not greater 

than one hour and reflects up-to-date forecasts of 

inputs such as (but not limited to) ambient air 

temperature, wind, solar heating, transmission line 

tension, or transmission line sag.’’ Managing 

Transmission Line Ratings, Order No. 881, 177 

FERC ¶ 61,179, at PP 235, 238 (2021); 18 CFR 

35.28(b)(14). 

409PJM Market Monitor Comments at 13. 

410Potomac Economics Comments at 4. 

411CAISO Comments at 113–114. 

412MISO Comments at 45–46. 

413PJM Comments at 59–60. 

414 Id. at 60. 

415SPP Comments at 12. 

416MISO Comments at 28; PJM Comments at 62– 

63. 

417PJM Comments at 60–63. 

418MISO Comments at 45–46. 

419Certain TDUs Comments at 22. 

420CTC Global Comments at 6. 

available data, principles for developing 

plausible scenarios, and techniques for 

evaluating benefits of proposed 

transmission facilities. We seek 

comment on the benefits such a forum 

might provide, and, if implemented, 

how such a forum should be structured 

and the frequency on which it should be 

held. 

2. Consideration of Dynamic Line 

Ratings and Advanced Power Flow 

Control Devices in Long-Term Regional 

Transmission Planning 

a. ANOPR 

256. In the ANOPR, the Commission 

sought comment on whether the 

development of longer-term scenarios 

for planning purposes should be 

pursued and, if so, whether and how 

Grid-Enhancing Technologies (GETs) 401

should be accounted for in determining 

what transmission is needed under such 

scenarios.402 The Commission solicited 

input on how it could require greater 

consideration of GETs and asked 

commenters to describe any challenges 

that exist in establishing such a 

requirement and how they might be 

addressed.403

b. Comments 

257. The majority of commenters on 

the ANOPR support the Commission 

requiring public utility transmission 

providers to consider GETs in the 

regional transmission planning process, 

emphasizing that advanced technologies 

can optimize existing transmission 

corridors and provide cost-effective 

solutions for consumers.404 NARUC 

states that an effective transmission 

planning process should maximize the 

use of existing transmission and build 

new transmission only where necessary 

or economic, asserting that the 

transmission planning process needs a 

clear pathway for consideration of 

alternative transmission solutions, 

including GETs.405

258. Some commenters, such as Duke, 

EEI, and MISO Transmission Owners, 

either oppose the use of GETs in 

regional transmission planning, do not 

see it as a fit for regional transmission 

planning for transmission needs driven 

by changes in the resource mix and in 

demand, or urge caution, as they assert 

that the technologies are not always 

substitutes for transmission facilities.406

AEP notes that GETs should be 

considered as long as they are evaluated 

on an equal footing, for example, 

evaluating technology life span on equal 

footing.407

259. Market monitors, such as the PJM 

Market Monitor, emphasize the value 

that dynamic line ratings 408 and other 

GETs could add in maximizing existing 

transmission capacity but express 

caution about how they would be 

implemented and compensated.409

Potomac Economics sees some benefit to 

GETs in helping transmission owners 

avoid inefficient transmission upgrade 

costs to mitigate congestion but 

expresses concern about mandating 

long-term planning studies that would 

involve RTOs/ISOs or transmission 

providers ‘‘speculating on’’ GETs.410

260. RTOs/ISOs generally indicate 

that they currently consider the use of 

GETs in the regional transmission 

planning process. CAISO supports the 

use of GETs in the regional transmission 

planning process.411 MISO indicates 

that its current regional transmission 

planning process allows for the 

consideration of GETs, but also 

indicates that these technologies alone 

will not be able to address the changing 

needs of the transmission system.412

PJM states that, as part of its regional 

transmission planning process, it 

evaluates GETs proposals, to the extent 

submitted, in a manner not materially 

different from its evaluation of other 

project proposals.413 PJM also notes that 

it conducts an advanced technology 

pilot program as a testing ground for 

new technologies that require 

integration into PJM operations and 

markets.414 Additionally, SPP states that 

it supports the use of certain GETs 

where they can be appropriately used in 

regional transmission planning. It 

contends that it has considered certain 

GETs in the regional transmission 

planning process, but notes that certain 

technologies, such as dynamic line 

ratings or topological controls, have 

historically not lent themselves readily 

to utilization in the regional 

transmission planning process.415

261. RTOs/ISOs, notably MISO and 

PJM, also discuss the importance of 

ensuring that public utility transmission 

providers understand any GETs that 

may be deployed on the system and 

their limitations, as well as 

understanding the challenges of 

integrating GETs into existing systems; 

for example, whether there is a need to 

change telemetry, modeling, other 

operating tools, and protocols, all of 

which necessitate careful 

consideration.416 PJM notes the value of 

its ongoing Advanced Technology Pilot 

Program in addressing implementation 

challenges and identifying system risks 

associated with GETs. Expressing 

concerns about the deployment of GETs 

by nonincumbent transmission 

developers, PJM recommends that the 

Commission request that the industry, 

via NERC and/or U.S. DOE, develop a 

technology application guide addressing 

where, when, and how to apply 

GETs.417 MISO states that it is important 

not to overstate the capabilities of GETs 

in the regional transmission planning 

process, as these technologies generally 

cannot substitute for long-term 

investment in transmission facilities 

that are needed to address the evolving 

resource mix, and notes the inherent 

uncertainty in forecasting power flows 

and congestion longer into the future.418

262. A few commenters set forth 

criteria that public utility transmission 

providers should be required to 

consider in the regional transmission 

planning process to promote the use of 

GETs. These include: Optimizing the 

utilization of existing and new 

transmission facilities; 419 requiring 

energy efficiency as a design criterion 

for every transmission capital 

project; 420 and requiring public utility 

transmission providers to show where 

they have incorporated GETs in their 


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421PIOs Comments at 97. 

422TAPS Comments at 2. 

423 Id. at 22. 

424PJM Comments at 63. 

425WATT Coalition Comments at 4. 

426EDF Comments at 16–18. 

427WATT Coalition Comments at 5. 

428 Id. 

429Arizona Commission Reply Comments at 12. 

430Order No. 881, 177 FERC ¶ 61,179 at P 34. 

431 Id. P 253. 

432 Id. 

433 Id. P 255. 

434 Implementation of Dynamic Line Ratings, 178 

FERC ¶ 61,110 (2022). 

435 Id. P 1. 

436 Grid-Enhancing Technologies, Notice of 

Workshop, Docket No. AD19–19–000 (issued Sept. 

9, 2019). 

437Advanced power flow control devices serve a 

transmission function. These devices can help the 

system operator control power flows over a given 

path and can include phase shifting transformers 

(also known as phase angle regulators) and devices 

or systems necessary for implementing optimal 

transmission switching. Advanced power flow 

control devices allow power to be pushed and 

pulled to alternate lines with spare capacity leading 

to maximum utilization of existing transmission 

capacity. See T. Bruce Tsuchida et al., The Brattle 

Group, Unlocking the Queue with Grid-Enhancing 

Technologies, at 19–20 (Feb. 1, 2021), https://watttransmission.org/wp-content/uploads/2021/02/ 

Brattle__Unlocking-the-Queue-with-GridEnhancing-Technologies__Final-Report_PublicVersion.pdf90.pdf. 

regional transmission planning process 

where they are cost-effective.421

263. Other commenters offer specific 

suggestions on how GETs could be 

implemented. TAPS urges the 

Commission to ‘‘[m]ake more explicit 

the mandate to consider GETs as part of 

regional planning processes,’’ arguing 

that Order No. 1000’s requirement to 

consider non-transmission alternatives 

‘‘appears insufficient to ensure robust 

consideration of GETs in the planning 

process.’’ 422 In addition, TAPS 

recommends that the Commission 

expand the MISO/PJM Targeted Market 

Efficiency Process to the regional 

transmission planning process to 

promote the use of GETs for quick fixes 

identified in the regional transmission 

planning process.423

264. PJM suggests that the 

Commission require RTOs/ISOs and 

non-RTO/ISO transmission planning 

regions to ‘‘develop a robust process to 

account for the potential for [GETs] to 

be integrated into the planning 

processes as part of both near-term and 

long-range expansion options before 

requiring that new greenfield 

transmission be built.’’ 424 Along similar 

lines, WATT Coalition suggests that for 

proposed transmission projects with an 

initial cost estimate above $10 million, 

the Commission should require the 

transmission planning region to show 

documentation of its evaluation of 

alternative solutions utilizing GETs.425

265. EDF offers a specific application 

for GETs implementation, suggesting 

that the Commission encourage and 

even require that GETs be proposed to 

address outages that have a material 

impact on market efficiency, reliability, 

and resiliency. EDF notes that 

transmission system upgrades are often 

associated with multi-month outages, 

which can have a severe impact on 

market efficiency and suggests that 

GETs be proposed in combination with 

traditional upgrades or to minimize the 

impact of outages that can result from 

the construction of transmission 

upgrades.426 WATT Coalition builds on 

this notion, suggesting that the 

Commission require transmission 

owners and planning authorities to 

propose solutions, including GETs, that 

minimize the impacts of long duration 

outages.427

266. WATT Coalition encourages the 

Commission to require the periodic 

publication of a report on grid 

utilization to show transmission usage 

data in order to provide system planners 

with a ‘‘more holistic profile of their 

system capacity, establishing a new 

dataset for targeted GETs deployment 

and associated consumer savings.’’ 428

Arizona Commission adds that an 

independent transmission monitor 

could use information collected to 

provide feedback on how public utility 

transmission providers consider 

GETs.429

c. Need for Reform 

267. Since Order No. 1000, 

commercially available technologies to 

make transmission systems operate 

more efficiently or cost-effectively have 

greatly advanced. This influx of new 

and improved technologies has the 

potential to improve the operation of 

new and existing transmission facilities 

and defer new transmission 

investments. As such, the consideration 

of new technological innovations in 

regional transmission planning 

processes could help to ensure that 

these processes are identifying more 

efficient or cost-effective regional 

transmission facilities and in turn, that 

Commission-jurisdictional rates are just 

and reasonable. 

268. When the Commission issued 

Order No. 1000, integrating these new 

technologies was not a major focus of 

the rule, partly because many new 

technologies were either still in 

development or not yet widely in use. 

After more than a decade, the 

technologies available today may help 

to ensure that the transmission system 

operates more efficiently or costeffectively. However, Order No. 1000- 

compliant regional transmission 

planning processes do not appear to 

have kept time with technology 

advancements and potentially need to 

be updated to ensure that they are 

appropriately considering these new 

technologies. 

269. Recently, in Order No. 881, 

which required more accurate 

transmission line ratings in near-term 

transmission service through the use of 

ambient-adjusted transmission line 

ratings,430 the Commission highlighted 

the benefits of dynamic line ratings, 

including permitting greater power 

flows than would otherwise be allowed, 

aiding in the detection of situations 

where power flows should be reduced 

to maintain safe and reliable operations, 

and avoiding unnecessary wear on 

transmission equipment.431 Other 

benefits of dynamic line ratings that the 

Commission emphasized in Order No. 

881 include strategic deployments and 

targeted applications in which dynamic 

line ratings can provide net benefits to 

customers by increasing the accuracy 

and power carrying capabilities of a 

line.432 While the Commission declined 

to mandate dynamic line ratings in 

Order No. 881, it required RTOs/ISOs to 

establish and maintain systems and 

procedures necessary to allow 

transmission owners to electronically 

update transmission line ratings for 

ambient-adjusted ratings, which could 

facilitate the use of dynamic line 

ratings.433 In addition, the Commission 

issued a Notice of Inquiry to continue to 

explore the implementation of dynamic 

line ratings.434 This Notice of Inquiry 

sought comment on: Whether and how 

the required use of dynamic line ratings 

is needed to ensure just and reasonable 

Commission-jurisdictional rates; 

potential criteria for dynamic line 

ratings requirements; the benefits, costs, 

and challenges of implementing 

dynamic line ratings; the nature of 

potential dynamic line ratings 

requirements; and potential timeframes 

for implementing dynamic line ratings 

requirements.435

270. At a recent workshop held by 

Commission staff,436 participants 

highlighted the benefits of advanced 

power flow control devices,437 such as 

their ability to modify a transmission 

line’s electrical characteristics to 

increase or decrease power flowing 

through the line without increasing the 

capacity of the line. Participants also 

highlighted that optimal transmission 

switching acts to completely open or 

close off routes to power flow. Finally, 

participants noted that advanced power 


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438Order No. 1000, 136 FERC ¶ 61,051 at P 328; 

Order No. 1000–A, 139 FERC ¶ 61,132 at P 267. 

439For example, while transmission topology 

optimization can serve a useful function in 

optimizing system flows and deferring transmission 

investment in the short-term, system conditions 

over 5 to 20 years in the future may be too uncertain 

to rely on system reconfiguration to address 

identified transmission needs. 

440Cf. 18 CFR 35.25(g)(13)(i) (requiring each 

RTO/ISO to maintain systems and procedures to 

accept and utilize dynamic line ratings data). 

flow control devices, including optimal 

transmission switching, provide the 

tools to effectively control and route 

power to lines that have more capacity 

than those that do not, which can 

reduce congestion, reduce costs to 

consumers, and increase reliability of 

the transmission system. 

271. To address the issues described 

above, we propose reforms to require 

public utility transmission providers to 

more fully consider two specific 

technologies—dynamic line ratings and 

advanced power flow control devices— 

in regional transmission planning 

processes. 

d. Proposed Reform 

272. In order to help ensure that 

regional transmission planning 

processes identify more efficient or costeffective transmission facilities for 

selection in the regional transmission 

plan for purposes of cost allocation, we 

propose to require that public utility 

transmission providers in each 

transmission planning region more fully 

consider in regional transmission 

planning and cost allocation processes 

two specific technologies: The 

incorporation into transmission 

facilities of dynamic line ratings and 

advanced power flow control devices. 

We believe that selecting transmission 

facilities that incorporate dynamic line 

ratings or advanced power flow control 

devices in the regional transmission 

plan for purposes of cost allocation may 

offer a more efficient or cost-effective 

alternative to other regional 

transmission facilities in certain 

instances. 

273. Specifically, we believe it is 

possible that selecting transmission 

facilities that incorporate such 

technologies serving a transmission 

function in the regional transmission 

plan for purposes of cost allocation 

could be more efficient or cost-effective 

than a proposed regional transmission 

facility that does not use such 

technologies. For example, selecting in 

the regional transmission plan for 

purposes of cost allocation a 

transmission facility that is designed 

with the equipment necessary to 

support dynamic line ratings may 

provide greater benefits through 

reduced production costs than a similar 

transmission facility that does not 

include such equipment. Likewise, 

selecting in the regional transmission 

plan for purposes of cost allocation a 

transmission facility that incorporates 

an advanced power flow control device 

may provide greater production costs 

benefits under transmission outage 

scenarios than another transmission 

facility. 

274. To facilitate greater use of these 

technologies where warranted, we 

propose to require that public utility 

transmission providers in each 

transmission planning region consider 

for each identified regional transmission 

need whether selecting transmission 

facilities in the regional transmission 

plan for purposes of cost allocation that 

incorporate dynamic line ratings or 

advanced power flow control devices 

would be more efficient or cost-effective 

than transmission facilities that do not 

incorporate these technologies. 

Specifically, such consideration should 

include first, whether incorporating 

dynamic line ratings or advanced power 

flow control devices into existing 

transmission facilities could meet the 

same regional transmission need more 

efficiently or cost-effectively than other 

potential transmission facilities. 

Second, when evaluating transmission 

facilities for potential selection in the 

regional transmission plan for purposes 

of cost allocation, the public utility 

transmission providers in the 

transmission planning region must also 

consider whether incorporating 

dynamic line ratings and advanced 

power flow control devices as part of 

any potential regional transmission 

facility would be more efficient or costeffective. We propose that this 

requirement apply in all aspects of the 

regional transmission planning 

processes, including the existing 

regional transmission planning 

processes for near-term regional 

transmission needs and Long-Term 

Regional Transmission Planning, as 

proposed in this NOPR. As is the case 

for any other transmission facility 

selected in the regional transmission 

plan for purposes of cost allocation, we 

propose that the costs to incorporate 

dynamic line ratings or advanced power 

flow control devices that are selected in 

the regional transmission plan for 

purposes of cost allocation—whether as 

an addition to an existing transmission 

facility or as part of a new regional 

transmission facility—will be allocated 

using the applicable regional cost 

allocation method. 

275. As required by Order No. 1000, 

the evaluation process must culminate 

in a determination that is sufficiently 

detailed for stakeholders to understand 

why a particular transmission facility 

was selected or not selected in the 

regional transmission plan for purposes 

of cost allocation.438 This process must 

now include the consideration of 

dynamic line ratings and advanced 

power flow control devices and why 

they were not incorporated into selected 

regional transmission facilities. 

276. As discussed above, the ANOPR 

requested comment on GETs as a larger 

category of transmission technologies. 

While we recognize that there are likely 

other novel technologies that public 

utility transmission providers could 

consider as they develop their regional 

transmission plans, we are not 

proposing to mandate their 

consideration at this time. We believe 

that there is enough operational 

experience with dynamic line ratings 

and power flow control devices such 

that public utility transmission 

providers should be able to adequately 

consider their operations in the regional 

transmission planning process. In 

addition, the nature of dynamic line 

ratings and advanced power flow 

control devices allows for consideration 

in regional transmission planning and 

cost allocation processes in a way that 

may not be possible for other 

technologies.439

277. We seek comment on the 

requirements proposed in this section of 

the NOPR. We also seek comment on 

whether there are other transmission 

technologies serving a transmission 

function that should be considered in 

regional transmission planning and cost 

allocation processes. Finally, we seek 

comment on whether non-RTO/ISO 

transmission planning regions should be 

required to update their energy 

management systems or make other 

similar changes if dynamic line ratings 

are identified as a more efficient or costeffective transmission facility selected 

in the regional transmission plan for 

purposes of cost allocation.440

V. Regional Transmission Cost 

Allocation 

278. We preliminarily find that 

reforms to public utility transmission 

providers’ regional cost allocation 

methods are necessary to ensure that 

Commission-jurisdictional rates are just 

and reasonable and not unduly 

discriminatory or preferential. As 

discussed below, we propose to require 

that public utility transmission 

providers in each transmission planning 

region seek the agreement of relevant 

state entities within the transmission 

planning region regarding the cost 

allocation method or methods that will 


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441We are not proposing to require any changes 

to existing interregional cost allocation methods for 

interregional transmission facilities that are selected 

in the regional transmission plan for purposes of 

cost allocation and that the Commission previously 

accepted as compliant with Order No. 1000. 

442Order No. 890, 118 FERC ¶ 61,119 at PP 557– 

558. 

443 Id. P 559. 

444Order No. 1000, 136 FERC ¶ 61,051 at P 497. 

445 Id. P 498. 

446 Id. P 558. 

447 Id. 

448 Id. P 10; Order No. 1000–A, 139 FERC 

¶ 61,132 at P 647. 

449Order No. 1000, 136 FERC ¶ 61,051 at PP 622, 

637, 646, 657, 668, 685. 

450 Id. P 624. 

451Order No. 1000–A, 139 FERC ¶ 61,132 at P 

680. 

452MISO, Multi-Value Project Portfolio, Detailed 

Business Case, https://cdn.misoenergy.org/ 

2011%20MVP%20Portfolio

%20Detailed%20Business%20Case117056.pdf. 

More general benefits requirements for MVP 

Projects are described at MISO, FERC Electric 

Tariff, Attachment FF, Section II.C.2, .5. 

apply to transmission facilities selected 

in the regional transmission plan for 

purposes of cost allocation through 

Long-Term Regional Transmission 

Planning and revise their OATTs to 

include the method or methods.441

279. We also propose a reform to 

facilitate an additional opportunity for 

involvement of state regulators in 

decisions about how the costs of 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation through Long-Term 

Regional Transmission Planning will be 

allocated. Specifically, this reform 

would require public utility 

transmission providers in each 

transmission planning region to add a 

time period for states to negotiate an 

alternate cost allocation method for a 

transmission facility selected in the 

regional transmission plan for purposes 

of cost allocation through Long-Term 

Regional Transmission Planning. 

A. Background 

280. In Order No. 890, the 

Commission noted that for a 

transmission planning process to 

comply with the final rule, it must 

address the allocation of costs of new 

transmission facilities. The Commission 

required public utility transmission 

providers and their stakeholders to 

develop a new cost allocation method, 

if needed, for any new transmission 

facilities that did not fall under public 

utility transmission providers’ existing 

cost allocation methods.442 The 

Commission stated that such methods 

should consider: (1) Whether a 

proposed cost allocation method fairly 

assigns costs among participants, 

including those that cause them to be 

incurred and those that otherwise 

benefit from them; (2) whether a 

proposed cost allocation method 

provides adequate incentives to 

construct new transmission; and (3) 

whether a proposed cost allocation 

method is generally supported by the 

region’s state authorities and 

participants.443

281. In Order No. 1000, the 

Commission determined that, while 

existing cost allocation methods may 

have sufficed in the past, changing 

circumstances in the industry led to the 

need for changes to cost allocation 

requirements.444 The Commission 

observed that, as transmission needs 

increased, the challenges in allocating 

the cost of transmission appeared to 

grow more acute.445 The Commission 

further found that, in ‘‘the absence of 

clear cost allocation rules for regional 

transmission facilities, there is a greater 

potential that public utility transmission 

providers and nonincumbent 

transmission developers may be unable 

to develop transmission facilities that 

are determined by the region to meet 

their needs.’’ 446 As a result, the 

Commission required each public utility 

transmission provider to have in place 

a method, or set of methods, for 

allocating the costs of new transmission 

facilities selected in the regional 

transmission plan for purposes of cost 

allocation and established a set of six 

cost allocation principles that public 

utility transmission providers’ regional 

cost allocation methods must satisfy.447

The Commission determined that this 

principles-based approach requires 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.448

282. The six regional transmission 

cost allocation principles adopted in 

Order No. 1000 are: (1) The costs of 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation must be allocated to 

those within the transmission planning 

region that benefit from those facilities 

in a manner that is at least roughly 

commensurate with estimated benefits; 

(2) those that receive no benefit from 

transmission facilities, either at present 

or in a likely future scenario, must not 

be involuntarily allocated any of the 

costs of those transmission facilities; (3) 

a benefit to cost threshold ratio, if 

adopted, cannot exceed 1.25 to 1; (4) 

costs must be allocated solely within the 

transmission planning region unless 

another entity outside the region 

voluntarily assumes a portion of those 

costs; (5) the method for determining 

benefits and identifying beneficiaries 

must be transparent; and (6) there may 

be different regional cost allocation 

methods for different types of 

transmission facilities, such as those 

needed for reliability, congestion relief, 

or to achieve Public Policy 

Requirements.449 The Commission 

declined to require that public utility 

transmission providers adopt a 

universal or comprehensive definition 

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

regional transmission facilities, instead 

permitting regional flexibility and 

examining each transmission planning 

region’s definitions on compliance.450

283. While the Commission 

determined that generator 

interconnection was outside the scope 

of Order No. 1000, it also stated that 

public utility 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 be consistent with the Order No. 

2003 generator interconnection 

process.451 No public utility 

transmission providers have proposed a 

regional cost allocation method that 

allocates costs directly to generators, 

instead allocating all costs of 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation to transmission 

customers. 

284. On compliance, public utility 

transmission providers in each 

transmission planning region adopted 

varying regional transmission cost 

allocation methods to comply with the 

cost allocation principles of Order No. 

1000. The majority of these methods 

allocate the costs of transmission 

facilities selected in a regional 

transmission plan for purposes of cost 

allocation that address reliability needs 

separately from those that address 

economic needs, and separately from 

those that address transmission needs 

driven by Public Policy Requirements. 

285. Some public utility transmission 

providers’ Order No. 1000-compliant 

regional transmission cost allocation 

methods identify benefits across a 

portfolio of transmission facilities rather 

than on a facility-by-facility basis. An 

example of a transmission planning 

region accounting for broader benefits is 

MISO, which accounts for the following 

benefits in their MVP portfolio:452

• Economic: increased market 

efficiency (congestion and fuel savings 

and operating reserves), deferred 

generation investment (system planning 


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453MISO, Multi-Value Project Portfolio, Detailed 

Business Case at 27. 

454 Id. at 17–19. 

455 Id. at 21. 

456ANOPR, 176 FERC ¶ 61,024 at P 84. 

457 Id. PP 83–89. 

458ANOPR, 176 FERC ¶ 61,024 atId. P 176. 

459ANOPR, 176 FERC ¶ 61,024 at P 176Id. (citing 

SPP, Governing Documents Tariff, Bylaws, Section 

7.2 (Regional State Committee) (1.0.0)). 

460ANOPR, 176 FERC ¶ 61,024 atId. P 177. 

461Members of the Task Force similarly 

advocated for state regulatory involvement in cost 

allocation processes, emphasizing that states are not 

merely stakeholders. See, e.g., Joint Fed.-State Task 

Force on Elec. Transmission, Transcript of Feb. 16, 

2022 Meeting, Docket No. AD21–15–000, at 

107:1–6 (Chair French), 108:17–18 (Comm’r 

Duffley), 109:2 (Chair Nelson), 110:4–5, 15–16 

(Chair Stanek), 112:3–5 (Comm’r Rechtschaffen). 

462NARUC Comments at 25; see also Ohio 

Commission Comments at 15 (noting the PJM State 

Agreement Approach and related ‘‘hard work and 

progress that has already been made in 

incorporating state policy goals into transmission 

planning in the PJM region.’’);’’); Pennsylvania 

Commission Comments at 6 (similarly calling for 

respect of the State Agreement Approach). 

463NARUC Comments at 25–26. 

464NESCOE Comments at 21–25. 

465 Id. at 49. 

466NESCOE CommentsId. at 47–48; MISO 

Comments at 8, 21. 

467Arizona Commission Comments at 7; see also 

SPP RSC Comments at 10 (urging the Commission 

to seek approaches that enhance state authority 

rather than diminishing or diluting it). 

468New Jersey Commission Comments at 12–15. 

469Mississippi Commission Comments at 14. 

470Northwest and Intermountain Comments at 

28–30. 

471ACPA and ESA Comments at 75. 

472 District of Columbia’s Office of the People’s 

Counsel Comments at 4–5. 

473 Id. at 5. 

reserve margins and transmission line 

losses), and other capital benefits (wind 

turbine investment and future 

transmission investment); 453

• Reliability: transmission line 

overloads and system voltage 

constraints mitigated, transient stability 

benefits, mitigation of fault conditions 

that could cause system instability, 

voltage stability, increased transfer 

capacity, increased transfer 

capability; 454

• Policy: reliably enables the delivery 

of energy in support of policy 

mandates.455

B. ANOPR 

286. In the ANOPR, the Commission 

recognized that reforms to regional 

transmission planning cannot be 

successful without ensuring that 

transmission providers and customers 

alike are able to identify the types of 

benefits 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.456

Acknowledging that cost allocation 

methods can be ‘‘difficult and 

controversial,’’ particularly for regional 

transmission facilities that may be both 

more costly and have potentially broad 

benefits, the Commission sought 

comment on whether there should be 

reforms to cost allocation in regional 

transmission planning and cost 

allocation processes.457

287. Additionally, the Commission 

noted that one way to add oversight to 

the regional transmission planning and 

cost allocation processes could be to 

involve state commissions in those 

processes.458 For example, the 

Commission pointed to SPP’s 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.’’ 459 The Commission 

sought 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, 

inter alia, provide insight into regional 

transmission facility costs and cost 

allocation methods.460

C. Comments 

288. In response to the ANOPR, the 

Commission received comments from a 

broad range of stakeholders, generally 

recognizing the importance of cost 

allocation to successful development of 

more efficient or cost-effective regional 

transmission facilities and advocating 

different ways to reduce the likelihood 

that controversy regarding who pays for 

regional transmission facilities obstructs 

their development and to ensure the 

costs of regional transmission facilities 

are allocated roughly commensurate 

with benefits. 

289. In their comments, many state 

regulators and groups advocate for 

increased state involvement in cost 

allocation decisions.461 NARUC 

explains that most states think that more 

should be done to encourage and incent 

states with similar public policy profiles 

to use the State Agreement Approach, 

which it says has the benefit of being a 

stakeholder-driven product that enjoys 

significant state support.462 NARUC 

further asserts that planners could 

provide a platform for states with 

similar policy objectives to better 

coordinate and agree upon cost 

allocation, while urging that regions 

should ‘‘retain the flexibility to develop 

innovative approaches to allocating the 

costs.’’ 463 NESCOE asserts that states 

need to occupy a central role in cost 

allocation, consistent with applicable 

state requirements.464 NESCOE calls for 

state decision making in the evaluation 

and selection of projects providing 

public policy benefits and for a robust 

role in the regional transmission 

planning processes.465 Some 

commenters note that they are already 

pursuing cost allocation reforms with 

transmission planning regions.466

Arizona Commission contends that, 

because state commissions are already 

tasked with ensuring retail rates are just 

and reasonable for their ratepayers, 

increased state commission involvement 

in cost allocation processes would better 

allow state commissions to establish just 

and reasonable retail rates.467 New 

Jersey Commission states that to enable 

cost allocation reforms the Commission 

could mandate public utility 

transmission providers institute a 

process for states to submit portions of 

their public policies for consideration 

into PJM’s RTEP.468 Mississippi 

Commission notes that where one or 

more states have common economic 

development, environmental, or other 

goals, and require transmission 

investment to achieve those goals, the 

cost of such projects could be allocated 

to those states in an agreed upon 

amount.469 Northwest and 

Intermountain notes that a strong state 

role is particularly important in nonRTO/ISO regions.470 ACPA and ESA 

state that a Commission approach to 

cost allocation could include cost 

contributions from states and 

interconnection customers.471

290. But while there is broad 

agreement on the importance of states’ 

role in cost allocation, a number of 

states indicate that it is difficult for 

them to participate in a timely manner 

in the regional transmission planning 

and cost allocation processes to address 

concerns regarding cost allocation.472

District of Columbia’s Office of the 

People’s Counsel calls for the 

Commission to facilitate ‘‘the 

participation of any group that may be 

subject to cost allocation in early 

planning stages to determine which 

outcome best serves the needs of all the 

customers in that region.’’ 473 Other state 

commissions also call for greater 

involvement in cost allocation 


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474Arizona Commission Comments at 7; 

Maryland Energy AdministrationAdmin Comments 

at 2. 

475Maryland Energy AdministrationAdmin 

Comments at 3. 

476Exelon Comments at 31–32. 

477ACORE Comments at ii; AEE Comments at 31– 

32; ACEG Comments at 6–8; ACPA and ESA 

Comments at 75; AEP Comments at 14; Amazon 

Comments at 4; Anbaric Comments at 29; Avangrid 

Comments at 9; Business Council for Sustainable 

Energy Comments at 2; Citizens Energy Comments 

at 6–7; City of New York Comments at 3–4; Union 

of Concerned Scientists Comments at 66–75; 

Consumers Council Comments at 4, 16; Duke 

Comments at 12; EDF Comments at 8–10; EEI 

Comments at 33; ITC Comments at 28–34; 

Massachusetts Attorney General Comments at 24– 

25; New Jersey Commission Comments at 13–14, 

17–19; NextEra Comments at 83–88; Northwest and 

Intermountain Comments at 35–38; Orsted 

Comments at 6–7; PIOs Comments at 30, 60; Policy 

Integrity Comments at 43; PSEG Comments at 25– 

27; REBA Comments at 17; RMI Comments at 4; 

SEIA Comments at 9; Shell Comments at 18–20; 

State Agencies Comments at 21–22; State of 

Massachusetts Comments at 16–17; U.S. DOE 

Comments at 7–9, 23–24; WIRES Comments at 18. 

478PIOs Comments at 30; see also Orsted 

Comments at 6. 

479U.S. DOE Comments at 23. 

480Certain TDUs Comments at 5–6. 

481NYISO Reply Comments at 10–11. 

482SPP Comments at 14. 

483CAISO Comments at 85–88; MISO Comments 

at 85. 

484PJM Comments at 8. 

485CAISO Comments at 85; MISO Comments at 

85; NYISO Comments at 35–36. 

486Minnesota Commerce Comments at 6–7 

(noting cost allocation is one of the more difficult 

barriers to new transmission development); see also 

November 2021 Technical Conference Tr. at 79. 

487See, e.g., NASUCA Comments at 6; North 

Carolina Commission Comments at 23; Ohio 

Commission Comments at 12–13; SERTP Comments 

at 4, 21–23; SoCal Edison Comments at 6. 

488See NESCOE Comments at 50. 

489Under the load-ratio share regional cost 

allocation method, the costs of new transmission 

facilities are allocated based on some measure of 

system usage, whether at peak or overall. 

Specifically, load-ratio share cost allocation 

methods include both demand charge approaches 

and volumetric (energy) approaches. Under the 

demand charge approach, costs are allocated in 

proportion to each transmission customer’s 

contribution to the system peak load (which can be 

coincident or non-coincident peak). In contrast, 

under the volumetric approach, costs are allocated 

based on each transmission customer’s share of 

total system usage. See CAISO, Review 

Transmission Access Charge Structure Issue Paper, 

at 18, tbl. 2: Summary of ISO/RTO approaches to 

transmission charges (June 30, 2017). 

490Exelon Comments at 30–31. 

491Michigan Commission Comments at 20. 

492See, e.g., EEI Comments at 32–33; NARUC 

Comments at 22; see also Joint Fed.-State Task 

Force on Elec. Transmission, Transcript of Feb. 16, 

2022 Meeting, Docket No. AD21–15–000, at 36:12– 

13 (Chair Brown Dutrieuille) (reiterating NARUC’s 

comments that the Order No. 1000 cost allocation 

principles should remain in place). 

493AEP Comments at 15. 

494See, e.g., ACEG Comments at 6–7; Consumers 

Council Comments at 16–17; WIRES Comments at 

18–19; PSEG Comments at 5. 

495APPA Comments at 15–16. 

decisions.474 Maryland Energy Admin 

asserts that earlier state involvement in 

cost allocation for the Artificial Island 

transmission facility, for example, could 

have ‘‘avoided significant delays and 

additional costs, including some that 

were ultimately assigned to 

ratepayers.’’ 475 Other commenters note 

that failure to gain state support for 

selection and cost allocation for 

transmission facilities can result in 

states subsequently blocking or delaying 

transmission facilities selected in 

regional transmission planning and cost 

allocation processes through subsequent 

state siting proceedings.476

291. Many commenters support 

consideration of a wider set of benefits 

than those currently used to evaluate 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation.477 PIOs advocate that the 

Commission conduct a survey of all 

potential benefits that can result from 

multi-value, scenario-based planning 

and require that public utility 

transmission providers consider those 

benefits for regional cost allocation as 

well as for regional transmission 

planning.478 U.S. DOE states that the 

Commission should establish a 

minimum set of potential benefits (and 

costs) to be considered, to ensure that 

they are taken into account in both 

project selection and in the allocation of 

costs for selected projects, adding this 

practice would help ensure that benefits 

not currently fully valued will be more 

appropriately incorporated in the 

planning process and foster consistency 

among planning regions.479 Certain 

TDUs express that cost allocation 

reforms must be equitable for 

consumers.480

292. Some RTOs/ISOs support the 

Commission requiring public utility 

transmission providers to consider a 

broader set of transmission benefits. For 

example, NYISO states that requiring 

public utility transmission providers to 

adopt a broader range of evaluation and 

selection criteria in their transmission 

planning processes would enable them 

to consider the reliability, economic, 

and public policy benefits of proposed 

solutions to a transmission need 

regardless of the underlying driver of 

the need, which would enhance their 

ability to select the more efficient or 

cost-effective transmission solution.481

SPP states that the Commission should 

adopt a minimum, standardized set of 

benefit metrics for all public utility 

transmission providers to ensure that 

transmission is valued consistently 

between regions and to allow for an 

apples-to-apples comparison of 

potential projects.482 CAISO and MISO 

state that the Commission could 

consider requiring public utility 

transmission providers to consider the 

resilience benefits of transmission.483 If 

the Commission expands the set of 

benefits that public utility transmission 

providers must consider, PJM urges the 

Commission to provide clear decision 

criteria on whether and when it is 

appropriate for public utility 

transmission planners to order 

construction of new transmission for 

anticipated future generation not yet in 

the interconnection queue.484 If the 

Commission requires the consideration 

of a broader set of transmission benefits, 

several RTOs/ISOs urge the Commission 

to provide for regional flexibility.485

293. Minnesota Commerce 

acknowledges that cost allocation is a 

central factor in determining whether to 

build needed regional transmission.486

Many commenters state that existing 

regional transmission cost allocation 

methods are sound and/or should 

continue.487 At least one commenter 

suggests that ultimate cost allocation 

reforms should not unintentionally 

disrupt settled methods.488

294. Some commenters suggest 

special cost allocation methods for 

transmission facilities resulting from 

scenario-based planning. Exelon asserts 

that the default cost allocation method 

for transmission projects resulting from 

scenario-based planning should reflect a 

load-ratio share method,489 but that the 

Commission should allow suitable 

substitute cost allocations as agreed to 

by the participating states to reflect the 

particular aggregation of benefits 

provided by the portfolio.490 On the 

other hand, Michigan Commission notes 

that postage stamp cost allocation is 

highly divisive.491

295. Some commenters state that 

further analysis is necessary to 

determine if prescriptive action by the 

Commission is necessary and whether 

alteration of Order No. 1000’s six 

regional transmission cost allocation 

principles is warranted.492 AEP urges 

that benefits and methodologies to 

measure those benefits should be 

consistent throughout regions.493

296. Some commenters propose cost 

allocation pursuant to benefits related to 

anticipated future generation, resilience, 

and/or climate and environmental 

benefits.494 APPA states that, to the 

extent that regions shift their 

transmission planning processes to 

place a greater emphasis on anticipated 

future generation or otherwise modify 

existing planning protocols towards a 

more holistic analysis, it may be 

appropriate to consider conforming 

changes to cost allocation methods.495


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496Order No. 1000, 136 FERC ¶ 61,051 at P 496 

(discussing findings in Order No. 890). 

497 Id. 

498See, e.g., Long Island Power Auth. v. FERC, 27 

F.4th 705, 709 (D.C. Cir. 2022) (addressing a ‘‘longrunning dispute’’ over regional transmission cost 

allocation in PJM); Pub. Serv. Elec. & Gas Co. v. 

FERC, 989 F.3d 10 (D.C. Cir. 2021) (addressing 

dispute over cost allocation for particular 

transmission upgrades). 

499See, e.g., Transource Pa., LLC v. Dutrieuille, 

Case No. 1:2021cv0110 (filed June 22, 2021, M.D. 

Pa.) (lawsuit challenging state commission’s denial 

of an application for siting and construction of 

regional transmission facilities). 

500See Order No. 1000, 136 FERC ¶ 61,051 at P 

688 (citing Order No. 890, 118 FERC ¶ 61,119 at P 

574). In 2015, the Commission accepted NYISO’s 

proposal to facilitate the timely participation of the 

New York State Public Service Commission (New 

York Commission) in review of transmission 

facilities proposed to address transmission needs 

driven by Public Policy Requirements. Under 

NYISO’s process, the New York Commission is 

provided a time period during which it may 

propose a cost allocation method or negotiate a cost 

allocation method with the developer of such a 

proposed transmission facility before the Order No. 

1000-compliant ex ante regional cost allocation 

method is applied. See NY Indep. Sys. Operator, 

Inc., 151 FERC ¶ 61,040, at PP 119–121 (2015). 

501State Voluntary Agreements to Plan and Pay 

for Transmission Facilities, 175 FERC ¶ 61,225 

(2021). 

502 Id. PP 2, 6. 

503See Joint Fed.-State Task Force on Elec. 

Transmission, 175 FERC ¶ 61,224 at PP 1–2 

(establishing the Task Force). 504 Id. P 6. 505See NARUC Comments at 27, 46–47; NESCOE 

Comments at 21–25; Arizona Commission 

Comments at 7; SPP RSC Comments at 10; 

Maryland Energy Admin Comments at 2; Joint Fed.- 

State Task Force on Elec. Transmission, Transcript 

of Feb. 16, 2022 Meeting, Docket No. AD21–15–000, 

at 102:13–24 (Chair Thomas), 110:24–111:8 

(Comm’r Allen), 111:24–112:5 (Comm’r 

Rechtschaffen), 134:4–9 (Chair Stanek) (including 

in the list of three overarching themes from the 

meeting that of state consultation—soliciting state 

input, at a minimum—on cost allocation). 

506E.g., Maryland Energy Admin Comments at 3 

(pointing to significant delays and costs associated 

with the Artificial Island transmission facility); 

Exelon Comments at 31–32 (speaking generally to 

states blocking or delaying transmission 

development through siting). 

D. Need for Reform 

297. The Commission has previously 

recognized that knowing how the costs 

of transmission facilities would be 

allocated is critical to the development 

of new transmission infrastructure.496

Without such clarity, the likelihood that 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation will be developed is 

diminished, undermining the entire 

purpose of the regional transmission 

planning process, namely, the 

development of more efficient or costeffective transmission facilities.497 Yet, 

identifying a cost allocation method that 

is perceived as fair, especially within 

transmission planning regions that 

encompass several states, remains 

challenging. Litigation contesting 

regional transmission cost allocation 

methods persists.498 Moreover, even 

where the cost allocation method is 

reasonably settled, regional 

transmission facilities face significant 

uncertainty and risk of not reaching 

construction if certain stakeholders—in 

particular, a state regulator responsible 

for permitting transmission facilities— 

do not perceive the regional 

transmission facilities’ value as 

commensurate with their costs.499

298. We are concerned that these 

challenges are likely to be exacerbated 

in the context of Long-Term Regional 

Transmission Planning and Cost 

Allocation. We recognize that, by 

requiring a longer-term planning 

horizon, consideration of multiple 

scenarios, and accounting for the longerterm factors that affect transmission 

needs, Long-Term Regional 

Transmission Planning entails a more 

complex set of considerations as 

compared to existing regional 

transmission planning requirements. We 

are concerned that this increased 

complexity could make cost allocation 

decisions more contentious, which may 

risk undermining the development of 

more efficient or cost-effective regional 

transmission facilities to address 

transmission needs driven by changes in 

the resource mix and demand. For 

example, we anticipate that 

stakeholders, including state regulators, 

may diverge in their views of which 

scenarios best reflect future 

transmission needs, and these 

conflicting perceptions may lead to 

disagreements regarding who should 

pay for selected transmission facilities. 

299. For these reasons, we 

preliminarily find that the cost 

allocation requirements for transmission 

facilities identified and selected in the 

regional transmission plan through 

Long-Term Regional Transmission 

Planning proposed in this proceeding 

may differ in part from those established 

in Order No. 1000. In particular, we 

believe that providing state regulators 

with a formal opportunity to develop a 

cost allocation method for regional 

transmission facilities selected through 

Long-Term Regional Transmission 

Planning could help increase 

stakeholder—and state—support for 

those facilities, which, in turn, may 

increase the likelihood that those 

facilities are sited and ultimately 

developed with fewer costly delays and 

better ensure just and reasonable 

Commission-jurisdictional rates. 

300. The Commission has long 

recognized the critical role of states in 

transmission planning.500 The 

Commission recently issued a Policy 

Statement addressing state efforts to 

develop transmission facilities through 

voluntary agreements to plan and pay 

for those facilities.501 In the statement, 

the Commission recognized that such 

voluntary agreements may allow stateprioritized transmission facilities to be 

planned and built more quickly than 

would comparable facilities that are 

planned through the regional 

transmission planning process, and 

encouraged elimination to barriers to 

such agreements.502 The Commission 

has also recently taken action to further 

federal-state coordination and 

cooperation in this area through the 

establishment of the Task Force.503 The 

Commission included in the list of 

topics that the Task Force may consider: 

(1) ‘‘[E]xploring potential bases for one 

or more states to use FERCjurisdictional transmission planning 

processes to advance their policy goals, 

including multi-state goals;’’ and (2) 

‘‘[e]xploring opportunities for states to 

voluntarily coordinate in order to 

identify, plan, and develop regional 

transmission solutions.’’ 504 The Task 

Force, comprised of FERC 

Commissioners and state regulators, 

discussed the role of states in regional 

transmission planning and cost 

allocation processes at two meetings 

thus far, and numerous state regulators 

and other stakeholders filed comments 

in response to the ANOPR on this topic. 

The general consensus is that involving 

state regulators when it comes to 

allocating the costs of new regional 

transmission facilities is particularly 

important given states’ role in siting 

those transmission facilities, including 

consideration of the costs and benefits 

when making state public interest 

determinations.505

301. We believe that facilitating 

involvement of state regulators in the 

cost allocation process, as further 

described below, would allow states to 

voluntarily coordinate to advance their 

policy goals through needed 

transmission development and may 

minimize delays and additional costs 

that can be associated with siting 

proceedings that follow the regional 

transmission planning and cost 

allocation processes at the federal 

level.506 We believe that providing an 

opportunity for state involvement in 

regional transmission planning cost 

allocation processes is becoming more 

important as states take a more active 

role in shaping the resource mix and 

demand, which, in turn, means that 

those state actions are increasingly 

affecting the long-term transmission 


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507We propose to define a Long-Term Regional 

Transmission Facility as a transmission facility 

identified as part of Long-Term Regional 

Transmission Planning and selected in the regional 

transmission plan for purposes of cost allocation to 

address transmission needs driven by changes in 

the resource mix and demand. 

508We propose to define a Long-Term Regional 

Transmission Cost Allocation Method as an ex ante 

regional cost allocation method that would be 

included in each public utility transmission 

provider’s OATT as part of Long-Term Regional 

Transmission Planning. The developer of a LongTerm Regional Transmission Facility would be 

entitled to use the Long-Term Regional 

Transmission Cost Allocation Method if it is the 

applicable method. 

509We propose to define a State Agreement 

Process as an ex post cost allocation process that 

would be included in each public utility 

transmission provider’s OATT as part of Long-Term 

Regional Transmission Planning, which may apply 

to an individual Long-Term Regional Transmission 

Facility or a portfolio of such Facilities grouped 

together for purposes of cost allocation. After a 

Long-Term Regional Transmission Facility is 

selected in the regional transmission plan for 

purposes of cost allocation, the State Agreement 

Process would be followed to establish a cost 

allocation method for that facility (if agreement can 

be reached). If the Commission subsequently 

approves the cost allocation method that results 

from the State Agreement Process, the developer of 

the Long-Term Regional Transmission Facility 

would be entitled to use that cost allocation method 

if it is the applicable method. 

510For example, a ‘‘combination’’ approach may 

entail (i) providing a Long-Term Regional 

Transmission Cost Allocation Method for certain 

types of Long-Term Regional Transmission 

Facilities and providing a State Agreement Process 

for others; or (ii) providing for cost allocation for 

a Long-Term Regional Transmission Facility, 

portfolio, or type of such facilities partially based 

on a Long-Term Regional Transmission Cost 

Allocation Method and partially based on funding 

contributions in accordance with a State Agreement 

Process. 

511We are not proposing to require any changes 

to existing interregional cost allocation methods for 

interregional transmission facilities that are selected 

in the regional transmission plan for purposes of 

cost allocation and that the Commission previously 

accepted as compliant with Order No. 1000. 

512For example, states in ISO–NE may consider 

NESCOE’s by-laws in defining the threshold of 

agreement among relevant state entities. Likewise, 

states in MISO may consider OMS procedures to 

define agreement and rely on existing processes by 

which OMS conveys its positions to MISO. 

513As discussed infra in Proposed Compliance 

Procedures, we propose to establish an extended 

compliance period to accommodate meaningful 

engagement with states with respect to this LongTerm Regional Transmission Planning cost 

allocation reform. 

needs for which we are proposing to 

require public utility transmission 

providers to plan in this NOPR. 

E. Proposed Reform 

1. State Involvement in Cost Allocation 

for Long-Term Regional Transmission 

Facilities 507

302. We propose to require that public 

utility transmission providers in each 

transmission planning region revise 

their OATTs to include either (1) a 

Long-Term Regional Transmission Cost 

Allocation Method 508 to allocate the 

costs of Long-Term Regional 

Transmission Facilities, or (2) a State 

Agreement Process 509 by which one or 

more relevant state entities may 

voluntarily agree to a cost allocation 

method, or (3) a combination thereof.510

We propose to require that the LongTerm Regional Transmission Cost 

Allocation Method and any cost 

allocation method resulting from the 

State Agreement Process for Long-Term 

Regional Transmission Facilities 

comply with the existing six Order No. 

1000 regional cost allocation 

principles.511

303. In order to comply with this 

proposed requirement, public utility 

transmission providers in each 

transmission planning region would be 

required to seek the agreement of 

relevant state entities within the 

transmission planning region regarding 

the Long-Term Regional Transmission 

Cost Allocation Method, State 

Agreement Process, or a combination 

thereof. We propose to require public 

utility transmission providers in each 

transmission planning region to explain 

how the proposed Long-Term 

Transmission Cost Allocation Method, 

the proposed State Agreement Process, 

or a combination thereof either: (1) 

Reflect the agreement of the relevant 

state entities, or (2) to the extent 

agreement cannot be obtained, an 

explanation of the good faith efforts by 

the relevant public utility transmission 

provider to seek agreement from such 

entities. We seek comment below on 

how to resolve the potential inability of 

the relevant parties to come to 

agreement, noting that it will ultimately 

be necessary for public utility 

transmission providers to have a cost 

allocation method on file with the 

Commission for transmission facilities 

selected through Long-Term Regional 

Transmission Planning, and recognizing 

a State Agreement Process or 

combination cost allocation method 

would not comply with this proposed 

rule unless the relevant public utility 

transmission providers has obtained 

agreement from the relevant state 

entities. 

a. Agreement of Relevant State Entities 

304. We propose to define relevant 

state entities for purposes of the LongTerm Regional Transmission Planning 

cost allocation requirements as any state 

entity responsible for utility regulation 

or siting electric transmission facilities 

within the state or portion of a state 

located in the transmission planning 

region, including any state entity as may 

be designated for that purpose by the 

law of such state. Although, as 

discussed below, we propose to provide 

public utility transmission providers 

flexibility in determining what 

constitutes state agreement, we 

preliminarily find that, for each state, a 

single entity should be designated as the 

voting or representative entity to avoid 

confusion or over-representation by a 

single state in a multi-state voting 

process. 

305. We propose to require that public 

utility transmission providers in each 

transmission planning region seek 

agreement from the relevant state 

entities regarding the approach to cost 

allocation for Long-Term Regional 

Transmission Facilities. Specifically, 

public utility transmission providers in 

each transmission planning region must 

seek to determine whether, for all or a 

subset of Long-Term Regional 

Transmission Facilities, the relevant 

state entities agree to (1) a Long-Term 

Regional Transmission Cost Allocation 

Method; (2) a State Agreement Process; 

(3) forgo a role in determining the cost 

allocation approach for Long-Term 

Regional Transmission Facilities; or (4) 

some combination thereof. 

306. We further propose to afford 

public utility transmission providers in 

each transmission planning region 

flexibility in the process by which they 

seek agreement from the relevant state 

entities. In addition, we propose to 

require public utility transmission 

providers to provide the state entities 

with flexibility with regard to defining 

what constitutes ‘‘agreement’’ among 

the relevant state entities on the cost 

allocation approach for Long-Term 

Regional Transmission Facilities. For 

example, states may choose to apply the 

existing provisions for engaging with 

the relevant state entities.512 In other 

cases, the relevant state entities may 

elect to engage in new or different ways 

to reach and communicate agreement 

regarding a cost allocation approach for 

Long-Term Regional Transmission 

Facilities.513

307. We note that the relevant state 

entities may forgo a role in determining 

the cost allocation approach for all or a 

subset of Long-Term Regional 

Transmission Facilities. In the event 

that the relevant state entities do so, we 

propose to require public utility 

transmission providers to propose a 

Long-Term Regional Transmission Cost 

Allocation Method consistent with the 

requirements of Order No. 1000, 

including the prohibition on relying on 

voluntary agreement among states or 


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514Under this proposed requirement, the LongTerm Regional Transmission Cost Allocation 

Method that public utility transmission providers 

would be required to submit would only apply to 

the subset of Long-Term Regional Transmission 

Facilities for which the relevant state entities did 

not determine a cost allocation approach. 

515 In Order No. 1000, the Commission 

determined that, in the event public utility 

transmission providers in a region fail to reach 

agreement on a cost allocation method, it would use 

the record in the compliance filing to determine the 

cost allocation method. Order No. 1000, 136 FERC 

¶ 61,051 at P 607. 

516As noted, supra, those cost principles are: (1) 

The costs of transmission facilities selected in a 

regional transmission plan for purposes of cost 

allocation must be allocated to those within the 

transmission planning region that benefit from 

those facilities in a manner that is at least roughly 

commensurate with estimated benefits; (2) those 

that receive no benefit from transmission facilities, 

either at present or in a likely future scenario, must 

not be involuntarily allocated any of the costs of 

those transmission facilities; (3) a benefit to cost 

threshold ratio, if adopted, cannot exceed 1.25 to 

1; (4) costs must be allocated solely within the 

transmission planning region unless another entity 

outside the region voluntarily assumes a portion of 

those costs; (5) the method for determining benefits 

and identifying beneficiaries must be transparent; 

and (6) there may be different regional cost 

allocation methods for different types of 

transmission facilities, such as those needed for 

reliability, congestion relief, or to achieve Public 

Policy Requirements. 

517The Commission took a similar approach with 

respect to its cost allocation reforms in Order No. 

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

565. 

participant funding.514 Relevant state 

entities may also fail to reach agreement 

on a cost allocation method for all or a 

portion of Long-Term Regional 

Transmission Facilities, and we request 

comments below on the appropriate 

outcome in that situation. 

308. We clarify that we are not 

proposing to impose any requirements 

on states to participate in processes to 

establish regional cost allocation 

methods for Long-Term Regional 

Transmission Facilities. The 

Commission has no authority over 

relevant state entities in this regard and, 

as such, those entities need not engage 

on a cost allocation approach if they do 

not wish to do so. Instead, we propose 

only to require that public utility 

transmission providers in each 

transmission planning region seek the 

agreement of the relevant state entities, 

and demonstrate in their compliance 

filings how either the proposed LongTerm Regional Transmission Cost 

Allocation Method, the proposed State 

Agreement Process, or combination 

thereof: (1) Reflects the agreement of the 

relevant state entities, or (2) to the 

extent agreement cannot be obtained, 

reflects good faith efforts by the relevant 

public utility transmission provider to 

seek agreement from such entities. 

309. We seek comment on whether 

the proposed definition of relevant state 

entities is appropriate. We also seek 

comment on the proposal to afford 

relevant states entities the flexibility to 

define agreement among relevant state 

entities, or whether it is preferable for 

the Commission to adopt a specific 

definition of such agreement. 

310. We further recognize that it is 

possible that relevant states entities may 

seek to agree to a cost allocation 

approach but be unable to achieve 

agreement, or may be unwilling to seek 

agreement to a cost allocation approach 

but do not agree to forgo their role in 

developing a cost allocation approach 

for Long-Term Regional Transmission 

Facilities. We request comment on the 

appropriate outcome when the relevant 

state entities fail to agree on a cost 

allocation method for all or a portion of 

Long-Term Regional Transmission 

Facilities. Specifically, we request 

comment on whether in such 

circumstances the public utility 

transmission providers should be 

required to establish a Long-Term 

Regional Transmission Cost Allocation 

Method, the relevant state entities 

should be afforded additional time to 

endeavor to reach agreement, or the 

Commission should instead have the 

responsibility to establish the LongTerm Regional Transmission Cost 

Allocation Method.515

b. State Agreement Process 

311. We preliminarily find that a State 

Agreement Process by which one or 

more relevant state entities voluntarily 

agree to a cost allocation method for 

Long-Term Regional Transmission 

Facilities (or portfolio of facilities) after 

it is selected in the regional 

transmission plan for purposes of cost 

allocation may be a just and reasonable 

approach to cost allocation for such 

regional transmission facilities. The 

State Agreement Process may apply to 

all Long-Term Regional Transmission 

Facilities or only a subset thereof. 

312. We further propose to require 

that a cost allocation method that results 

from the State Agreement Process and is 

filed by the public utility transmission 

providers must comply with the existing 

six Order No. 1000 regional cost 

allocation principles.516 We 

preliminarily find that compliance with 

such principles will help to ensure that 

Commission-jurisdictional rates 

resulting from any State Agreement 

Process will be just and reasonable and 

not unduly discriminatory or 

preferential. 

313. If the relevant state entities 

decide on a State Agreement Process, 

we also propose to require that the 

public utility transmission providers in 

each transmission planning region 

detail the process by which the relevant 

state entities would reach voluntary 

agreement regarding the cost allocation 

for Long-Term Regional Transmission 

Facilities pursuant to the State 

Agreement Process, including the 

timeline for such processes. For 

example, the public utility transmission 

providers in each transmission planning 

region could specify, as part of the 

Long-Term Regional Transmission 

Planning in their OATTs the procedures 

by which such voluntary agreements by 

the relevant state entities may be filed 

with the Commission for consideration 

under FPA section 205. Such 

procedures should set forth a process by 

which the relevant state entities would 

agree to funding contributions and the 

mechanism by which such costs would 

be allocated (e.g., through a pro forma 

contract). 

314. Finally, we note that, to the 

extent public utility transmission 

providers believe their existing cost 

allocation approaches comply with the 

requirements adopted in any final rule 

in this proceeding, including those 

related to the agreement of relevant state 

entities, we propose that they may make 

such demonstration in their compliance 

filings in response to any final rule. In 

addition, we propose to apply the cost 

allocation reforms we propose in this 

NOPR only to new Long-Term Regional 

Transmission Facilities and, therefore, 

these proposed reforms would not 

provide grounds for re-litigation of cost 

allocation decisions for transmission 

facilities that are selected in the regional 

transmission plan for purposes of cost 

allocation prior to the effective date of 

any final rule in this proceeding,517 nor 

would they apply to the cost allocation 

methods associated with regional 

transmission facilities that address 

shorter-term transmission needs driven 

by reliability and/or economic 

considerations. We believe the proposed 

cost allocation requirements for LongTerm Regional Transmission Facilities 

will help to ensure just and reasonable 

Commission-jurisdictional rates by 

increasing the likelihood that more 

efficient or cost-effective regional 

transmission facilities to address 

transmission needs driven by changes in 

the resource mix and demand are 

developed, and with fewer delays. The 

proposed reforms would enable relevant 

state entities, such as state regulators 

and siting authorities, who seek greater 

involvement in cost allocation for LongTerm Regional Transmission Facilities 

an opportunity to do so. Where relevant 

state entities in a multi-state 


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518 Id. P 499; Order No. 1000–A, 139 FERC 

¶ 61,132 at P 52. 

519Order No. 1000, 136 FERC ¶ 61,051 at P 723. 

Under a participant funding approach to cost 

allocation, the costs of a transmission facility are 

allocated only to those entities that volunteer to 

bear those costs. Id. P 486 n.375. 

520 Id. P 586 (stating regional cost allocation 

principles, including ‘‘[t]hose that receive no 

benefit from transmission facilities, either at present 

or in a likely future scenario, must not be 

involuntarily allocated the costs of those 

facilities.’’). 

transmission planning region are able to 

agree upon an approach to allocate the 

costs of Long-Term Regional 

Transmission Facilities needed to meet 

these longer-term transmission needs, 

applying that approach is likely to 

decrease the controversy over 

development of such facilities, by, for 

example, making the relevant state 

entities more confident that ratepayers 

in the state are receiving benefits at least 

roughly commensurate with their share 

of the cost of such facilities. In so doing, 

the engagement of relevant state entities 

may help to reduce instances in which 

a Long-Term Regional Transmission 

Facility is selected, has an established 

ex ante cost allocation method that 

applies to it, but nevertheless fails to be 

developed because it cannot receive a 

necessary state regulatory approval. 

After all, states retain siting authority 

over transmission facilities and will 

review whether Long-Term Regional 

Transmission Facilities are consistent 

with the public interest and state siting 

regulations. 

315. We recognize that, if states agree 

to a State Agreement Process instead of 

a Long-Term Regional Transmission 

Cost Allocation Method, certain LongTerm Regional Transmission Facilities 

selected in the regional transmission 

plan for purposes of cost allocation 

would lack a clear ex ante cost 

allocation method. We continue to 

believe that the availability of an ex ante 

cost allocation method helps to ensure 

the development of more efficient or 

cost-effective regional transmission 

facilities identified in the regional 

transmission planning process.518

However, given the increased 

uncertainty of Long-Term Regional 

Transmission Planning and potential for 

divergent views on the benefits of 

meeting transmission needs driven by 

changes in the resource mix and 

demand, we believe that applying a cost 

allocation approach agreed to by the 

relevant state entities may be just and 

reasonable and support the viability of 

Long-Term Regional Transmission 

Facilities. 

316. We recognize that in Order No. 

1000, the Commission explained that 

reliance on participant funding as a 

regional cost allocation method 

‘‘increases the incentive of any 

individual beneficiary to defer 

investment in the hopes that other 

beneficiaries will value a transmission 

project enough to fund its development’’ 

and would therefore not comply with 

the regional cost allocation principles 

adopted in Order No. 1000.519

317. Nevertheless, we preliminarily 

find that allowing a State Agreement 

Process for Long-Term Regional 

Transmission Facilities, where agreed to 

by the relevant state entities, 

appropriately balances the concerns 

about increased free ridership problems 

against the benefit of greater state 

involvement in determining the cost 

allocation of Long-Term Regional 

Transmission Facilities.520 As discussed 

above, we are proposing to require 

public utility transmission providers to 

engage in transmission planning over a 

longer time-horizon than we have 

previously required. Although we 

preliminarily find that such reforms are 

necessary to ensure just and reasonable 

rates, we recognize that the precise 

quantification and allocation of the 

benefits of Long-Term Regional 

Transmission Facilities may be more 

uncertain than transmission facilities 

that are planned on a shorter-term basis 

and/or based on a more limited set of 

benefits. As such, we recognize that 

state entities charged with siting 

transmission facilities within their state 

may, at least in certain circumstances, 

take a more skeptical approach to 

evaluating applications to site LongTerm Regional Transmission Facilities. 

We believe that providing relevant state 

entities an opportunity for involvement 

in establishing a cost allocation method, 

including through use of a State 

Agreement Process, would help to 

address any such concerns on the part 

of state regulators, increasing the 

likelihood that Long-Term Regional 

Transmission Facilities are actually 

developed, and without delay. 

Accordingly, we preliminarily find that 

this potential benefit outweighs 

concerns about free-ridership with 

respect to the reforms proposed herein. 

318. We seek comment on the 

requirements proposed in this section of 

the NOPR. We also seek comment on 

whether the Commission should 

require, instead of the reforms proposed 

in this section of the NOPR, public 

utility transmission providers to include 

a Long-Term Regional Transmission 

Cost Allocation Method in their OATTs. 

2. Time Period in Long-Term Regional 

Transmission Planning Cost Allocation 

Processes for State-Negotiated Alternate 

Cost Allocation Method 

319. Additionally, we propose to 

require that public utility transmission 

providers establish a process, detailed 

in their OATTs, to provide a state or 

states (in multi-state transmission 

planning regions) a time period to 

negotiate a cost allocation method for a 

transmission facility (or portfolio of 

facilities) selected for purposes of cost 

allocation through Long-Term Regional 

Transmission Planning that is different 

than any ex ante regional cost allocation 

method that would otherwise apply. 

During this time period for a statenegotiated alternate cost allocation 

method, if a state or all states within the 

transmission planning region in which 

the selected regional transmission 

facility will be located unanimously 

agree on an alternate cost allocation 

method, the public utility transmission 

provider may elect to file it with the 

Commission for consideration under 

FPA section 205. As discussed above, 

we anticipate the public utility 

transmission provider may elect to file 

an alternate cost allocation method 

because doing so increases the 

likelihood that relevant stakeholders 

perceive the cost allocation as fair and 

that the needed regional transmission 

facilities are actually constructed. 

320. If the relevant state or states 

cannot agree on an alternate cost 

allocation method memorialized in 

writing within a specified timeframe 

after a transmission facility is selected 

in the regional transmission plan for 

purposes of cost allocation through 

Long-Term Regional Transmission 

Planning (e.g., 90 days), then the 

transmission developer will be entitled 

to use any ex ante regional cost 

allocation method that would otherwise 

apply for that regional transmission 

facility. 

321. Providing states with a time 

period to propose alternate cost 

allocation methods could help facilitate 

the timely development of more 

efficient or cost-effective regional 

transmission facilities. For example, 

allowing states to negotiate an alternate 

cost allocation method for selected 

regional transmission facilities at a time 

when details of the transmission 

facilities are known could facilitate 

agreements on the cost allocation for 

new regional transmission facilities 

because states would have better 

knowledge of relevant facts, including 

benefits and costs, regarding the 

transmission facilities for which they 

are negotiating cost allocation. 


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521Public Law 109–58, 1241, 119 Stat. 594 (2005). 

522Promoting Transmission Inv. 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). 

523 Id. P 9. 

524The Commission has also provided that any 

public utility engaged in the sale of electric power 

for resale can file to include in rate base up to 50% 

of CWIP, subject to limitations. Construction Work 

in Progress for Public Utilities; Inclusion of Costs in 

Rate Base, Order No. 298, FERC Stats. & Regs. 

¶ 30,455 (1983), order on reh’g, 25 FERC ¶ 61,023 

(1983). 

525Order No. 679, 116 FERC ¶ 61,057 at n.70. 

Moreover, state siting proceedings may 

proceed more efficiently if states have 

better information about the costs and 

benefits of such regional transmission 

facilities. 

322. We propose to require that public 

utility transmission providers add to 

their OATTs provisions that describe a 

time period for state involvement in 

regional cost allocation for transmission 

facilities selected in Long-Term 

Regional Transmission Planning, 

including when this time period will 

occur, what its duration will be, and 

that any alternate cost allocation 

method must be submitted to the 

Commission for review and approval 

under FPA section 205 prior to taking 

effect. When filed, the Commission will 

evaluate the alternate cost allocation 

method to ensure that it is just and 

reasonable and allocates costs in a 

manner that is at least roughly 

commensurate with estimated benefits. 

If the Commission rejects a stateproposed cost allocation method, the 

transmission developer of the 

transmission facility selected in the 

regional transmission plan for purposes 

of cost allocation through Long-Term 

Regional Transmission Planning would 

be entitled to use the applicable ex ante 

regional cost allocation method that 

would have applied to it in the absence 

of the proposed alternative cost 

allocation method, just as it would be 

absent this proposed provision for an 

alternate cost allocation method. 

323. We recognize the tension 

between a proposal for a time period for 

state-negotiated cost allocation within 

an Order No. 1000-compliant regional 

transmission planning process and the 

Commission’s ex ante cost allocation 

approach, which we do not propose to 

remove, including the potential for 

delay as compared to the ex ante 

approach. We propose to prescribe a 90- 

day time period for state-negotiated cost 

allocation memorialized in writing, 

which is consistent with the period for 

state cost allocation negotiation that the 

Commission accepted in NYISO’s filing 

described above. 

324. We seek comment on the 

requirements proposed in this section of 

the NOPR, including the timing and 

duration of any time period for statenegotiated cost allocation for 

transmission facilities selected in the 

regional transmission plan for purposes 

of cost allocation through Long-Term 

Regional Transmission Planning. We 

also seek comment on whether there 

should be a requirement for a time 

period for state involvement in regional 

cost allocation for transmission facilities 

selected in existing near-term reliability 

and economic regional transmission 

planning processes. 

3. Identification of Benefits Considered 

in Cost Allocation for Long-Term 

Regional Transmission Facilities 

325. We are concerned that the 

Commission’s existing regional 

transmission planning and cost 

allocation requirements may result in 

public utility transmission providers 

undervaluing the benefits of Long-Term 

Regional Transmission Facilities for 

purposes of allocating the costs of such 

facilities to beneficiaries in a manner 

that is roughly commensurate with 

estimated benefits. The current 

approach of considering only a subset of 

categories of benefits based on the type 

of transmission need that is being 

studied may result in inaccurate 

valuation of a transmission facility’s 

benefits in Long-Term Regional 

Transmission Planning. We are also 

concerned that considering only a 

subset of benefits in assigning the cost 

of Long-Term Regional Transmission 

Facilities may contribute to the risk of 

free rider problems that impede 

development of the more efficient or 

cost-effective regional transmission 

facilities. At the same time, as discussed 

above, we consider it important that 

cost allocation should reflect the views 

of stakeholders, and the state entities 

with a role in permitting transmission 

facilities in particular, and believe that 

the involvement of states in cost 

allocation increases the likelihood that 

Long-Term Regional Transmission 

Facilities are actually developed. 

326. Nevertheless, we acknowledge 

the support for the adoption of a 

common set of minimum benefits, and 

we propose for consideration a list of 

Long-Term Regional Transmission 

Benefits described above for public 

utility transmission providers to apply 

in Long-Term Regional Transmission 

Planning and Cost Allocation processes. 

In addition, we propose to require that 

public utility transmission providers 

identify on compliance the benefits they 

will use in any ex ante cost allocation 

method associated with Long-Term 

Regional Transmission Planning, how 

they will calculate those benefits, and 

how the benefits will reasonably reflect 

the benefits of regional transmission 

facilities to meet identified transmission 

needs driven by changes in the resource 

mix and demand. As part of this 

compliance obligation, public utility 

transmission providers should explain 

the rationale for using the benefits 

identified. 

327. We request comment on this 

proposed requirement. We also request 

comment on whether the Commission 

should require that public utility 

transmission providers account for the 

full list of benefits described in the 

Evaluation of the Benefits of Regional 

Transmission Facilities section above in 

Long-Term Regional Transmission 

Planning, or whether no change to the 

benefits currently used in existing 

regional transmission planning 

processes is needed. 

VI. Construction Work in Progress 

Incentive 

A. Background 

328. In the Energy Policy Act of 

2005,521 Congress added section 219 to 

the FPA, directing the Commission to 

establish, by rule, incentive-based rate 

treatments to promote capital 

investment in certain transmission 

infrastructure. The Commission 

subsequently issued Order No. 679 in 

2006, which sets forth processes by 

which a public utility may seek 

transmission rate incentives pursuant to 

FPA section 219.522

329. In Order No. 679, the 

Commission adopted several incentivebased rate treatments to promote capital 

investment in certain transmission 

infrastructure and to address 

impediments faced by those investing in 

transmission. The Commission found 

that the long-lead time to construct new 

transmission and associated cash flow 

difficulties presented an impediment to 

new transmission investment.523 To 

remove this impediment, the 

Commission adopted its proposal to 

allow for the recovery of 100% of CWIP 

costs in rate base in certain 

circumstances (CWIP Incentive).524

Allowing transmission developers to 

include construction costs in rate base 

prior to commercial operation provides 

utilities with additional cash flow in the 

form of an immediate earned return, 

rather than delaying recovery of those 

costs until the plant is placed into 

service.525 In Order No. 679, the 

Commission acknowledged that the 

CWIP Incentive was a departure from 

the existing ratemaking doctrine that 

rates should be based on plant costs that 


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526 Id. PP 116–117. 

527 Id. P 117 (quoting Jersey Cent. Power & Light 

Co. v. FERC, 810 F.2d 1168, 1178 (D.C. Cir. 1987)). 

528See, e.g., NextEra Energy Transmission Sw., 

LLC, 178 FERC ¶ 61,082 (2022) (Christie, Comm’r, 

concurring). 

529Order No. 679, 116 FERC ¶ 61,057 at P 115. 

530We further note that our proposal regarding 

the CWIP Incentive for Long-Term Regional 

Transmission Facilities does not affect Commission 

policy and regulations established before Order No. 

679. That is, public utility transmission providers 

would still be allowed to request 50% CWIP in rate 

base, as is permitted pursuant to 18 CFR 35.25(c)(3), 

subject to an FPA section 205 filing detailing how 

the request meets the requirements of Order No. 

298. We believe that the ability to include 50% 

CWIP in rate base, if requested and granted, reflects 

a more reasonable sharing of risks and benefits than 

the CWIP Incentive for Long-Term Regional 

Transmission Facilities given the greater 

uncertainty inherent in Long-Term Regional 

Transmission Planning, as proposed in this NOPR. 

531See ISO New Eng. Inc., 169 FERC ¶ 61,054, at 

PP 1–2 (2019) (citations omitted); see also Order No. 

1000, 136 FERC ¶ 61,051 at PP 225–344. 

532Order No. 1000, 136 FERC ¶ 61,051 at P 225. 

are ‘‘used and useful.’’ 526 However, the 

Commission clarified that ‘‘the 

Commission can depart from the norm 

as long as it reasonably balances 

consumers’ interest in fair rates against 

investors’ interest in maintaining 

financial integrity and access to capital 

markets.’’ 527

B. Need for Reform 

330. As indicated above in this NOPR, 

under the proposed Long-Term Regional 

Transmission Planning reforms, we seek 

to strike a balance between the risk of 

over- and under-investment regarding 

the selection of transmission facilities in 

the regional transmission plan for 

purposes of cost allocation that address 

transmission needs driven by changes in 

the resource mix and demand. We 

acknowledge that there is likely to be 

more uncertainty in Long-Term 

Regional Transmission Planning, e.g., 

requiring public utility transmission 

providers to conduct Long-Term 

Regional Transmission Planning over a 

minimum of 20 years (compared to the 

current practice of 6–15 years), than in 

the existing regional transmission 

planning processes. 

331. In light of the incremental 

uncertainty associated with the 

proposed Long-Term Regional 

Transmission Planning, we 

preliminarily find that additional 

protection for ratepayers may be 

necessary to reasonably balance 

consumers’ interest in just and 

reasonable rates against investors’ 

interest in earning a return on their 

investments and reduce the risk to 

ratepayers of potentially financing overinvestment in regional transmission 

facilities.528 The Commission 

previously found that the CWIP 

Incentive is beneficial to ease the 

financial pressures associated with 

transmission development by providing 

up-front regulatory certainty, rate 

stability, and improved cash flow, 

which in turn can result in higher credit 

ratings and lower capital costs.529 These 

benefits mainly accrue to the public 

utility transmission providers and their 

shareholders during construction, while 

ratepayers mainly receive the benefits 

from completed transmission facilities 

under a more stable rate environment. 

Specifically, during the construction of 

the regional transmission facilities, 

ratepayers do not receive benefits from 

the regional transmission facilities, 

while simultaneously ratepayers 

directly finance the construction under 

the CWIP Incentive. Should the regional 

transmission facilities not be placed in 

service, then ratepayers will have 

financed the construction of such 

facilities that were not used and useful, 

while ultimately receiving no benefits 

from such facilities. 

332. Given the Long-Term Regional 

Transmission Planning reforms 

proposed in this NOPR and the 

incremental uncertainty and risk that 

Long-Term Regional Transmission 

Facilities may not become ‘‘used and 

useful,’’ we are concerned that the CWIP 

Incentive, if made available for LongTerm Regional Transmission Facilities, 

may shift too much risk to consumers to 

the benefit of public utility transmission 

providers in a manner that renders 

Commission-jurisdictional rates unjust 

and unreasonable. 

C. Proposed Reform 

333. To address the concerns 

identified above, we propose to not 

permit public utility transmission 

providers to take advantage of the CWIP 

Incentive for Long-Term Regional 

Transmission Facilities. We note that 

public utility transmission providers 

may still book costs incurred during the 

pre-construction or construction phase 

as Allowance for Funds Used During 

Construction (AFUDC) and only recover 

those costs after the project is in service 

to customers, in accordance with 

generally accepted utility accounting 

principles for AFUDC.530

334. We seek comment on the 

requirements proposed in this section of 

the NOPR. In particular, we seek 

comment on whether this proposed 

reform would reasonably balance 

consumer and investor interests. 

VII. Exercise of a Federal Right of First 

Refusal in Commission-Jurisdictional 

Tariffs and Agreements 

335. Order No. 1000 instituted a 

number of reforms regarding the 

participation of nonincumbent 

transmission developers in the regional 

transmission planning process, which, 

as a whole, facilitate competition for 

transmission development.531 As 

explained in more detail below, we 

continue to require compliance with 

Order No. 1000’s nonincumbent 

transmission developer reforms, and we 

maintain our commitment to 

transmission development rules and 

policies that align with or advance the 

goals of those reforms, or otherwise 

ensure just and reasonable Commissionjurisdictional rates and limit 

opportunities for undue discrimination 

by public utility transmission providers. 

336. However, in light of the 

experience gained since the issuance of 

Order No. 1000 and the comments 

received in response to the ANOPR, we 

propose to amend Order No. 1000’s 

nonincumbent transmission developer 

requirements, in part. As described in 

more detail below, we propose to permit 

the exercise of federal rights of first 

refusal for transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation, 

conditioned on the incumbent 

transmission provider with the federal 

right of first refusal for such regional 

transmission facilities establishing joint 

ownership of the transmission facilities 

consistent with the proposal below. 

A. Background 

1. Order No. 1000’s Nonincumbent 

Transmission Developer Reforms and 

Federal Right of First Refusal 

Elimination Mandate 

337. In instituting nonincumbent 

transmission developer reforms, the 

Commission in Order No. 1000 

distinguished between incumbent 

transmission developers (also called 

incumbent transmission providers) and 

nonincumbent transmission developers. 

An incumbent transmission developer/ 

provider is an entity that develops a 

transmission facility within its own 

retail distribution service territory or 

footprint. A nonincumbent transmission 

developer refers to two categories of 

transmission developer: (1) A 

transmission developer that does not 

have a retail distribution service 

territory or footprint; and (2) a public 

utility transmission provider that 

proposes a transmission facility outside 

of its existing retail distribution service 

territory or footprint, where it is not the 

incumbent for purposes of that 

facility.532

338. Among its nonincumbent 

transmission developer reforms, Order 

No. 1000 requires that each public 


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533 Id. P 313; Order No. 1000–A, 139 FERC 

¶ 61,132 at P 426 (‘‘The concept is that there should 

not be a federally established monopoly over the 

development of an entirely new transmission 

facility that is selected in a regional transmission 

plan for purposes of cost allocation to others.’’). The 

phrase ‘‘a federal right of first refusal’’ refers only 

to rights of first refusal that are created by 

provisions in Commission-jurisdictional tariffs or 

agreements. Order No. 1000–A, 139 FERC ¶ 61,132 

at P 415. Before Order No. 1000, some RTO/ISO 

governing documents and other utility tariffs and 

agreements included federal rights of first refusal, 

which ‘‘gave incumbent utilities the option to 

construct any new transmission facilities in their 

particular service areas, even if the proposal for 

new construction came from a third party.’’ S.C. 

Pub. Serv. Auth., 762 F.3d at 72. 

534Order No. 1000, 136 FERC ¶ 61,051 at PP 63, 

226, 258, 318. In addition, the Commission clarified 

in Order No. 1000–A that a transmission facility 

whose costs are 100% allocated to the public utility 

transmission provider in whose retail distribution 

service territory or footprint the facility is located 

is not considered to be selected in the regional 

transmission plan for purposes of cost allocation 

and could remain subject to a federal right of first 

refusal. Order No. 1000–A, 139 FERC ¶ 61,132 at PP 

423–424; see also id. P 427. 

535Order No. 1000, 136 FERC ¶ 61,051 at PP 226, 

319; Order No. 1000–A, 139 FERC ¶ 61,132 at P 426. 

Upgrades to existing transmission facilities include, 

for example, tower change outs or reconductoring, 

regardless of whether or not an upgrade has been 

selected in the regional transmission plan for 

purposes of cost allocation. Order No. 1000, 136 

FERC ¶ 61,051 at P 319. The Commission clarified 

in Order No. 1000–A that the term ‘‘upgrade’’ 

means an improvement to, addition to, or 

replacement of a part of, an existing transmission 

facility. The term does not refer to an entirely new 

transmission facility. Order No. 1000–A, 139 FERC 

¶ 61,132 at P 426. 

536Order No. 1000, 136 FERC ¶ 61,051 at PP 226, 

319. 

537See, e.g., PJM Interconnection, L.L.C., 174 

FERC ¶ 61,117, at P 3 (2021); Sw. Power Pool, Inc., 

171 FERC ¶ 61,213, at P 3 (2020); Midcontinent 

Indep. Sys. Operator, Inc., 173 FERC ¶ 61,203, at P 

1 (2020); ISO New Eng. Inc., 171 FERC ¶ 61,211, at 

P 1, 3 (2020); N.Y. Indep. Sys. Operator, Inc., 171 

FERC ¶ 61,082, at PP 30–34 (2020). 

538Order No. 1000, 136 FERC ¶ 61,051 at PP 229, 

256–257, 284, 320. 

539 Id. PP 284–286, 291; see also id. PP 229, 315. 

The Commission reasoned, in part, that ‘‘[g]reater 

participation by transmission developers in the 

transmission planning process may lower the cost 

of new transmission facilities, enabling more 

efficient or cost-effective deliveries by load serving 

entities and increased access to resources.’’ Id. P 

291. 

540 Id. P 256. 

541Order No. 1000–A, 139 FERC ¶ 61,132 at P 

361; see also Order No. 1000, 136 FERC ¶ 61,051 

at PP 269, 286. The Commission also reiterated that 

‘‘if a regional transmission planning process does 

not consider and evaluate transmission projects 

proposed by nonincumbents that regional 

transmission planning process cannot meet the 

Order No. 890 transmission planning principle of 

being ‘open.’ ’’ Order No. 1000, 136 FERC ¶ 61,051 

at P 229. 

542See Order No. 1000, 136 FERC ¶ 61,051 at P 

260 (acknowledging that incumbent transmission 

providers ‘‘may have unique knowledge of their 

own transmission systems, familiarity with the 

communities they serve,’’ and other potential 

transmission development advantages); see also id. 

PP 241, 250 (summarizing other contentions ‘‘that 

incumbent transmission owners are better situated 

to build new transmission facilities’’). 

543 Id. P 260. 

544See supra notes 534–536 and associated text. 

The Commission explained, in part, that its 

decision in this regard would ‘‘continue[ ] to permit 

an incumbent . . . to meet its reliability needs or 

service obligations’’ through local transmission 

facilities, and the Commission hoped that this 

exemption would also, in part, address concerns 

that Order No. 1000’s reforms would ‘‘adversely 

impact the collaborative nature of current regional 

transmission planning processes.’’ See Order No. 

1000, 136 FERC ¶ 61,051 at PP 258, 262. 

545See supra note 537 and associated text. 

546See, e.g., Order No. 1000–A, 139 FERC 

¶ 61,132 at P 426 (‘‘The concept is that there should 

not be a federally established monopoly over the 

development of an entirely new transmission 

facility that is selected in a regional transmission 

plan for purposes of cost allocation to others.’’); id. 

P 360 (finding on rehearing that ‘‘the Commission’s 

decision to require public utility transmission 

providers to adopt the nonincumbent transmission 

developer reforms was an appropriate, and 

adequately tailored, remedy’’ and noting that the 

Commission did not accept the position of some 

commenters that ‘‘supported eliminating all federal 

rights of first refusal’’ but rather it ‘‘determined that 

utility transmission provider eliminate 

provisions in Commission-jurisdictional 

tariffs and agreements that establish a 

federal right of first refusal for an 

incumbent transmission provider with 

respect to entirely new transmission 

facilities selected in a regional 

transmission plan for purposes of cost 

allocation.533

339. This requirement from Order No. 

1000 does not apply to local 

transmission facilities, which are 

defined as transmission facilities 

located solely within an incumbent 

transmission provider’s retail 

distribution service territory or footprint 

that are not selected in the regional 

transmission plan for purposes of cost 

allocation.534 The requirement also does 

not apply to the right of an incumbent 

transmission provider to build, own, 

and recover costs for upgrades to its 

own existing transmission facilities, 

regardless of whether an upgrade has 

been selected in the regional 

transmission plan for purposes of cost 

allocation.535 In addition, the 

Commission noted that the requirement 

does not remove, alter, or limit an 

incumbent transmission provider’s use 

and control of its existing rights-of-way 

under state law.536 The Commission has 

also permitted exemptions from the 

federal right of first refusal elimination 

mandate for immediate need reliability 

projects.537

340. In adopting Order No. 1000’s 

nonincumbent transmission developer 

reforms, the Commission identified 

several reasons why it believed that 

eliminating federal rights of first refusal 

from Commission-jurisdictional tariffs 

and agreements was necessary and 

appropriate to ensure that Commissionjurisdictional rates are just and 

reasonable. The Commission found that 

federal rights of first refusal ‘‘creat[e] a 

barrier to entry,’’ and that their 

existence could lead to the loss of 

nonincumbent transmission developer 

investment opportunities to incumbent 

transmission providers, which 

‘‘discourages nonincumbent 

transmission developers from proposing 

alternative solutions for consideration at 

the regional level’’ in regional 

transmission planning processes.538 The 

Commission found that administering 

transmission planning processes with 

federal rights of first refusal ‘‘may result 

in the failure to consider more efficient 

or cost-effective solutions to regional 

needs’’ and thus their elimination may 

give ‘‘customers . . . the benefits of 

competition in transmission 

development, and associated potential 

savings.’’ 539 The Commission also 

expressed concern that federal rights of 

first refusal could allow an incumbent 

transmission provider ‘‘to act in its own 

economic self-interest,’’ which in 

general would not support permitting 

‘‘new entrants to develop transmission 

facilities, even if proposals submitted by 

new entrants would result in a more 

efficient or cost-effective solution to the 

region’s needs.’’ 540

341. The Commission also found that 

elimination of federal rights of first 

refusal was ‘‘necessary to address 

opportunities for undue discrimination 

and preferential treatment against 

nonincumbent transmission developers 

within regional transmission planning 

processes.’’ 541 While the Commission 

did not dispute the claim that 

incumbent transmission providers may 

have some inherent advantages over 

nonincumbent transmission developers 

in the transmission development 

context,542 the Commission found that 

these claimed incumbent advantages 

were ‘‘strengths’’ that could be deployed 

by incumbent transmission providers to 

their benefit in competitive 

transmission development processes, 

and not a reason to forgo holding those 

processes.543

342. Importantly, while the 

Commission declined to eliminate 

federal rights of first refusal for 

upgrades to existing transmission 

facilities and local transmission 

facilities, among other specific types of 

transmission facilities,544 and has 

permitted exemptions for immediate 

need reliability projects,545 the 

Commission did not otherwise qualify 

or limit the federal right of first refusal 

elimination mandate within its defined 

scope (i.e., as applied to entirely new 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation).546 Instead, the 


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incumbent transmission providers should be able to 

maintain an existing federal right of first refusal for 

certain types of new transmission projects’’). 

547See FERC, Staff Report, 2017 Transmission 

Metrics, at 8 (Oct. 6, 2017), https://www.ferc.gov/ 

sites/default/files/2020-05/transmissioninvestment-metrics.pdf (describing the two general 

types of competitive transmission development 

processes, the ‘‘competitive bidding model’’ and the 

‘‘sponsorship model’’); see also Competition 

Coalition Comments at 14–15 (same). 

548See FERC, Staff Report, 2017 Transmission 

Metrics, at 23–26 (Oct. 6, 2017), https:// 

www.ferc.gov/sites/default/files/2020-05/ 

transmission-investment-metrics.pdf; see also 

Brattle Apr. 2019 Competition Report at 5, 8 fig. 2, 

28 fig. 10 (included as Ex. 2 to LS Power Oct. 12 

Comments). 

549See Competition Coalition Comments at 9–10 

(describing growth trend in overall transmission 

investment); NextEra Comments at 99–101 

(estimating that only a small fraction of overall 

transmission investment in RTO/ISO regions 

between 2013–2020 was awarded as the result of a 

competitive process); Brattle Apr. 2019 Competition 

Report at 1, 3, 5–8, 25 (same). 

550See APPA Comments at 20; AEE Comments at 

22–23; LS Power Reply Comments at 41–44; see 

also California Commission Comments at 14–16 

(discussing investment in ‘‘self-approved projects’’); 

EEI Comments at 6 (referring in part to ‘‘a near 

standstill in transmission development for regional 

projects’’); Brattle-Grid Strategies Oct. 2021 Report 

at 19–20 (explaining that concentration on local 

transmission facilities and the incentives given to 

transmission owners may create ‘‘a bias against 

larger regional solutions even if they are more 

innovative and cost-effective’’). 

551ANOPR, 176 FERC ¶ 61,024 at P 37. 

552 Id. 

553 Id. 

554E.g., MISO Comments at 26–27, 29–30 

(asserting that ‘‘Order No. 1000 requirements for 

competitive development of projects selected in a 

regional plan for purposes of cost allocation [have] 

. . . seen only limited success’’ and describing the 

challenges MISO has faced in implementing those 

mandates); WIRES Comments at 11–12, 16 

(asserting that the ‘‘introduction of competition . . . 

has not lived up to expectations’’ and addressing 

the Commission’s articulated concerns about the 

possibility that ‘‘current policies and processes are 

not appropriately incentivizing the development 

and construction of larger regional facilities’’); 

Harvard ELI Comments at 17–18, 20–21 (contending 

that ‘‘Order No. 1000-compliant regional processes 

. . . have not fulfilled their promise’’ and did not 

‘‘lead to an increase in regional projects’’). 

555Competition Coalition Comments at 4, 11; see 

also id. at 4 nn.4–5 (citing Brattle Apr. 2019 

Competition Report at 13, 19); California 

Commission Comments at 24–25, 34–35, 42–43. 

556LS Power Oct. 12 Comments at 28, 31–33, 35, 

85–111 (citations omitted); see also LS Power Reply 

Comments at 2–39 (collecting statements from 

similar comments (citations omitted)). 

Commission ordered, with limited 

exceptions, the elimination of federal 

rights of first refusal for entirely new 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation, regardless of the 

specifics of or the circumstances under 

which such federal rights of first refusal 

had been or could be used. 

2. Experience Since Order No. 1000 

343. Since the Commission issued 

Order No. 1000, all public utility 

transmission providers across the 

country have adopted and many have 

administered competitive transmission 

development processes for the selection 

of transmission facilities in a regional 

transmission plan for purposes of cost 

allocation.547 Though public utility 

transmission providers in all 

transmission planning regions must 

participate in their respective regional 

transmission planning processes, the 

degree to which competitive 

transmission development processes 

have led to specific transmission facility 

selection, investment, and development 

activities since Order No. 1000—and the 

proportion of such processes that 

resulted in the selection of a 

nonincumbent transmission developer’s 

proposal—varies significantly by 

region.548

344. Importantly, recent transmission 

investment trends suggest that despite 

increased investment in transmission 

facilities overall, in many transmission 

planning regions there has been 

comparatively limited investment in 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation as a result of a 

competitive process; transmission 

investment has instead largely been 

concentrated in transmission facilities 

generally not subject to competitive 

transmission development processes.549

In particular, recent transmission 

investment appears to be concentrated 

in local transmission facility 

development or regional transmission 

facilities subject to an exception from 

competitive transmission development 

processes, such as immediate need 

reliability projects or upgrades to 

existing transmission facilities, as 

opposed to investment in regional 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation that serve a wider set 

of transmission needs and are subject to 

competitive transmission development 

processes.550

3. ANOPR 

345. In the ANOPR, the Commission 

recognized the possibility that ‘‘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.’’ 551 The Commission also 

recognized that to ‘‘the extent that the 

requirements of the regional 

transmission planning process result in 

transmission providers expanding 

predominately local transmission 

facilities, that process may fail to 

identify more efficient or cost-effective 

transmission facilities needed to 

accommodate anticipated future 

generation.’’ 552 The Commission sought 

‘‘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.’’ 553

4. Comments 

346. In response, many commenters 

address issues related to competitive 

transmission development processes, 

federal rights of first refusal, and how 

Order No. 1000’s reforms may have 

shaped transmission development 

decisions and investments in recent 

years. Included among these comments 

are critiques of the Commission’s Order 

No. 1000 nonincumbent transmission 

developer reforms, which contend that 

those reforms have not achieved their 

predicted benefits; these critiques tend 

to associate that track record at least in 

part with Order No. 1000’s federal right 

of first refusal elimination policy.554

347. However, commenters are 

divided regarding the steps that they 

believe the Commission should take in 

response to the concerns and trends 

described above. Several commenters 

support increasing the scope and 

number of competitive transmission 

development processes by expanding 

Order No. 1000’s federal right of refusal 

elimination mandate to other types of 

transmission facilities. For example, the 

Competition Coalition and the 

California Commission call for more 

competition in regional transmission 

planning, design, and construction, 

which they predict will lower costs to 

customers as transmission investment 

increases.555 Similarly, LS Power 

contends that the implementation of 

current regional transmission planning 

processes has resulted in increasingly 

local transmission planning to the 

detriment of regional transmission 

planning, that a focus on local 

transmission needs leads to piecemeal 

solutions, and that the proper response 

is to expand competitive transmission 

development processes to address a 

greater number of transmission 

facilities.556 NARUC similarly 

recommends that the Commission 

encourage the use of current 

competitive processes and discourage 

over-investment in local transmission 

facilities to help maximize regional and 


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557NARUC Comments at 55–56; see also 

Environmental Advocates Comments at 15–18 

(arguing, in part, that reliance on projects not 

subject to competition ‘‘can forestall regional 

projects by making transmission planning and 

construction into a piecemeal process’’). 558PIOs Reply Comments at 13. 559PJM Market Monitor Comments at 8. For 

example, the PJM Market Monitor criticizes the lack 

of oversight of supplemental projects in PJM, noting 

that the need for supplemental projects should be 

clearly defined within PJM’s transmission planning 

process and there should be a transparent, robust, 

and clearly defined mechanism to permit 

competition to build supplemental projects. Id. at 

8–9. 

560Chairman of the Kentucky Commission Kent 

A. Chandler Reply Comments at 3–4. 

561See EEI Comments at 21–23; see also id. at 23– 

24 (urging the Commission to recognize that 

‘‘transmission is not being built’’ and to act to 

‘‘remove the complex and costly competitive 

processes’’ that, in EEI’s view, delay transmission 

development); See EEI Comments at 21–23; see also 

Eversource Comments at 13–14 (arguing that, in its 

experience, competitive transmission development 

processes have created delays, and that it is unclear 

what benefits can be shown from such processes); 

Indicated PJM TOs Comments at 4 (arguing in part 

that Order No. 1000’s nonincumbent transmission 

developer reforms have ‘‘fostered conflict and 

litigation, with the associated expense and delays’’). 

562EEI Comments at 23–24. 

563 ITC Comments at 13–15 & nn.8–9 (citing 

Concentric Energy Advisors, Building New 

Transmission, Experience to Date Does Not Support 

Expanding Solicitations (June 2019) (included as 

attach. B to EEI Reply Comments)). 

564 Id. at 13. 

565See supra note 550 and associated text. 

566See, e.g., Rob Gramlich & Jay Caspary, 

Americans for a Clean Energy Grid, Planning for the 

Future, at app. A (Jan. 2021) (included as Ex. 1 to 

ACORE Comments) (ACEG Jan. 2021 Planning 

Report); at app. A; Brattle, Offshore Transmission 

in New England: The Benefits of a Better Planned 

Grid (May 2020), https://www.brattle.com/wpcontent/uploads/2021/05/18939_offshore_

transmission_in_new_england_-the_benefits_of_a_

better-planned_grid_brattle.pdf (Brattle Offshore 

Transmission Study). 

567See, e.g., ACEG Jan. 2021 Planning Report at 

25 & fig. 8 (charting the annual regionally planned 

transmission investment in RTOs/ISOs from 2010 to 

2018); ACORE Comments at 4 (citing Ex. 1, ACEG 

Jan. 2021 Planning Report at 25). For example, 

investment in regional transmission facilities in 

PJM averaged $2.76 billion from 2005 to 2013 and 

dropped to $1.65 billion from 2014 to 2020. 

Harvard ELI Comments at 21 & n.92 (citations 

omitted); see also PJM, Transmission Expansion 

Advisory Committee, 2019 Project Statistics, at 3 

(May 12, 2020), https://www.pjm.com/-/media/ 

committees-groups/committees/teac/2020/ 

20200512/20200512-item-10-2019-projectstatistics.ashx. 

568See, e.g., Brattle Apr. 2019 Competition Report 

at 19 fig. 6. 

569See Order No. 1000, 136 FERC ¶ 61,051 at PP 

2–3, 46. 

570See, e.g., id. (Moeller, Comm’r, dissenting in 

part). 

interregional benefits.557 PIOs assert 

that the Commission must require 

public utility transmission providers to 

plan for local transmission needs as part 

of the regional transmission planning 

process.558 The PJM Market Monitor 

indicates that there is not yet a 

transparent, robust, and clearly defined 

mechanism to permit competition to 

build transmission projects, to ensure 

that competitors provide a total project 

cost cap, or to obtain least cost financing 

through the capital markets. The PJM 

Market Monitor claims that the 

Commission should build upon Order 

No. 1000 to remove barriers to 

nonincumbent transmission 

development and create more 

opportunities for competition between 

incumbent transmission providers and 

nonincumbent transmission 

providers.559 The Chairman of the 

Kentucky Commission states that more 

transmission facilities and needs should 

be subject to competition.560

348. In contrast, other commenters 

urge the Commission to move in the 

opposite direction, arguing that the 

existence of competitive transmission 

development processes leads to delays 

and added costs while the elimination 

of federal rights of first refusal for 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation has failed to produce 

the benefits that the Commission 

expected.561 For example, EEI urges the 

Commission to recognize that 

‘‘transmission is not being built’’ and to 

act to ‘‘remove the complex and costly 

competitive processes’’ that, in EEI’s 

view, delay transmission 

development.562 ITC asserts that 

significant time and resources are 

required to conduct competitive 

transmission development processes, 

yet those processes ‘‘deliver few if any 

savings to customers, let alone savings 

which justify their costs.’’ 563

Accordingly, ITC advocates for allowing 

public utility transmission providers to 

adopt or reinstate a federal right of first 

refusal in light of ‘‘the urgency of the 

need for new transmission 

investment.’’ 564

B. Need for Reform 

349. As noted above, recent 

investment appears to be concentrated 

in transmission facilities not subject to 

Order No. 1000 competitive 

transmission development processes, 

which are often developed within 

individual incumbent transmission 

provider retail distribution service 

territories or footprints or address 

narrow regional transmission needs, as 

opposed to investment in regional 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation that serve a wider set 

of transmission needs and are subject to 

competitive transmission development 

processes.565 Indeed, despite the fact 

that multiple industry studies estimate 

that regionally planned transmission 

expansion would yield numerous 

consumer benefits,566 transmission 

investment through the regional 

transmission planning and cost 

allocation processes has not necessarily 

increased since implementation of 

Order No. 1000; in fact, in some 

transmission planning regions, 

investment in regionally planned 

transmission has declined.567 The 

record here further indicates that 

regional transmission facilities subject 

to a competitive transmission 

development process represent only a 

small portion of total transmission 

investment in recent years across 

several transmission planning 

regions.568

350. This trend may be related to 

Order No. 1000’s nonincumbent 

transmission developer reforms. While 

Order No. 1000 anticipated and 

generally sought to facilitate greater and 

more efficient or cost-effective 

investment in regional transmission 

facilities,569 some observers at the time 

expressed concern that Order No. 1000’s 

reforms ‘‘could ultimately discourage’’ 

existing ‘‘transmission owners from 

seeking regional cost allocation for their 

local projects,’’ and thereby 

unintentionally encourage ‘‘more local 

transmission projects’’ serving more 

local needs, even where broader 

regional transmission facilities may be 

more efficient or cost-effective.570 Thus, 

given the investment trends observed 

since Order No. 1000’s implementation, 

it is possible that the Commission’s 

Order No. 1000 nonincumbent 

transmission developer reforms may in 

fact be inadvertently discouraging 

investment in and development of 

regional transmission facilities to some 

extent. Incumbent transmission 

providers, as a result of those reforms, 

may be presented with perverse 

investment incentives that do not 

adequately encourage those incumbent 

transmission providers to develop and 

advocate for transmission facilities that 

benefit more than just their own local 

retail distribution service territory or 

footprint. Due to these concerns, we 

propose to revisit and reform the 

Commission’s rules and policies 

regarding the elimination of federal 

rights of first refusal, as described in 

this section. 

C. Proposed Reform 

1. Approach To Reform 

351. In light of the experience gained 

since the issuance of Order No. 1000 

and the comments received in response 

to the ANOPR, we propose to amend 

Order No. 1000’s nonincumbent 

transmission developer reforms in part, 


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571 16 U.S.C. 825h (‘‘The Commission shall have 

power to perform any and all acts, and to prescribe, 

issue, make, amend, and rescind such orders, rules, 

and regulations as it may find necessary or 

appropriate to carry out the provisions of this 

chapter.’’); see also id. section 824d(a)–(b) 

(requiring that ‘‘all rules and regulations affecting 

or pertaining to’’ jurisdictional rates ‘‘be just and 

reasonable’’ and free from ‘‘undue preference or 

advantage’’); Am. Pub. Power Ass’n v. FPC, 522 F.2d 

142, 144, 145–47 (D.C. Cir. 1975) (affirming 

Commission action taken under FPA section 309 to 

change rules regarding cost basis for wholesale 

electric power rates, observing in part that 

‘‘ratemaking methodologies perceived to produce 

just and reasonable results in the past may be 

scrapped in favor of other methodologies now 

perceived to be preferable’’ (citation omitted)); 

La.Regional Transmission Organizations, Order No. 

2000, FERC Stats. & Regs. ¶ 31,089, at 30,993 (1999) 

(cross-referenced at 89 FERC ¶ 61,285) (relying in 

part on section 205 in a rulemaking order that 

enabled voluntary reforms), order on reh’g, Order 

No. 2000–A, FERC Stats. & Regs. ¶ 31,092 (2000) 

(cross-referenced at 90 FERC ¶ 61,201), aff’d sub 

nom. Pub. Util. Dist. No. 1 of Snohomish Cty. v. 

FERC, 272 F.3d 607 (DC Cir. 2001); La. Pub. Serv. 

Comm’n v. Entergy Corp., Opinion No. 519–A, 153 

FERC ¶ 61,188, at P 15 (2015) (‘‘The Commission, 

which is responsible for determining what is ‘just 

and reasonable’ under the FPA, necessarily has 

broad discretion to take into account all factors that 

affect that determination.’’). 

572See Order No. 1000, 136 FERC ¶ 61,051 at PP 

5, 7, 226. 573See supra notes 538 to 541 and associated text. 

so as to permit the exercise of federal 

rights of first refusal for transmission 

facilities selected in a regional 

transmission plan for purposes of cost 

allocation, conditioned on the 

incumbent transmission provider with 

the federal right of first refusal for such 

regional transmission facilities 

establishing joint ownership of the 

transmission facilities consistent with 

the proposal below. We propose to use 

the discretion afforded by FPA section 

309 to ‘‘amend, and rescind such orders, 

rules, and regulations as [the 

Commission] may find necessary or 

appropriate’’ in implementing the FPA, 

including FPA section 205,571 to amend 

Order No. 1000’s findings and mandates 

in part. Specifically, we preliminarily 

find that Order No. 1000 remains correct 

regarding the unconditional exercise of 

federal rights of first refusal for entirely 

new transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation—the unconditional 

use of federal rights of first refusal for 

such facilities remains unjust and 

unreasonable given the likelihood that 

the presence and exercise of those rights 

may prevent the realization of more 

efficient or cost-effective transmission 

solutions to regional transmission 

needs.572

352. However, in light of the years of 

experience since the issuance of Order 

No. 1000 and the comments received in 

response to the ANOPR, we 

preliminarily find that Order No. 1000’s 

remedy—requiring the elimination of all 

federal rights of first refusal for entirely 

new transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation—was overly broad. 

Order No. 1000 may have overlooked 

the possibility that, as an alternative to 

elimination of federal rights of first 

refusal for transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation, 

conditions could be applied to the use 

of federal rights of first refusal for such 

facilities that would make their exercise 

just and reasonable and not unduly 

discriminatory or preferential. 

353. Accordingly, we preliminarily 

find that, while Order No. 1000’s 

nonincumbent transmission developer 

reforms have a sound theoretical 

basis,573 in requiring the elimination of 

all federal rights of first refusal for 

entirely new transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation, the 

remedy prescribed by Order No. 1000 

failed to recognize that at least some of 

the most notable expected benefits from 

competitive transmission development 

processes (e.g., new transmission 

developer market entry, greater 

innovation in and potentially lower 

costs of transmission development) 

could be achieved or at least reasonably 

approximated through other means. We 

believe that it may be possible that 

allowing public utility transmission 

providers to propose conditional federal 

rights of first refusal consistent with the 

proposal below may help public utility 

transmission providers address 

potentially flawed investment 

incentives that may be restraining 

otherwise more efficient or costeffective regional transmission facility 

development. Therefore, under FPA 

sections 309 and 205, we preliminarily 

find it necessary or appropriate to carry 

out the provisions of the FPA to amend 

Order No. 1000 in part as described in 

this section. 

354. Should the Commission proceed 

to amend Order No. 1000’s findings and 

mandates as described above, following 

the issuance of any final rule in this 

docket, we propose to allow public 

utility transmission providers to 

propose, pursuant to FPA section 205, 

new federal rights of first refusal for 

incumbent transmission providers, 

provided that such rights are 

conditioned on the incumbent 

transmission provider with the federal 

right of first refusal for such regional 

transmission facilities establishing joint 

ownership of the transmission facilities 

consistent with the proposal below. We 

believe that this reform will help to 

ensure just and reasonable Commissionjurisdictional rates and limit 

opportunities for undue discrimination 

by public utility transmission providers. 

We preliminarily continue to find that 

unconditional federal rights of first 

refusal for incumbent transmission 

providers are unjust and unreasonable, 

and unduly discriminatory and 

preferential. 

355. In making this proposal, 

however, we do not intend to require 

the establishment of any particular 

federal rights of first refusal. Given the 

nature of our proposed action, public 

utility transmission providers would not 

be obligated to adopt the conditional 

federal rights of first refusal described in 

this section. Instead, Order No. 1000’s 

findings and mandates would be 

amended such that joint ownership 

conditions may presumptively be found 

to ensure just and reasonable 

Commission-jurisdictional rates and 

limit opportunities for undue 

discrimination by public utility 

transmission providers, if imposed upon 

the exercise of an incumbent 

transmission provider’s federal right of 

first refusal for transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation. We 

believe that this approach would permit 

justified variations from an otherwise 

one-size-fits-all federal rights of first 

refusal policy, and thereby would allow 

for regional flexibility, without 

imposing new federal rights of first 

refusal requirements on all public utility 

transmission providers. Public utility 

transmission providers would have the 

opportunity in their regular course of 

business to consider whether this type 

of a conditional federal right of first 

refusal would, if adopted, help improve 

their particular regional transmission 

planning process or help address 

potentially misaligned incentives 

regarding regional and local 

transmission facility investment. 

356. We also propose to allow public 

utility transmission providers that 

establish conditional federal rights of 

first refusal as recognized in any final 

rule adopted in this proceeding to make 

other corresponding adjustments to the 

timing and procedural requirements of 

their competitive transmission 

development processes that are just and 

reasonable and not unduly 

discriminatory or preferential. More 

specifically, to accommodate changes in 

federal rights of first refusal provisions 

regarding certain transmission facilities 

selected in a regional transmission plan 

for purposes of cost allocation, we 

propose to permit changes to existing 

tariff provisions that were adopted to 

comply with the following requirements 


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574The federal right of first refusal elimination 

requirement means the requirement that each 

public utility transmission provider eliminate 

provisions in Commission-jurisdictional tariffs and 

agreements that establish a federal right of first 

refusal for an incumbent transmission provider 

with respect to transmission facilities selected in a 

regional transmission plan for purposes of cost 

allocation. See Order No. 1000, 136 FERC ¶ 61,051 

at P 313. 

575The qualification requirement means the 

requirement that each public utility transmission 

provider revise its OATT to demonstrate that the 

regional transmission planning process in which it 

participates has established appropriate 

qualification criteria for determining an entity’s 

eligibility to propose a transmission facility for 

selection in the regional transmission plan for 

purposes of cost allocation, whether that entity is 

an incumbent transmission provider or a 

nonincumbent transmission developer. See id. P 

323. 

576The information requirement means the 

requirement that each public utility transmission 

provider identify in its OATT the information that 

a prospective transmission developer must submit 

in support of a transmission project the developer 

proposes in the regional transmission planning 

process. See id. P 325. 

577The access to use the regional cost allocation 

method(s) requirement means the requirement that 

each public utility transmission provider 

participate in a regional transmission planning 

process that provides that a nonincumbent 

transmission developer has an opportunity 

comparable to that of an incumbent transmission 

provider to allocate the cost of a transmission 

facility selected in the regional transmission plan 

for purposes of cost allocation through a regional 

cost allocation method or methods. See id. PP 332, 

335. 

578See, e.g., PJM Interconnection, L.L.C., 174 

FERC ¶ 61,117 at PP 3–4 (describing the criteria for 

and process regarding immediate need reliability 

projects). 

579See S.C. Pub. Serv. Auth., 762 F.3d at 72 & n.6. 580 If the competitive transmission development 

process does not yield a qualified transmission 

developer to use the regional transmission cost 

allocation method for the selected regional 

transmission facilities, and if necessary, the 

incumbent transmission provider may be obligated 

to build those selected regional transmission 

facilities. See PJM Interconnection, L.L.C., 142 FERC 

¶ 61,214, at P 224 (2013) (explaining that Order No. 

1000 did not limit ‘‘mechanisms to impose an 

obligation to build transmission facilities in a 

regional transmission plan’’); e.g., CAISO, CASIO 

eTariff, § 24.6.4, (Inability to Complete the 

Transmission Solution) (2.0.0) (granting CAISO the 

discretion, regarding reliability driven transmission 

solutions an Approved Project Sponsor is unable to 

construct, to either ‘‘direct the Participating TO in 

whose PTO Service Territory or footprint either 

terminus of the transmission solution is located 

. . . to build the transmission solution, or the 

CAISO may open a new solicitation for Project 

Sponsors to finance, own, and construct the 

transmission solution’’). 

581See supra P 337. 

582See infra PP 365, 371. 

583Order No. 1000, 136 FERC ¶ 61,051 at P 776. 

584 Id. (citing Order No. 890, 118 FERC ¶ 61,119 

at P 593). 

585See, e.g., CAISO, CASIO eTariff, § 24.5.2 

(Project Sponsor Application and Information 

Requirements) (6.0.0), § 24.5.2.1 (Opportunity for 

Collaboration); id. 24.15.1 Transmission Additions 

and Upgrades under TCA (0.0.0), section 24.15.1 

(referencing ‘‘transmission additions and upgrades 

[that] are jointly developed by Participating TOs 

and non-Participating TOs’’); MISO, FERC Electric 

Tariff, attach. FF (Transmission Expansion Planning 

Protocol) (85.0.0), § VIII.D.4.2. (Joint-Developer 

Proposal); PJM, Intra-PJM Tariffs, OA Schedule 6, 

§ 1.5 (Procedure for the Development of the 

Regional Transmission Expansion Plan) (28.0.0), 

§ 1.5.6(l) (‘‘Nothing herein shall prevent any 

Transmission Owner or other entity designated to 

construct, own and/or finance a recommended 

transmission enhancement or expansion from 

agreeing to undertake its responsibilities under 

such designation jointly with other Transmission 

Owners or other entities.’’). 

of Order No. 1000: The federal rights of 

first refusal elimination requirement; 574

the qualification requirement; 575 the 

information requirement; 576 and the 

access to use the regional cost allocation 

method(s) requirement.577 The degree to 

which changes to such tariff provisions 

will be necessary will depend on the 

specifics of the future proposal made by 

a particular public utility transmission 

provider. In allowing these 

corresponding adjustments, we intend 

for public utility transmission providers 

to provide robust openness and 

transparency safeguards regarding the 

exercise of conditional federal rights of 

first refusal, to help ensure just and 

reasonable Commission-jurisdictional 

rates and to limit and detect instances 

of potential undue discrimination.578

357. Also, we envision that 

conditional federal right of first refusal 

proposals would seek to establish 

federal rights of first refusal true to their 

name—a process whereby an incumbent 

transmission provider may, at its own 

election, choose to exercise a right to be 

designated to use the regional cost 

allocation method for a particular 

transmission facility or set of 

transmission facilities within its retail 

distribution service territory or footprint 

that is selected in a regional 

transmission plan for purposes of cost 

allocation,579 subject to applicable 

conditions. Should the incumbent 

transmission provider choose not to 

exercise its right, we envision that a 

public utility transmission provider 

would then proceed to follow its 

competitive transmission development 

process to select a qualified 

transmission developer to use the 

regional transmission cost allocation 

method for the selected regional 

transmission facilities.580

2. Conditional Federal Rights of First 

Refusal for Certain Jointly-Owned 

Transmission Facilities 

358. We propose to preliminarily find 

presumptively just and reasonable and 

not unduly discriminatory or 

preferential the establishment of a 

federal right of first refusal for 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation, conditioned on jointownership requirements, as more fully 

described in this section. We propose 

that an incumbent transmission 

provider may establish qualifying joint 

ownership structures with unaffiliated 

nonincumbent transmission developers 

as defined in Order No. 1000,581 or with 

another unaffiliated entity, including 

another incumbent transmission 

provider, if the joint ownership 

structure meets the requirements 

outlined in this section, including the 

requirement that the joint ownership 

structure offer a meaningful level of 

participation and investment in 

proposed transmission facilities to the 

incumbent transmission provider’s 

unaffiliated partners.582 We believe this 

proposed reform could address the 

potentially misaligned incentives for 

regional transmission facility 

development faced by incumbent 

transmission providers while still 

largely ensuring at least some of the 

potential cost-related benefits of 

competitive transmission development 

processes. 

a. Background 

359. In Order No. 1000, in response to 

comments requesting that the 

Commission consider joint transmission 

ownership as a financing and cost 

allocation tool, the Commission stated 

that specific financing techniques such 

as joint ownership were beyond the 

scope of that proceeding. While the 

Commission declined to ‘‘specifically 

address joint ownership as a cost 

allocation tool,’’ it did note that 

transmission developers were ‘‘free to 

consider joint ownership when 

proposing and developing a 

transmission project.’’ 583 The 

Commission also reiterated its belief 

that ‘‘there are benefits to joint 

ownership of transmission facilities, 

particularly large backbone facilities, 

both in terms of increasing 

opportunities for investment in the 

transmission grid, as well as ensuring 

nondiscriminatory access to the 

transmission grid by transmission 

customers.’’ 584 Since Order No. 1000, 

joint proposals or joint ownership 

arrangements between incumbent 

transmission providers and 

nonincumbent transmission developers 

have been an option generally available 

to qualified transmission developers 

participating, pursuant to public utility 

transmission provider tariffs, in 

competitive transmission development 

processes.585

b. Comments 

360. Although the Commission did 

not specifically ask about jointly-owned 


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586See ANOPR, 176 FERC ¶ 61,024 at P 37. 

587SDG&E Comments at 4–5. 

588TAPS Comments at 8 (citing TAPS 2021 White 

Paper (June 25, 2021), https://www.tapsgroup.org/ 

wp-content/uploads/2021/09/TAPS-Inclusive-JointOwnership-White-Paper.pdf (TAPS 2021 White 

Paper)). 

589 Id. at 9–11. 

590 Id. at 8–9 & nn.9–11. 

591 Id. at 12; TAPS 2021 White Paper at 7–8 

(citing in part Order No. 1000, 136 FERC ¶ 61,051 

at P 776; Promoting Transmission Inv. Through 

Pricing Reform, Policy Statement, 77 FR 69754 

(Nov. 21, 2012), 141 FERC ¶ 61,129 (2012)). 

592TAPS Comments at 13–15, 52–53. 

593 Id. at 13–15. 

594 Id. at 12, 14–15, 52–53. 

595See supra P 337. 

596See FERC, Staff Report, 2017 Transmission 

Metrics, at 8 (Oct. 6, 2017), https://www.ferc.gov/ 

sites/default/files/2020-05/transmissioninvestment-metrics.pdf (describing the two general 

types of competitive transmission development 

processes). 

transmission facilities in the ANOPR,586

some commenters address the topic of 

jointly-owned transmission facilities. 

For example, SDG&E discusses its 

partnership with nonincumbent 

transmission developers to develop and 

construct two new transmission lines, 

known as the Sunrise Powerlink and 

Sycamore-Pen ̃ asquitos projects.587

361. In its comments, TAPS supports 

joint transmission ownership 

arrangements, which TAPS argues have 

been effective for getting transmission 

facilities constructed.588 Among other 

potential benefits of joint transmission 

ownership arrangements, TAPS argues 

that these arrangements improve 

coordination by leveraging relationships 

and knowledge among the joint-owning 

parties for transmission siting, obtaining 

approval from state-level retail 

regulators, easing cost allocation issues 

by spreading or socializing costs among 

the joint-owning parties, spreading risk 

more evenly, and likely lessening 

disputes related to transmission 

planning and cost allocation that the 

Commission may otherwise have to 

adjudicate.589 Joint ownership 

arrangements, TAPS explains, can be 

structured in various ways, including as 

an inclusive transmission-only 

company, or shared-system 

arrangement, or other type of joint 

venture, including structures where 

ownership among two or more utilities 

is held in proportion to each 

participant’s load ratio share of 

connected customer load.590

362. TAPS asserts that while the 

Commission has previously found that 

joint transmission ownership 

arrangements are beneficial and 

encouraged more entities to consider 

these types of arrangements,591 there are 

few joint transmission ownership 

arrangements today. TAPS warns that 

the Commission’s objective of 

modifying transmission planning and 

expansion requirements to 

accommodate the changing resource 

mix, while minimizing costs to 

consumers, would be thwarted if costs 

are unnecessarily increased; that 

objective may also be thwarted if 

needed transmission projects are not 

timely built because those projects face 

greater financial or siting risk without 

joint ownership, which may relate to 

federal rights of first refusal 

requirements.592

363. In order to foster joint 

transmission ownership arrangements, 

TAPS recommends that the Commission 

make changes to transmission planning 

processes, including by permitting 

public utility transmission providers to 

bid out the cost of construction and 

associated capital requirements 

regarding regional and interregional 

transmission facilities selected in 

regional transmission plans, which 

would be designed to identify 

ownership partners among the existing 

load-serving entities in the transmission 

planning region. TAPS recommends 

that, to the extent the Commission 

makes a finding on joint transmission 

ownership arrangements, the 

Commission should structure 

competitive bidding processes such that 

they provide transmission-dependent 

utilities in the project’s footprint with 

opportunities to participate in 

supplying their fair share of capital for 

certain projects.593

364. While TAPS does not explicitly 

request that the Commission permit the 

establishment of a conditional federal 

right of first refusal for constructing 

transmission facilities under certain 

joint transmission ownership 

arrangements, TAPS contends that in 

general there is significant interest from 

willing partners that could work 

together with incumbent transmission 

providers to construct a transmission 

facility, and that the structure of 

competitive transmission development 

processes should ‘‘advance[ ] the role of 

inclusive joint ownership.’’ 594

c. Proposed Reform 

365. We preliminarily find 

presumptively just and reasonable and 

not unduly discriminatory or 

preferential the establishment of a 

federal right of first refusal for 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation, conditioned on the 

incumbent transmission provider with 

the federal right of first refusal for such 

regional transmission facilities 

establishing joint ownership of the 

transmission facilities consistent with 

this subsection. We propose that an 

incumbent transmission provider may 

establish qualifying joint ownership 

with unaffiliated nonincumbent 

transmission developers as defined in 

Order No. 1000,595 or another 

unaffiliated entity, including another 

incumbent transmission provider, if 

otherwise consistent with this 

subsection. These potential joint 

ownership partners could include 

unaffiliated public power entities, 

unaffiliated load-serving entities such as 

transmission-dependent municipallyowned utilities or electric cooperatives, 

other unaffiliated third parties that do 

not have (or are operating outside of) 

their retail distribution service territory 

or footprint, or another unaffiliated 

entity, including another incumbent 

transmission provider. 

366. We expect that public utility 

transmission providers seeking to adopt 

this reform will need to include in their 

tariffs a detailed process for the exercise 

of a conditional right of first refusal for 

regional transmission facilities that will 

be jointly owned. Relatedly, we believe 

that an incumbent transmission 

provider’s conditional federal right of 

first refusal—whether exercised or not 

regarding any particular transmission 

facility—should not significantly delay 

the regional transmission planning 

process, nor should it result in 

prolonged uncertainty regarding which 

transmission facilities will (or, 

alternatively, will not) be subject to 

competitive transmission development 

processes. 

367. We envision, as an example, the 

following process for the exercise of a 

conditional federal right of first refusal 

for regional transmission facilities that 

will be jointly owned. First, the public 

utility transmission providers in a 

transmission planning region will 

identify a regional transmission need 

(under the sponsorship model) or 

identify a regional transmission need 

and select a transmission facility in the 

regional transmission plan for purposes 

of cost allocation to meet that need 

(under the competitive bidding 

model).596

368. Second, before public utility 

transmission providers in each 

transmission planning region initiate 

competitive transmission development 

processes, public utility transmission 

providers in each transmission planning 

region will give an opportunity for an 

incumbent transmission provider 

possessing a relevant conditional federal 

right of first refusal to indicate its intent 

to invoke that right and submit a jointlyowned regional transmission facility 


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597See, e.g., supra PP 360–364 (discussing 

examples of joint ownership structures employed or 

identified by ANOPR commenters, including those 

based on load-ratio share); see also infra note 604 

and associated text (describing the inclusive 

transmission-only company or shared-system 

agreement concepts). 

598See Order No. 1000, 136 FERC ¶ 61,051 at P 

776; see also Order No. 890, 118 FERC ¶ 61,119 at 

PP 593–594. 

599See Promoting Transmission Inv. through 

Pricing Reform, Order No. 679, 71 FR 43294 (July 

31, 2006), 116 FERC ¶ 61,057, at PP 354, 355 (2006). 

proposal in partnership with one or 

more unaffiliated entities. 

369. Third, given that the potentially 

relevant conditional federal right of first 

refusal and process for exercising it has 

been established in Commissionjurisdictional tariffs and agreements, 

upon receipt of a jointly-owned regional 

transmission facility proposal, the 

public utility transmission providers in 

the transmission planning region would 

confirm the parties’ rights and 

responsibilities associated with the 

jointly-owned transmission facility 

proposal and its conformance with tariff 

provisions implementing the option 

proposed in this subsection. Here, we 

envision that the parties participating in 

the jointly-owned regional transmission 

facility proposal would have to 

demonstrate that their proposal commits 

the parties to a joint-ownership 

arrangement consistent with this 

subsection and that it meets the 

requirements of the applicable regional 

transmission planning process as 

outlined in the public utility 

transmission providers’ tariffs on file 

with the Commission. For instance, the 

parties to a jointly-owned regional 

transmission facility proposal would 

have to provide sufficient detail to 

adequately delineate their respective 

financial interests and relationship as 

partners, and to demonstrate that the 

parties either individually or jointly 

meet all other applicable requirements. 

Public utility transmission providers in 

the transmission planning region 

should, at the conclusion of this step in 

the process, notify stakeholders and the 

public (e.g., through posting on a public 

website) that either the jointly-owned 

regional transmission facility proposal 

conforms with tariff provisions 

implementing the conditional right of 

first refusal and, thus, a relevant 

conditional right of first refusal has been 

exercised, or, alternatively, that the 

public utility transmission providers in 

the transmission planning region will 

proceed to initiate a competitive 

transmission development process given 

that the jointly-owned regional 

transmission facility proposal does not 

conform with such tariff provisions. If a 

jointly-owned regional transmission 

facility proposal is not or cannot be 

confirmed as conforming with the 

public utility transmission provider’s 

Commission-jurisdictional tariffs and 

agreements that relate to the incumbent 

transmission provider’s conditional 

federal right of first refusal, or otherwise 

does not qualify for selection in the 

regional transmission plan for purposes 

of cost allocation, public utility 

transmission providers in the 

transmission planning region shall 

proceed to follow their otherwise 

applicable competitive transmission 

development process. 

370. Finally, public utility 

transmission providers in the 

transmission planning region would 

proceed to evaluate the jointly-owned 

regional transmission facility proposal 

without going through the competitive 

transmission development process. In a 

transmission planning region with a 

sponsorship model, this means that 

public utility transmission providers 

would evaluate in their regional 

transmission planning process the 

jointly-owned regional transmission 

facility proposal for potential selection 

in the regional transmission plan for 

purposes of cost allocation without 

soliciting any sponsored transmission 

facility proposals. In a transmission 

planning region with a competitive 

bidding model, where the transmission 

facility has already been selected in the 

regional transmission plan for purposes 

of cost allocation, this means that public 

utility transmission providers would 

evaluate the jointly-owned regional 

transmission facility proposal through 

the regional transmission planning 

process without soliciting other 

proposals to develop the alreadyselected regional transmission facility. 

371. As part of this proposal and in 

general, we believe that the benefits of 

joint ownership would not be achieved 

if an incumbent transmission provider 

partnered with an affiliated entity to 

submit a proposal, or if that incumbent 

transmission provider limited the input 

or ownership share of its intended 

partners to less than a meaningful level. 

Instead, we intend for incumbent 

transmission providers pursuing jointownership proposals to offer 

unaffiliated entities a reasonable chance 

at meaningful participation and 

investment in the proposed regional 

transmission facility. Therefore, we 

propose that to qualify for the 

presumption advanced in this proposal, 

incumbent transmission providers with 

a conditional federal right of first refusal 

would not be allowed to partner with 

affiliated entities, and would not be 

allowed to structure joint-ownership 

arrangements such that unaffiliated 

entities were offered less than a 

meaningful level of participation and 

investment in the proposed regional 

transmission facility. While we do not 

propose to limit potentially qualifying 

joint ownership structures to those 

already employed in the industry, we 

note that a meaningful level of 

participation and investment in 

proposed facilities has been or could be 

offered to unaffiliated entities under 

various types of joint ownership 

structures that have been established or 

proposed.597

372. We believe that a conditional 

federal right of first refusal for jointlyowned transmission facilities as 

described in this subsection may help 

facilitate openness in the regional 

transmission planning process, decrease 

potential financial and siting risks, and 

increase the likelihood that 

transmission facilities selected in a 

regional transmission plan for purposes 

of cost allocation are successfully and 

cost-effectively developed. First, if a 

conditional federal right of first refusal 

was available for jointly-owned regional 

transmission facilities, the greater 

development certainty that a federal 

right of first refusal could provide for 

the development of a transmission 

facility could help incentivize interested 

parties (including incumbent 

transmission providers and potential 

unaffiliated partners) to consider a 

jointly-owned transmission facility and 

leverage the combined transmission 

development strengths of the parties, 

potentially including the parties’ 

knowledge of siting and permitting 

processes or other strengths. Joint 

ownership arrangements could, 

consistent with Commission precedent, 

help increase opportunities for 

investment in the transmission system, 

as well as ensure not unduly 

discriminatory access to the 

transmission system by transmission 

customers.598 Indeed, we believe that 

jointly-owned regional transmission 

facilities, which may involve the 

participation of multiple nearby loadserving entities and potentially those 

that are public power entities, may 

increase collaboration within the 

regional transmission planning process 

consistent with Order No. 679.599

373. Second, given the nature of a 

joint-ownership arrangement, 

individual parties working together may 

achieve efficiencies in addressing their 

collective transmission needs and, 

therefore, achieve lower overall costs 

compared to developing transmission 

facilities to resolve more individualized 

needs in a more piecemeal manner as is 

the case today. Relatedly, the entities in 


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600See SDG&E Comments at 4–5; see also 

California State Water Project Reply Comments at 

12 n.44 (discussing the Sycamore-Pen ̃ asquitos 

Project (citations omitted)); Citizens SycamorePenasquitos Transmission LLC, 164 FERC ¶ 61,149, 

at PP 5–6 (2018) (same); Citizens Sunrise 

Transmission LLC, 138 FERC ¶ 61,129, at PP 3–10 

(2012) (discussing the Sunrise Powerlink Project); 

Citizens Energy Corp., 129 FERC ¶ 61,242, at P 5 

(2009) (same). 

601See supra notes 538 to 541 and associated text. 

602See supra note 550; see also WIRES Comments 

at 11–12, 16 (asserting that the ‘‘introduction of 

competition . . . has not lived up to expectations’’ 

and addressing the Commission’s articulated 

concerns about the possibility that ‘‘current policies 

and processes are not appropriately incentivizing 

the development and construction of larger regional 

facilities’’). 

603See supra notes 538 to 543 and associated text. 

604 In its comments and related white paper, 

TAPS cites Vermont Transco LLC and American 

Transmission Company LLC as inclusive 

transmission-only companies where instead of 

retaining direct ownership of separate transmission 

facilities, investor-owned and public power or 

cooperative utilities alike own membership units or 

equity stakes in one jointly-owned transmission 

company. See TAPS Comments at 8 nn.8–9; see also 

TAPS 2021 White Paper at 2. As TAPS further 

explains, under ‘‘shared-system arrangements, . . . 

transmission facilities of two or more utilities are 

planned and operated jointly, as a single system, 

pursuant to a long-term agreement. Ownership is 

generally in proportion to each participant’s load 

ratio share of connected customer load, which can 

be achieved in a variety of ways, e.g., owning an 

undivided share of the entire joint system; owning 

discrete facilities; owning new facilities.’’ See TAPS 

Comments at 8 n.10. 

605See TAPS Comments at 14–15. 

a joint ownership arrangement might 

bring different strengths to the process 

of developing a regional transmission 

facility, potentially reducing the costs 

for development or leveraging their 

expertise to design a more efficient or 

cost-effective transmission facility than 

the partners would have designed 

separately, thus benefiting customers. 

We note, for example, that while 

SDG&E’s Sunrise Powerlink and 

Sycamore-Pen ̃ asquitos projects 

addressed multiple reliability needs for 

CAISO’s transmission system, these 

transmission facilities also enabled the 

transmission facility’s other joint owner 

the option to lease a portion transfer 

capability of the transmission facility.600

In short, we believe that this joint 

ownership proposal may help promote 

innovative transmission ownership 

structures for transmission 

development, as well as innovative 

regional transmission facilities that 

more efficiently or cost-effectively 

address regional transmission needs, 

which in turn would help ensure just 

and reasonable Commissionjurisdictional rates. 

374. Third, jointly-owned regional 

transmission facilities, by spreading the 

risks and responsibilities of developing 

transmission facilities among multiple 

parties, may act as a useful hedging tool 

against expected longer-term, future 

transmission system development costs 

by allowing the parties to offset nearterm expenditures on constructing 

transmission facilities necessary to 

maintain reliability. 

375. Thus, we preliminarily find that 

a conditional federal right of first refusal 

for regional transmission facilities that 

will be jointly owned, as described in 

this subsection, could address the 

potentially misaligned incentives for 

transmission facility development faced 

by incumbent transmission providers 

while still largely ensuring the potential 

cost-related benefits of competitive 

transmission development processes. 

Given that jointly-owned transmission 

facilities appear to offer many benefits, 

we preliminarily find that customers 

may benefit from such a conditional 

federal right of first refusal through the 

selection of more efficient or costeffective transmission facilities in the 

regional transmission plan for purposes 

of cost allocation. Indeed, we believe 

that joint ownership arrangements may 

help achieve several of the goals that 

competitive transmission development 

processes are intended to serve today.601

376. In particular, we believe that this 

proposal would offer nonincumbent 

transmission developers and other 

potential unaffiliated entities the 

opportunity to partner with an 

incumbent transmission provider and 

thereby achieve market entry and 

greater diversity of participation and 

perspectives in transmission ownership. 

Moreover, to exercise their conditional 

federal right of first refusal under this 

proposed reform, incumbent 

transmission providers would be 

required to share ownership and 

investment opportunities with other 

partners, potentially including other 

transmission developers, limiting an 

incumbent transmission provider’s 

ability to use federal rights of first 

refusal to serve only its own economic 

interests. 

377. As described above, we are 

concerned that today’s processes place 

unintended emphasis on the 

development of local transmission 

facilities or other transmission facilities 

not subject to competitive transmission 

development processes, potentially at 

the expense of regional transmission 

facility development, given trends 

observed since the issuance of Order 

No. 1000.602 We believe that this joint 

ownership-focused conditional federal 

right of first refusal proposal may help 

address that issue while advancing the 

goals of Order No. 1000. 

378. We seek comment on the 

requirements proposed in this section of 

the NOPR. In particular, we request that 

commenters address how this proposed 

conditional right of first refusal aligns 

with or advances the goals of Order No. 

1000’s reforms,603 or otherwise ensures 

just and reasonable Commissionjurisdictional rates and limits 

opportunities for undue discrimination 

by public utility transmission providers. 

379. We also seek comment regarding 

the administrability of and 

implementation challenges associated 

with the establishment and exercise of 

joint ownership-focused conditional 

federal rights of first refusal, including 

what specific requirements the 

Commission should impose on jointownership agreements or on the process 

of formulating them. We also seek 

comment on whether limiting this 

option to proposals that form or expand 

an inclusive transmission-only company 

or shared-system arrangement is 

necessary to ensure just and reasonable 

Commission-jurisdictional rates and 

limited opportunities for undue 

discrimination by public utility 

transmission providers.604 We seek 

comment as well regarding whether all 

transmission-dependent utilities or 

load-serving entities in a particular 

public utility transmission provider’s 

service territory where a proposed 

regional transmission facility would be 

located should be given the opportunity 

to participate in a joint ownership 

arrangement that allows those 

transmission-dependent utilities or 

load-serving entities to supply up to 

their fair share (e.g., load-ratio share) of 

capital for certain regional transmission 

facilities.605

380. We also seek comment on the 

standards, such as ownership share 

percentages or load-ratio share offer 

requirements, that should govern 

whether particular joint ownership 

arrangements qualify for the 

presumption identified here because 

such standards would help achieve the 

benefits described above. Accordingly, 

we seek comment on whether any 

additional requirements beyond those 

mentioned above would be necessary to 

prevent the exertion of undue influence 

over the transmission development 

process or joint ownership arrangement 

by any project entity (including an 

incumbent transmission provider), 

avoid greater risks of project 

cancellation or abandonment, or 

otherwise protect customer interests. 

381. Relatedly, we seek comment on 

eligibility and participation criteria 

related to jointly-owned transmission 

facilities and partners that should be 

permitted to qualify for the presumption 

proposed in this section, and any 


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606For example, MISO’s tariff requires 

information regarding the responsibilities and 

liabilities of each party to a joint-developer 

transmission project proposal. See MISO, FERC 

Electric Tariff, attach. FF (Transmission Expansion 

Planning Protocol) (85.0.0), § VIII.D.4.2. (JointDeveloper Proposal); id. § VIII.D.5.1.1. 

(Identification of RFP Respondents). 

607For example, we note that SDG&E’s SycamorePen ̃ asquitos Project was developed in partnership 

with Citizens Energy and required both SDG&E and 

Citizens Energy to enter into a Development, 

Coordination, and Option Agreement to provide for 

their rights, responsibilities, and future options 

related to the Sycamore-Pen ̃ asquitos Project. See 

Citizens Sycamore-Penasquitos Transmission LLC, 

164 FERC ¶ 61,149 at P 7. 

608Supra P 17. 

609Order No. 1000–A, 139 FERC ¶ 61,132 at P 

190. 

610For the purposes of this NOPR, we define an 

‘‘in-kind replacement’’ as a new transmission 

facility that does not expand the capacity of the 

existing transmission facility that is being replaced 

unless the incidental increase in transmission 

capacity occurs as a function of advancements in 

technology of the replaced equipment and is thus 

not reasonably severable from that replacement. 

(e.g., a 345 kV transmission facility that is replaced 

with a 345 kV transmission facility). 

611See S. Cal. Edison Co., 164 FERC ¶ 61,160, at 

P 31 (2018) (‘‘While Order No. 890 does not 

explicitly define the scope of ‘transmission 

planning,’ the Commission adopted the 

transmission planning requirements in Order No. 

890 to remedy opportunities for undue 

discrimination in expansion of the transmission 

grid.’’ (citing Order No. 890, 118 FERC ¶ 61,119 at 

PP 57–58, 421–422)); Cal. Pub. Utils. Comm’n v. 

Pac. Gas & Elec. Co., 164 FERC ¶ 61,161, at P 68 

(2018); PJM Interconnection, L.L.C., 172 FERC 

¶ 61,136, at PP 12, 89, order on reh’g, 173 FERC 

¶ 61,225 (2020); PJM Interconnection, L.L.C., 173 

FERC ¶ 61,242, at P 54 (2020), order on reh’g, 176 

FERC ¶ 61,053 (2021). The Commission has further 

clarified that there may be instances in which a 

transmission owner’s replacement of an existing 

transmission facility may result in an incidental 

increase in transmission capacity that is not 

reasonably severable from that replacement, e.g., 

that occurs as a function of advancements in 

technology of the replaced equipment. In such 

cases, the Commission stated, the incidental 

increase in transmission capacity would not render 

the in-kind replacement of an existing transmission 

facility a transmission expansion that is subject to 

the transmission planning requirements of Order 

No. 890. Cal. Pub. Utils. Comm’n v. Pac. Gas & Elec. 

Co., 164 FERC ¶ 61,161 at P 68. 

612See, e.g., PJM Manual 14B: PJM Regional 

Transmission Planning Process at 19–20 (‘‘It should 

also be noted that prior to integrating a 

Supplemental Project into the RTEP base case PJM 

performs a ‘do no harm study’ to evaluate whether 

a proposed Supplemental Project will adversely 

impact the reliability of the Transmission System as 

represented in the planning models used in all 

other PJM reliability planning studies. If as a result 

of the do no harm study, system upgrades are 

required, such upgrades will be considered part of 

the Supplemental Project and are the responsibility 

of the Transmission Owner sponsoring the 

Supplemental Project.’’); see also MISO Business 

Practice Manual, Transmission Planning, Manual 

No. 020 at 22–23 (‘‘In its role as the Planning 

Coordinator (PC), MISO will evaluate all bottom-up 

projects submitted by Transmission Owner(s) and 

validate that the projects represent prudent 

solutions to one or more identified Transmission 

Issues.’’). 

transparency, informational, or 

screening processes that may be 

required.606 While transmission 

developers already must satisfy 

qualification criteria to be eligible to use 

the regional transmission cost allocation 

method for regional transmission 

facilities selected in a regional 

transmission plan for purposes of cost 

allocation, we seek comment on 

whether this proposal necessitates 

specialized eligibility criteria or 

particular joint ownership partner 

selection processes to ensure just and 

reasonable Commission-jurisdictional 

rates and limit opportunities for undue 

discrimination by public utility 

transmission providers.607

382. Finally, we seek comment 

regarding whether the Commission 

should pursue broader reform to its 

rules and regulations governing federal 

rights of first refusal. In particular, we 

seek comment on whether the 

Commission should consider fully 

restoring the federal rights of first 

refusal eliminated in Order No. 1000 

and, if so, how the Commission should 

go about doing so. We recognize that 

pursuing reforms focused on joint 

ownership alone may not fully address 

the potential issues that commenters 

have raised regarding competitive 

transmission development processes. 

Therefore, we seek comment both on the 

joint ownership-focused conditional 

federal rights of first refusal reform 

proposed above and on whether more 

significant changes to Order No. 1000’s 

federal right of first refusal elimination 

mandate would help ensure just and 

reasonable Commission-jurisdictional 

rates while limiting opportunities for 

undue discrimination by public utility 

transmission providers. 

VIII. Enhanced Transparency of Local 

Transmission Planning Inputs in the 

Regional Transmission Planning 

Process and Identifying Potential 

Opportunities to Right-Size 

Replacement Transmission Facilities 

A. Background 

383. Generally, the transmission 

facilities that public utility 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. 

384. As noted earlier, the Commission 

in Order No. 1000 defined a local 

transmission facility as a transmission 

facility located solely within a public 

utility transmission provider’s retail 

distribution service territory or footprint 

that is not selected in the regional 

transmission plan for purposes of cost 

allocation.608 The Commission did not 

require that the transmission facilities in 

a public utility transmission provider’s 

local transmission plan be subject to 

approval at the regional or interregional 

level, unless that public utility 

transmission provider seeks to have any 

of those facilities selected as regional 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation.609

385. As existing transmission 

infrastructure ages, transmission owners 

must assess the state of their 

transmission systems and the condition 

of their transmission assets to determine 

whether and, if so, how to replace 

existing transmission facilities that have 

reached the end of their useful lives. 

The Commission has found that a 

replacement of an existing transmission 

facility that does not incrementally 

increase that facility’s capacity is not 

subject to the transmission planning 

requirements of Order No. 890 or Order 

No. 1000 because an in-kind 

replacement 610 of an existing 

transmission facility does not represent 

an expansion or enhancement of the 

transmission system.611 Therefore, 

under this precedent there is no 

requirement that public utility 

transmission providers provide 

information about potential in-kind 

replacements of existing transmission 

facilities in either their local or regional 

transmission planning processes. Some 

RTO/ISO transmission planning regions 

may assess a planned in-kind 

replacement of an existing transmission 

facility to ensure that it does not cause 

adverse reliability impacts,612 but 

regional transmission planning 

processes generally do not evaluate 

whether the planned in-kind 

replacement transmission facility could 

be modified to more efficiently or costeffectively address regional 

transmission needs. However, we note 

that some public utility transmission 

providers do provide stakeholders with 

reports detailing the justification and 

quantity of replacement transmission 


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613See PJM Interconnection, L.L.C., 172 FERC 

¶ 61,136 at 21. 

614Supra Table 1—Long-Term Regional 

Transmission Benefits. 

615Order No. 1000–A, 139 FERC ¶ 61,132 at P 

426. 

616 Id. PP 366, 379, 425, 428; Order No. 1000, 136 

FERC ¶ 61,051 at P 262; Order No. 1000–A, 139 

FERC ¶ 61,132 at PP 366, 379, 425, 428. 

617ANOPR, 176 FERC ¶ 61,024 at P 171. 

618ANOPR, 176 FERC ¶ 61,024 at P 37. 

619 Id. P 162. 

620ACORE Comments at 19–23; AEE Comments 

at 41–43; ACPA and ESA Comments at 30; 

American Municipal Power Comments at 22–24; 

APPA Comments at 20; California Commission 

Comments at 31–37; Union of Concerned Scientists 

Comments at 24–31; Harvard ELI Comments at 20– 

21; LS Power Oct. 12 Comments at 36–37; Michigan 

Commission Comments at 8–9; NARUC Comments 

at 55–56; New Jersey Commission Comments at 3– 

7; Pennsylvania Commission Comments at 16–17; 

Policy Integrity Comments at 16. 

621E.g., District of Columbia’s Office of the 

People’s Counsel Comments at 11–12; EDF 

Comments at 12. 

622California Commission Comments at 17–18. 

623NARUC Comments at 15, 48–29. 

624New Jersey Commission Comments at 12–13. 

625ACEG Jan. 2021 Planning Report at 18–24. 

626Eversource Comments at 10. 

627LS Power Oct. 12 Comments at 43–44. 

628PIOs Comments at 50 (citing Brattle-Grid 

Strategies Oct. 2021 Report at 3). 

629ACEG Comments at 4–6 (citing Brattle Report 

at 25); AEE Comments at 41–49; Union of 

Concerned Scientists Comments at 24–31; 

Eversource Comments at 15–18; New Jersey 

Commission Comments at 4–6; LS Power Oct. 12 

Comments at 49–62; PJM Market Monitor 

Comments at 9., Harvard ELI Reply Comments at 

12–16. 

facilities.613 Further, as discussed 

above, some public utility transmission 

providers do assess the benefits of 

deferred or avoided infrastructure, 

including asset replacements that would 

otherwise be needed.614

386. The Commission in Order 1000– 

A clarified that it was not eliminating 

the right of an owner of a transmission 

facility to improve its own existing 

transmission facility.615 Order No. 1000 

also allows an incumbent transmission 

provider to meet its reliability needs or 

service obligations by choosing to build 

new transmission facilities that are 

located solely within its retail 

distribution service territory or footprint 

and that are not selected in a regional 

transmission plan for purposes of cost 

allocation.616 Such transmission 

facilities’ costs are allocated to the retail 

distribution service territory or footprint 

in which the facility is located through 

the incumbent transmission provider’s 

individual transmission service rates in 

its OATT or though the zonal rates in an 

RTO/ISO OATT. 

B. ANOPR 

387. In the ANOPR, the Commission 

sought comment on whether individual 

incumbent transmission provider 

practices regarding replacement of 

existing transmission facilities 

sufficiently align with the directive to 

ensure evaluation of alternative 

transmission solutions and whether 

these practices sufficiently consider the 

more efficient or cost-effective ways to 

serve future needs.617 Additionally, the 

Commission sought comment on 

whether sufficient transparency exists 

around replacement decisions made by 

transmission providers to allow an 

assessment of these decisions in the 

regional transmission planning process. 

388. In the ANOPR, the Commission 

also sought comment on local 

transmission planning 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 regional transmission 

planning processes.618

389. The Commission requested 

comment on whether the current 

regional and local transmission 

planning processes provide sufficient 

transparency for stakeholders to 

understand how best to obtain 

information and fully participate in the 

various processes.619 The Commission, 

for example, theorized that in non-RTO/ 

ISO regions, individual transmission 

owning members’ local transmission 

planning processes may not be as wellpublicized or follow as well-understood 

processes to provide information as in 

RTO/ISO regions. Based on this 

example, the Commission inquired 

whether customers and other 

stakeholders may benefit from enhanced 

oversight of local transmission 

planning. 

C. Comments 

390. Numerous commenters state that 

the vast majority of investment for 

transmission facilities in recent years 

has increasingly been focused on local 

level transmission facilities (typically 

less than 100–250 kV), and in replacing 

existing transmission facilities.620

391. Several commenters generally 

agree that the process for replacing 

aging transmission facilities needs 

additional improvements related to 

transparency and to increase the 

potential that multiple transmission 

system needs are addressed.621 The 

California Commission argues that 

because the decision to order 

replacement transmission facilities is 

delegated to incumbent transmission 

owners, there is no process to evaluate 

whether replacement transmission 

facilities could be a ‘‘like-for-like’’ 

replacement or whether the replacement 

transmission facility may be upgraded 

via a new design or capacity.622 NARUC 

argues that the Commission should 

require public utility transmission 

providers to apply Order No. 890 

transparency principles to replacement 

transmission facilities to guard against 

incumbent public utility transmission 

providers’ incentive to overinvest in 

replacement transmission facilities.623

The New Jersey Commission asserts that 

by evaluating replacement transmission 

facilities through the regional 

transmission planning process, a 

potentially broader transmission 

solution may be identified thus 

obviating the need for a smaller-scope 

replacement transmission facility.624

392. ACEG notes that much of the 

nation’s transmission facilities are over 

50 years old and that the lack of a 

broader view of transmission planning 

in terms of replacement of existing, 

aging transmission facilities, coupled 

with a changing generation mix, will 

lead to a suboptimal transmission 

infrastructure network.625 Eversource 

argues that, going forward, the 

Commission should encourage 

flexibility by breaking down 

transmission planning silos so that an 

existing or planned transmission facility 

can be ‘‘upsized’’ to address multiple 

system needs like transmission facility 

conditions while also anticipating clean 

energy goals.626 LS Power argues that 

the Commission should require NERC to 

develop a new requirement that 

transmission providers must give notice 

when an existing transmission facility 

has reached the end of its useful life.627

PIOs explain that the routine of in-kind 

replacement of aging transmission 

facilities misses opportunities for better 

utilizing existing rights-of-way so as to 

meet multiple transmission system 

needs, which increases costs and 

inefficiencies.628

393. Likewise, many commenters 

argue that the current relationship 

between local and regional transmission 

planning processes must be reformed. 

Some consumer groups, state 

commissions, market monitors, and 

renewable energy developers and 

organizations argue that the local 

transmission planning process is 

broken.629 These entities argue that the 

local transmission planning process 

lacks transparency and oversight and is 

inappropriately influenced by 

incumbent transmission owners. To 

correct these flaws, these commenters 


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630California Commission Comments at 39–43; 

Competition Coalition Comments at 16; LS Power 

Oct. 12 Comments at 49–53. 

631See e.g., Union of Concerned Scientists 

Comments at 24–31; see also Environmental 

Advocates Comments at 22; Northwest and 

Intermountain Comments at 49. 

632PJM Market Monitor Comments at 9. 

633American Municipal Power Comments at 32; 

City of New York Comments at 20–21; LS Power 

Oct. 12 Comments at 61–62; New Jersey 

Commission Comments at 11–13. 

634AEP Comments at 43–44 (citing PJM 

Interconnection, L.L.C., 172 FERC ¶ 61,136 (2020)). 

Briefly, PJM’s Attachment M–3 process for 

Supplemental Projects refers to the additional 

transparency and stakeholder input rules around 

transmission facilities that are not eligible for 

selection in the regional transmission plan for 

purposes of cost allocation but, though classified as 

local transmission facilities, nonetheless impact the 

identification and selection of regional transmission 

facilities. 

635CAISO Comments at 55–56. 636MISO TOs Comments at 21–22. 637PJM TOs Comments at 13–14. 638Alabama Commission Comments at 2; Duke 

Comments at 2–4; Southern Comments at 22–33; 

Louisiana Commission Comments at 4–9; Ohio 

Commission Comments at 1–6. 639See Order No. 1000, 136 FERC ¶ 61,051 at P 

148 (providing that regional planning processes 

should identify ‘‘alternative transmission solutions 

that might meet the needs of the transmission 

planning region more efficiently or cost-effectively 

than solutions identified by individual utility 

transmission providers in their local transmission 

planning process’’). 

640Order No. 890, 118 FERC ¶ 61,119 at PP 418– 

601. 

641 Id. P 454. 642See, e.g., Monongahela Power Co., 156 FERC 

¶ 61,134 (2016). 643NARUC Comments at 14 (stating current 

planning processes may not be sufficiently 

transparent ‘‘in every region’’); Massachusetts 

Attorney General Comments at 11 (stating it 

requires ‘‘herculean’’ efforts to review transmission 

project proposals); Resale Iowa Comments at 7 

(claiming ‘‘[c]ustomers and other third parties have 

little or no input into alternative evaluation and 

project selection of these local projects’’); Northwest 

and Intermountain Comments at 6 (stating ‘‘local 

utilities’ transmission plans are incorporated into 

regional transmission planning processes as inputs 

with little opportunity for stakeholder comment’’). 

644See supra P 40; note 63. 

are in favor of lowering voltage 

thresholds for regional transmission 

planning processes, such that more 

transmission facilities would be 

planned through that process rather 

than local transmission planning 

processes.630 Some of those commenters 

further urge the Commission to require 

transmission owners and providers to 

provide information and metrics about 

their local systems to the transmission 

planning process, and to do so within a 

timeframe that allows opportunity for 

real engagement with stakeholders, 

because without such a requirement, 

transmission owners and providers may 

be inhibiting the sharing of information 

relevant to the regional transmission 

planning processes.631

394. The PJM Market Monitor 

recommends that PJM should clearly 

define the need for local transmission 

projects within the regional 

transmission planning process and that 

there should be a transparent, robust, 

and clearly defined mechanism to 

permit competition to build the 

project.632 Some commenters go so far 

as to argue that there should be no 

separation between local and regional 

transmission planning processes at 

all.633

395. Other commenters identify the 

potential for less significant changes. 

AEP recommends that, to the extent the 

Commission reforms local transmission 

planning processes by increasing 

transparency and oversight, the 

Commission apply the practices and 

principles of PJM’s Attachment M–3 

process for Supplemental Projects 

across all other regions, including nonRTO/ISO regions.634

396. Alternatively, some commenters 

contend that existing processes are 

adequate. Some commenters argue that 

existing processes adequately address 

replacements of aging transmission 

facilities. CAISO notes that, while only 

participating transmission owners 

oversee replacement transmission 

facilities that do not expand the 

capacity of transmission facilities, 

CAISO continues to evaluate and 

approve transmission facilities that do 

expand the transmission system.635

MISO TOs assert that replacement 

transmission facilities are evaluated 

through the MISO regional transmission 

planning process already and that MISO 

is obligated to seek combining 

replacement transmission facilities with 

other transmission facility projects 

where it is efficient and cost-effective to 

do so.636 PJM TOs note that they 

provide PJM with a list of candidates for 

replacement transmission facilities so 

that PJM can determine if the 

replacement transmission project may 

also address a larger, regional need.637

397. Additionally, some commenters 

argue that existing processes provide for 

an appropriate level of coordination 

between regional and local planning. 

The Alabama Commission, Duke, 

Southern, the Louisiana Commission, 

and the Ohio Commission,638 assert 

jurisdictional arguments in opposition 

to enhanced or expanded local 

transmission planning processes. These 

commenters argue that the Commission 

should not intervene in retail activities 

that are subject to state-level regulatory 

bodies. 

D. Need for Reform 

398. We are concerned that local 

transmission planning processes may 

lack adequate provisions for 

transparency and meaningful input from 

stakeholders, and that regional 

transmission planning processes may 

not adequately coordinate with local 

transmission planning processes.639 In 

Order No. 890, the Commission required 

that public utility transmission 

providers’ local transmission planning 

processes comply with nine 

transmission planning principles, 

including coordination, openness, 

transparency, and information 

exchange.640 The Commission further 

explained that to satisfy the 

coordination principle, public utility 

transmission providers must facilitate 

the timely and meaningful input and 

participation of customers in the 

development of transmission plans and, 

more specifically, that ‘‘customers must 

be included at the early stages of the 

development of the transmission plan 

and not merely given an opportunity to 

comment on transmission plans that 

were developed in the first instance 

without their input.’’ 641 At times, the 

Commission has found it necessary to 

review local transmission planning 

processes to ensure stakeholders’ 

opportunity to engage in them is 

meaningful.642 However, 

implementation of these principles in 

local transmission planning processes 

appears to remain uneven, as 

commenters from regions across the 

country raise concerns about the 

transparency of and the opportunity for 

real engagement in various aspects of 

local transmission planning processes 

and their interaction with regional 

transmission planning processes.643 We 

are concerned that the lack of minimal 

standards or specified procedures to 

implement these principles may 

contribute to inadequate transparency 

and opportunities for stakeholders to 

engage in local transmission planning 

processes. In addition, we believe that 

reforms to better ensure more consistent 

implementation of these principles may 

be timely and important in light of the 

significant investments in transmission 

that now occur through local 

transmission planning processes.644

399. In addition, we are concerned 

that, given the age of the nation’s 

transmission infrastructure, many 

incumbent transmission providers are 

replacing aging transmission 

infrastructure as it reaches the end of its 

useful life without evaluating whether 

those replacement transmission 

facilities could be modified (i.e., right 

sized) to more efficiently or costeffectively address regional 

transmission needs, and, more 

generally, that public utility 

transmission providers developing 


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645For example, we note a recent PJM analysis 

estimates that roughly two-thirds of all PJM 

transmission system assets are more than 40 years 

old, with some transmission facilities approaching 

90 years old. See PJM Interconnection, L.L.C., The 

Benefits of the PJM Transmission System at 5 (April 

16, 2019), https://www.pjm.com/-/media/library/ 

reports-notices/special-reports/2019/the-benefits-ofthe-pjm-transmission-system.pdf.https:// 

www.pjm.com/-/media/library/reports-notices/ 

special-reports/2019/the-benefits-of-the-pjmtransmission-system.pdf. Moreover, AEP estimates 

that approximately 30 percent of all its transmission 

assets will need to be replaced over the next ten10 

years. See AEP, Wolfe Utilities, Midstream, & Clean 

Energy Conference, at 40 (Sept. 30, 2021), https:// 

www.aep.com/Assets/docs/investors/ 

eventspresentationsandwebcasts/ 

WolfeConferencePresentation093021.pdf.https:// 

www.aep.com/Assets/docs/investors/ 

eventspresentationsandwebcasts/ 

WolfeConferencePresentation093021.pdf. 

646S. Cal. Edison Co., 164 FERC ¶ 61,160 at P 33; 

Cal. Pub. Utils. Comm’n v. Pac. Gas & Elec. Co., 164 

FERC ¶ 61,161 at P 68; PJM Interconnection, L.L.C., 

172 FERC ¶ 61,136 at PP 12, 89; PJM 

Interconnection, L.L.C., 173 FERC ¶ 61,242 at P 54. 647Order No. 890, 118 FERC ¶ 61,119 at P 471. 

regional transmission plans may lack 

the information necessary to identify the 

benefits regional transmission facilities 

may provide in deferring or eliminating 

the need for in-kind replacements.645

Specifically, as described in the 

background section, in-kind 

replacements of existing transmission 

facilities are managed by individual 

incumbent transmission providers 

according to their company practices; 

there is no requirement that public 

utility transmission providers plan these 

in-kind replacement transmission 

facilities through an Order No. 890- 

compliant transmission planning 

process.646 While a transmission 

provider may be able to meet its needs 

associated with an aging asset through 

an in-kind replacement, there may be 

circumstances under which ‘‘rightsizing’’ the planned transmission 

replacement would result in a more 

efficient or cost-effective transmission 

facility to meet both the need for the 

transmission provider to replace the 

existing transmission facility and 

transmission needs identified through 

Long-Term Regional Transmission 

Planning. Because in-kind replacement 

of existing transmission facilities is not 

subject to any transmission planning 

process, we are concerned that, absent 

reform, there may be a lack of 

coordination between regional 

transmission planning processes and inkind replacement of existing 

transmission facilities to identify 

whether these replacement transmission 

facilities could be modified to more 

efficiently or cost-effectively address 

transmission needs identified through 

Long-Term Regional Transmission 

Planning. This lack of coordination may 

result in a regional transmission 

planning process that fails to identify 

opportunities to right size planned inkind replacement transmission facilities 

and may result in the development of 

duplicative or unnecessary transmission 

facilities that increase costs to 

consumers and render Commissionjurisdictional rates unjust and 

unreasonable. 

E. Proposed Reform 

400. We propose to require that public 

utility transmission providers in each 

transmission planning region revise the 

regional transmission planning process 

in their OATTs with additional 

provisions to enhance transparency of: 

(1) The criteria, models, and 

assumptions that they use in their local 

transmission planning process, (2) the 

local transmission needs that they 

identify through that process, and (3) 

the potential local or regional 

transmission facilities that they will 

evaluate to address those local 

transmission needs. Under this 

proposed reform, public utility 

transmission providers would be 

required to establish an iterative process 

that would ensure that stakeholders 

have meaningful opportunities to 

participate and provide feedback on 

local transmission planning throughout 

the regional transmission planning 

process. Leveraging the existing 

stakeholder processes for regional 

transmission planning, we propose to 

require that the regional transmission 

planning process include at least three 

stakeholder meetings concerning the 

local transmission planning process of 

each public utility transmission 

provider that is a member of the 

transmission planning region before 

each public utility transmission 

provider’s local transmission plan can 

be incorporated into the transmission 

planning region’s planning models, as 

described further below. 

401. Specifically, prior to the 

submission of local transmission 

planning information to the 

transmission planning region for 

inclusion in the regional transmission 

planning process, public utility 

transmission providers in each 

transmission planning region would be 

required to convene, collectively, as part 

of the regional transmission planning 

process, a stakeholder meeting to review 

the criteria, assumptions, and models 

related to each public utility 

transmission provider’s local 

transmission planning (Assumptions 

Meeting). Next, no fewer than 25 

calendar days after the Assumptions 

Meeting, public utility transmission 

providers that are members of the 

transmission planning region would be 

required to convene, collectively, as part 

of the regional transmission planning 

process, a stakeholder meeting to review 

identified reliability criteria violations 

and other transmission needs that drive 

the need for local transmission facilities 

(Needs Meeting). Finally, no fewer than 

25 calendar days after the Needs 

Meeting, public utility transmission 

providers that are members of the 

transmission planning region would be 

required to convene, collectively, as part 

of the regional transmission planning 

process, a stakeholder meeting to review 

potential solutions to those reliability 

criteria violations and other 

transmission needs (Solutions Meeting). 

Additionally, we propose to require that 

all materials for stakeholder review 

during these three meetings be publicly 

posted and that stakeholders have 

opportunities before and after each 

meeting to submit comments. 

402. We preliminarily find that these 

proposed requirements will result in 

needed additional transparency into 

local transmission planning processes, 

which inform the regional transmission 

planning process in a transmission 

planning region. We believe that these 

proposed requirements are needed to 

ensure just and reasonable Commissionjurisdictional rates because the 

information provided will better 

facilitate the identification of regional 

transmission facilities that may be more 

efficient or cost-effective than proposed 

local transmission facilities through the 

regional transmission planning process. 

We also believe that these proposed 

requirements are needed to ensure just 

and reasonable and not unduly 

discriminatory or preferential 

Commission-jurisdictional rates because 

the information provided will enable 

customers and other stakeholders alike 

to evaluate or replicate the findings of 

public utility transmission providers so 

as to reduce after-the-fact disputes 

regarding whether local transmission 

planning has been conducted in an 

unjust and unreasonable or unduly 

discriminatory or preferential 

fashion.647

403. We also propose to require that, 

as part of each Long-Term Regional 

Transmission Planning cycle, public 

utility transmission providers in each 

transmission planning region evaluate 

whether transmission facilities 

operating at or above 230 kV that an 

individual public utility transmission 

provider that owns the transmission 

facility anticipates replacing in-kind 

with a new transmission facility during 

the next 10 years can be ‘‘right-sized’’ to 

more efficiently or cost-effectively 

address regional transmission needs 


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648 Grid Strategies LLC, Advanced Conductors on 

Existing Transmission Corridors to Accelerate Low 

Cost Decarbonization, at 2 (Mar. 2022), https:// 

gridprogress.files.wordpress.com/2022/03/ 

advanced-conductors-on-existing-transmissioncorridors-to-accelerate-low-costdecarbonization.pdf. 

649We note that in RTOs/ISOs, the RTO/ISO is 

the public utility transmission provider. Each 

individual transmission-owning member of the 

RTO/ISO generally has the responsibility to 

maintain its own existing transmission facilities 

and thus would have the obligation to provide 

replacement estimates to the RTO/ISO. 

650We note that benefits associated with rightsizing potential replacement transmission facilities 

to address transmission needs identified through 

Long-Term Regional Transmission Planning should 

be evaluated the same as any potential transmission 

facility that could address that transmission need. 

See supra Regional Transmission Planning: 

Proposed Reforms, Evaluation of the Benefits of 

Regional Transmission Facilities. 

651See supra Regional Transmission Planning: 

Proposed Reforms, Selection of Regional 

Transmission Facilities. 

652Similarly, nothing in this proposed rule would 

alter existing law concerning subsequent 

proceedings involving an in-kind asset replacement, 

e.g., state-law siting proceedings. 

identified in Long-Term Regional 

Transmission Planning. By ‘‘rightsizing’’ we mean the process of 

modifying a public utility transmission 

provider’s in-kind replacement of an 

existing transmission facility to increase 

that facility’s transfer capability. Rightsizing could include, for example, 

increasing the transmission facility’s 

voltage level, adding circuits to the 

towers (e.g., redesigning a single-circuit 

line as a double-circuit line), or 

incorporating advanced technologies 

(such as advanced conductor 

technologies).648

404. As part of this proposed reform, 

first, we propose to require that, at a 

specified point early in each Long-Term 

Regional Transmission Planning cycle, 

each public utility transmission 

provider submit, as part of the regional 

transmission planning process, a list of 

each existing transmission facility 

operating at or above 230 kV that the 

public utility transmission provider 

owns and that it estimates may need to 

be replaced with a new in-kind 

transmission facility over the next 10 

years, starting from the point in the 

transmission planning cycle when the 

list is compiled (which we refer to as 

‘‘in-kind replacement estimates’’).649

405. Second, we propose to require 

that public utility transmission 

providers in each transmission planning 

region, as part of Long-Term Regional 

Transmission Planning, review and 

evaluate whether the existing 

transmission facilities included in each 

public utility transmission owner’s inkind replacement estimates can be rightsized to address a transmission need 

identified in Long-Term Regional 

Transmission Planning. 

406. We preliminarily find that an 

existing transmission facility operating 

at or above 230 kV that a public utility 

transmission provider indicates may 

need to be replaced over the next 10 

years is the type of facility that is best 

suited to be considered for right-sizing 

as part of Long-Term Regional 

Transmission Planning. We believe that 

in-kind replacement transmission 

facilities that will operate at or above 

230 kV are the most likely candidates 

for right-sizing, i.e., are most susceptible 

to modification that could more 

efficiently or cost-effectively meet 

transmission needs identified through 

Long-Term Regional Transmission 

Planning. We also believe that 10 years 

is an appropriate timeframe to evaluate 

potential in-kind replacements for rightsizing to balance the long lead times 

necessary to construct large 

transmission facilities with the 

uncertainty associated with the exact 

timing when aging transmission assets 

may need to be replaced. A right-sized 

replacement transmission facility has 

the potential to both meet the individual 

public utility transmission provider’s 

responsibility to maintain the reliability 

of its existing transmission system and 

address a regional transmission need(s) 

identified in Long-Term Regional 

Transmission Planning more efficiently 

or cost-effectively. In addition, a rightsized replacement transmission facility 

may defer or displace the need for other 

transmission facilities, including both 

new transmission facilities and in-kind 

replacement of existing transmission 

facilities, thus representing a benefit to 

the public utility transmission provider 

and its customers. We believe that if 

opportunities for right-sized 

replacement transmission facilities are 

not considered, regional transmission 

planning processes may not select the 

more efficient or cost-effective 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation to meet transmission needs 

identified through Long-Term Regional 

Transmission Planning.650

407. The process under this proposed 

reform would entail the following steps. 

First, sufficiently early in each LongTerm Regional Transmission Planning 

cycle, each public utility transmission 

provider would submit its in-kind 

replacement estimates for use in LongTerm Regional Transmission Planning. 

Then, if a right-sized replacement 

transmission facility is identified as a 

potential solution to a Long-Term 

Regional Transmission Planning need, 

that right-sized replacement 

transmission facility would be evaluated 

in the same manner as any other 

proposed transmission facility to 

determine whether it is the more 

efficient or cost-effective transmission 

facility to address the transmission 

need. If a right-sized replacement 

transmission facility addresses the 

public utility transmission provider’s 

need to replace an existing transmission 

facility, meets all the applicable 

selection criteria included in Long-Term 

Regional Transmission Planning, and is 

found to be the more efficient or costeffective solution to a transmission need 

identified through Long-Term Regional 

Transmission Planning, then the rightsized replacement transmission facility 

may be selected in the regional 

transmission plan for purposes of cost 

allocation.651

408. Although the right-sized 

replacement transmission facility may 

be selected in the regional transmission 

plan for purposes of cost allocation, it 

is necessary that a selected right-sized 

replacement transmission facility be 

subject to different rules with respect to 

the elimination of a federal right of first 

refusal than other regional transmission 

facilities. Absent reform, if a public 

utility transmission provider’s estimated 

in-kind replacement were right-sized 

and then selected in the regional 

transmission plan for purposes of cost 

allocation to meet transmission needs 

identified through Long-Term Regional 

Transmission Planning, the right-sized 

replacement transmission facility might 

then be subject to the transmission 

planning region’s competitive 

transmission development process. 

However, the public utility transmission 

provider would not necessarily be 

bound by that right-sizing decision 

made by the region, unless the public 

utility transmission provider was 

selected to develop the right-sized 

replacement transmission facility. This 

is because nothing in this proposed rule 

would alter existing law concerning the 

public utility transmission provider’s 

ability to proceed with developing its 

planned in-kind replacement 

transmission facility without the rightsizing, in spite of the potential 

efficiencies of right-sizing identified in 

the regional transmission planning 

process.652 This may reduce the 

opportunities for the regional 

transmission planning process to 

identify more efficient or cost-effective 

solutions to transmission needs 

identified through Long-Term Regional 

Transmission Planning and potentially 

lead to duplicative or inefficient 

transmission development. 


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653See, e.g., PJM, Intra-PJM Tariffs, OATT, attach. 

M–3, OATT Attachment M–3 (1.0.0), § (d)(1)(iii) 

(providing that every year ‘‘each Transmission 

Owner will provide to PJM a Candidate [End-of-Life 

(EOL)] Needs List comprising its non-public 

confidential, non-binding projection of up to 5 

years of EOL Needs that it has identified under the 

Transmission Owner’s processes for identification 

of EOL Needs’’ and that each ‘‘Transmission Owner 

may change its projection as it deems necessary and 

will update it annually’’). 

654Order No. 1000, 136 FERC ¶ 61,051 at P 262; 

Order No. 1000–A, 139 FERC ¶ 61,132 at PP 366, 

379, 425, 428. 

655See supra P 412. 

656See supra Regional Transmission Planning: 

Proposed Reforms, Selection of Regional 

Transmission Facilities. 

409. In addition, requiring in-kind 

replacement estimates to cover the next 

10 years, starting from the point in the 

transmission planning cycle when the 

list is compiled, may lengthen the time 

horizon over which in-kind replacement 

needs are assessed, compared to current 

practices where in-kind replacement 

needs may be assessed on a shorter-term 

or nearer-term basis.653 Accordingly, 

areas of uncertainty that could lessen 

the accuracy of a public utility 

transmission provider’s in-kind 

replacement estimates should be 

minimized where possible. In 

particular, such an approach that looks 

out over 10 years, would allow the 

public utility transmission provider to 

formulate in-kind replacement estimates 

with greater certainty as to its own 

future role in meeting that transmission 

need. Therefore, for any right-sized 

replacement transmission facility that is 

selected in the regional transmission 

plan for purposes of cost allocation to 

meet transmission needs identified 

through Long-Term Regional 

Transmission Planning, we propose to 

require the establishment of a federal 

right of first refusal for the public utility 

transmission provider that included the 

in-kind replacement transmission 

facility in its in-kind replacement 

estimates, which would extend to any 

portion of such a transmission facility 

located within the applicable public 

utility transmission provider’s retail 

distribution service territory or 

footprint. 

410. With respect to cost allocation, 

we propose that if a right-sized 

replacement transmission facility is 

selected in the regional transmission 

plan for purposes of cost allocation, 

only the incremental costs of rightsizing the transmission facility will be 

eligible to use the applicable Long-Term 

Regional Transmission Cost Allocation 

Method. We propose that the costs the 

incumbent transmission provider would 

have otherwise incurred to construct the 

in-kind replacement transmission 

facility be allocated in a manner 

consistent with the allocation that 

would have otherwise occurred for the 

in-kind replacement. We preliminarily 

find that it is just and reasonable and 

not unduly discriminatory or 

preferential for only the portion of the 

costs associated with right-sizing a 

right-sized replacement transmission 

facility that is selected in the regional 

transmission plan for purposes of cost 

allocation to be eligible to use the LongTerm Regional Transmission Cost 

Allocation Method because it is the 

right-sizing of the in-kind replacement 

transmission facility that allows the 

transmission facility to meet the 

transmission need(s) identified in LongTerm Regional Transmission Planning. 

In addition, the customers of the public 

utility transmission provider that would 

be allocated the costs associated with 

the original in-kind replacement 

transmission facility would have 

otherwise been responsible for paying 

those costs had the replacement 

transmission facility not been rightsized. 

411. We note that Order No. 1000 

allows a public utility transmission 

provider to meet its reliability needs or 

service obligations by choosing to build 

new transmission facilities that are 

located solely within its retail 

distribution service territory or footprint 

and that are not selected in the regional 

transmission plan for purposes of cost 

allocation.654 Similarly, nothing in the 

reforms that we propose here alters 

existing law concerning a public utility 

transmission provider’s existing rights 

and responsibilities with respect to 

maintaining, and when necessary 

replacing, existing transmission 

facilities. Thus, the proposed 

requirements for public utility 

transmission providers to provide 

greater transparency and stakeholder 

process surrounding local transmission 

planning and in-kind replacement 

estimates would not create an obligation 

for an incumbent transmission provider 

to actually replace any existing 

transmission facilities. We believe that 

this clarification is important given that 

decisions related to replacement of 

existing transmission facilities may 

change as a public utility transmission 

provider gets better information about 

the condition of its transmission 

facilities. 

412. Even if a right-sized replacement 

transmission facility is selected in the 

regional transmission plan for purposes 

of cost allocation to meet transmission 

needs identified in Long-Term Regional 

Transmission Planning, that selection 

does not alter existing law concerning 

any existing rights and responsibilities a 

public utility transmission provider may 

have to replace as needed its existing 

transmission facilities with in-kind 

replacement transmission facilities. For 

example, a public utility transmission 

provider could inform the transmission 

planning region that, notwithstanding 

the selection of a right-sized 

replacement transmission facility in the 

regional transmission plan for purposes 

of cost allocation, the public utility 

transmission provider has chosen to 

build the original in-kind replacement 

transmission facility instead. In such 

cases, as we explain earlier,655 we 

understand that, depending on the rules 

of the particular regional transmission 

planning process, the in-kind 

replacement transmission facility may 

be included in the regional transmission 

plan for informational purposes, but not 

selected in the regional transmission 

plan for purposes of cost allocation. 

413. Our proposal to only allow the 

incremental costs of right-sizing 

replacement transmission facilities to be 

eligible to use the applicable Long-Term 

Regional Transmission Cost Allocation 

Method emphasizes the need for 

transparency in regional transmission 

planning processes so as to clearly 

determine which right-sized 

replacement transmission facilities have 

been selected in the regional 

transmission plan for purposes of cost 

allocation.656 Therefore, we propose to 

require public utility transmission 

providers in each transmission planning 

region to amend their regional 

transmission planning processes to 

provide transparency with respect to 

which right-sized replacement 

transmission facilities have been 

selected in the regional transmission 

plan for purposes of cost allocation (and 

thus found to be a more efficient or costeffective transmission facility to meet 

regional transmission needs) and which 

transmission facilities are simply 

included in the regional transmission 

plan for informational (and not cost 

allocation) purposes. We believe that 

this additional transparency would 

inform interested parties, including 

state regulators, regarding the degree to 

which a right-sized replacement 

transmission facility was evaluated 

through Long-Term Regional 

Transmission Planning. As such, we 

believe that this additional transparency 

ensures just and reasonable 

Commission-jurisdictional rates because 

the information provided will enable 

customers and other stakeholders alike 

to evaluate or replicate the findings 

related to right-sized replacement 

transmission facilities or in-kind 


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657 In Order No. 1000, the Commission defined an 

interregional transmission facility as a transmission 

facility that is located in two or more transmission 

planning regions. Order No. 1000, 136 FERC 

¶ 61,051 at P 482 n.374. 

658 Id. PP 393–399. 

659 Id. P 436. 

660 Id. 

661 Id. P 437; Order No. 1000–A, 139 FERC 

¶ 61,132 at PP 506, 510. 

662Order No. 1000, 136 FERC ¶ 61,051 at P 400; 

Order No. 1000–A, 139 FERC ¶ 61,132 at P 509. 

663Order No. 1000, 136 FERC ¶ 61,051 at PP 443, 

635. 

664 Id. P 578. 

665 Id. P 603. 

666ANOPR, 176 FERC ¶ 61,024 at PP 57, 62–64. 

667 Id. P 64. 

replacement transmission facilities so as 

to reduce after-the-fact disputes 

regarding transmission system needs or 

cost allocation. 

414. We seek comment on the 

requirements proposed in this section of 

the NOPR. In particular, we seek 

comment on whether the Commission 

should impose any requirements 

regarding how the relevant public utility 

transmission providers would 

determine incremental costs of rightsizing the transmission facility. 

415. We also seek comment on 

whether there is additional information 

from transmission owners that would 

help public utility transmission 

providers to identify whether there are 

estimated in-kind replacements of an 

existing transmission facility that could 

be right-sized to address a transmission 

need identified in Long-Term Regional 

Transmission Planning. If so, we seek 

comment what level of burden such a 

requirement would impose on the 

transmission owners required to provide 

that information, and what level of 

burden is justified given the potential 

benefits of such information. Moreover, 

we seek comment on whether there is 

additional information beyond a list of 

in-kind replacement estimates that 

public utility transmission providers 

need to calculate such benefits and, if 

so, how that information could be 

obtained. 

IX. Interregional Transmission 

Coordination and Cost Allocation 

416. In the ANOPR, the Commission 

asked several questions about the value 

and logistics of reforms to interregional 

transmission coordination, planning, 

and cost allocation. The Commission 

continues to examine those issues, 

including review of comments to the 

ANOPR, and to consider possible 

reforms. As such, we do not, at this 

time, propose changes to the existing 

interregional transmission coordination 

and cost allocation requirements of 

Order No. 1000. However, we propose 

to require that public utility 

transmission providers revise their 

existing interregional transmission 

coordination procedures adopted in 

compliance with Order No. 1000 to 

apply them to the proposed Long-Term 

Regional Transmission Planning reforms 

in this NOPR, as discussed below. 

A. Background 

417. In Order No. 1000, the 

Commission set out a number of 

requirements for interregional 

transmission coordination and 

interregional cost allocation.657 Order 

No. 1000 requires public utility 

transmission providers in neighboring 

transmission planning regions to 

develop and implement procedures to 

provide for: (1) The sharing of 

information regarding the respective 

transmission needs of each region and 

potential solutions to those needs; and 

(2) the identification and joint 

evaluation of interregional transmission 

facilities that may be more efficient or 

cost-effective transmission facilities 

needed to meet those regional needs.658

418. With regard to the evaluation of 

interregional transmission facilities, 

Order No. 1000 requires public utility 

transmission providers in neighboring 

transmission planning regions to 

develop and implement formal 

procedures to identify and jointly 

evaluate transmission facilities that are 

proposed to be located in neighboring 

transmission planning regions.659 The 

Commission clarified that the developer 

of an interregional transmission facility 

must first propose its transmission 

facility in the regional transmission 

planning processes of each of the 

neighboring transmission planning 

regions in which the transmission 

facility is proposed to be located. The 

submission of the interregional 

transmission facility in each regional 

transmission planning process triggers 

the procedure under which the public 

utility transmission providers, acting 

through their regional transmission 

planning process, jointly evaluate the 

proposed transmission project.660

419. The Commission further 

required, inter alia, that interregional 

transmission coordination procedures 

must have a process by which 

differences in the data, models, 

assumptions, planning horizons, and 

criteria used to study a proposed 

transmission project can be identified 

and resolved for purposes of jointly 

evaluating the proposed interregional 

transmission facility.661

420. With regard to transmission 

facility selection, Order No. 1000 

requires that an interregional 

transmission facility must be selected in 

both of the relevant regional 

transmission plans for purposes of cost 

allocation in order to be eligible for 

interregional cost allocation.662 The 

Commission further clarified that based 

on the information gained during the 

joint evaluation of an interregional 

transmission project, each transmission 

planning region will determine, for 

itself, whether to select those 

interregional transmission facilities 

within its footprint in the regional 

transmission plan for purposes of cost 

allocation.663

421. With respect to interregional cost 

allocation, the Commission required 

that each public utility transmission 

provider in a transmission planning 

region must have, together with the 

public utility transmission providers in 

its own transmission planning region 

and a neighboring transmission 

planning region, a common method or 

methods for allocating the costs of a 

new interregional transmission facility 

among the beneficiaries of that 

transmission facility in the two 

neighboring transmission planning 

regions in which the transmission 

facility is located.664 The Commission 

also defined six interregional cost 

allocation principles that apply to, and 

only to, a cost allocation method or 

methods for a new interregional 

transmission facility.665

B. ANOPR 

422. In the ANOPR, the Commission 

asked several questions about the value 

and logistics of reforms to interregional 

transmission coordination, planning, 

and cost allocation. Specifically, the 

Commission sought comment on 

whether greater interregional or stateregional coordination is required to 

address other topics in the ANOPR, 

including long-term regional 

transmission planning, identifying 

geographic zones that have the potential 

for the development of large amounts of 

new generation, and incentives for 

transmission development.666 The 

Commission also sought comment on 

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 interregional transmission 

coordination.667 Further, the 

Commission sought comment on 

whether to require joint transmission 

planning processes for neighboring 

transmission planning regions, rather 

than simply joint coordination, and 


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668 Id. PP 62–63. 

669See, e.g., ACEG Comments at 4–5; ACORE 

Comments at 27; ACPA and ESA Comments at 51– 

52; Advanced Power Comments at 2; AEE 

Comments at 31; AEP Comments at 18–24; Amazon 

Comments at 2; American Municipal Power 

Comments at 33; Anbaric Comments at 30–32; 

Avangrid Comments at 20–21; Arizona Commission 

Comments at 4; Competition Coalition Comments at 

20; Consumers Council Comments at 10–11; EDF 

Comments at 8; Eversource Comments at 18–19; 

Kansas Commission Comments at 2; LS Power Oct. 

12 Comments at 63; NARUC Comments at 16–19; 

Nature Conservancy Comments at 9–10; New Jersey 

Commission Comments at 2; NY TOs Comments at 

25–26; Northwest and Intermountain Comments at 

30; PG&E Comments at 7; PIOs Comments at 70– 

72; Policy Integrity Comments at 16–18; REBA 

Comments at 17; Resale Iowa Comments at 15; RMI 

Comments at 3–4; State Agencies Comments at 28– 

30; State of Massachusetts Comments at 21; U.S. 

DOE Comments at 25–26; Xcel Comments at 22. 

670See, e.g., APPA Comments at 5; CAISO 

Comments at 6–8, 59–63; LPPC Comments at 24– 

26; MISO Comments at 2–3, 15–16; MISO TOs 

Comments at 16–18; NYISO Comments at 56–57; 

PJM Comments at 68. 

671Order No. 1000, 136 FERC ¶ 61,051 at P 369. 

672 Id. P 368. 

673 Id. 

674As noted earlier, we are not proposing to 

require any changes to existing interregional cost 

allocation methods for interregional transmission 

facilities that are selected in the regional 

transmission plan for purposes of cost allocation 

and that the Commission previously accepted as 

compliant with Order No. 1000. 

675See Order No. 1000, 136 FERC ¶ 61,051 at PP 

99–117 (explaining the Commission’s legal basis for 

requiring interregional transmission coordination 

and interregional cost allocation). 

whether the Commission should 

establish interregional reliability 

planning criteria.668

C. Comments 

423. Some commenters urge the 

Commission to require substantial 

changes to the existing interregional 

transmission coordination requirements 

established in Order No. 1000.669 Other 

commenters instead urge the 

Commission to maintain the existing 

interregional transmission coordination 

requirements.670

D. Need for Reform 

424. In establishing the Order No. 

1000 interregional transmission 

coordination and cost allocation 

requirements, the Commission 

considered the requirements of Order 

No. 890, determining that the 

transmission planning requirements of 

Order No. 890 were too narrowly 

focused geographically and failed to 

provide for adequate analysis of the 

benefits associated with interregional 

transmission facilities in neighboring 

transmission planning regions.671 The 

Commission stated that ‘‘in the absence 

of coordination between transmission 

planning regions, public utility 

transmission providers may be unable to 

identify more efficient or cost-effective 

solutions to the individual needs 

identified in their respective local and 

regional transmission planning 

processes, potentially including 

interregional transmission facilities.’’ 672

Therefore, the Commission concluded 

that interregional transmission 

coordination reforms were necessary. 

The Commission stated that ‘‘[c]lear and 

transparent procedures that result in the 

sharing of information regarding 

common needs and potential solutions 

across the seams of neighboring 

transmission planning regions will 

facilitate the identification of 

interregional transmission facilities that 

more efficiently or cost-effectively could 

meet the needs identified in individual 

regional transmission plans.’’ 673

425. Based upon our experience since 

Order No. 1000 and the record in this 

proceeding, we continue to believe that 

there is a significant need for 

interregional transmission coordination. 

We therefore preliminarily find that it is 

necessary to revise the existing Order 

No. 1000 interregional transmission 

coordination requirements to apply 

them to the proposed Long-Term 

Regional Transmission Planning reforms 

in this NOPR to ensure that 

interregional transmission coordination 

is just and reasonable. We believe that 

the reforms we propose here will ensure 

that the information sharing and 

evaluation of interregional transmission 

facilities required as part of the existing 

interregional transmission coordination 

procedures will continue to occur with 

respect to all aspects of the regional 

transmission planning process, 

including the proposed Long-Term 

Regional Transmission Planning. 

E. Proposed Reform 

426. We propose to require that public 

utility transmission providers revise 

their existing interregional transmission 

coordination procedures to reflect the 

Long-Term Regional Transmission 

Planning reforms proposed in this 

NOPR.674

427. Specifically, we propose to 

require that public utility transmission 

providers in neighboring transmission 

planning regions revise their existing 

interregional coordination procedures 

(and regional transmission planning 

processes as needed) to provide for: (1) 

The sharing of information regarding the 

respective transmission needs identified 

in the Long-Term Regional 

Transmission Planning that we propose 

to require in that section above, as well 

as potential transmission facilities to 

meet those needs; and (2) the 

identification and joint evaluation of 

interregional transmission facilities that 

may be more efficient or cost-effective 

transmission facilities to address 

transmission needs identified through 

Long-Term Regional Transmission 

Planning. 

428. We also propose to require that 

public utility transmission providers in 

neighboring transmission planning 

regions revise their interregional 

transmission coordination procedures 

(and regional transmission planning 

processes as needed) to allow an entity 

to propose an interregional transmission 

facility in the regional transmission 

planning process as a potential solution 

to transmission needs identified through 

Long-Term Regional Transmission 

Planning. We believe that this will align 

the existing requirement for an entity to 

propose an interregional transmission 

facility in the regional transmission 

planning processes of each of the 

neighboring transmission planning 

regions in which the transmission 

facility is proposed to be located with 

the proposed requirement for public 

utility transmission providers to 

conduct Long-Term Regional 

Transmission Planning as part of their 

regional transmission planning 

processes. 

429. This proposed reform aims to 

ensure that transmission needs driven 

by changes in the resource mix and 

demand identified through Long-Term 

Regional Transmission Planning can be 

considered in existing interregional 

transmission coordination and cost 

allocation processes.675 Doing so will 

ensure that there is an opportunity for 

the public utility transmission providers 

in neighboring transmission planning 

regions to consider whether there are 

interregional transmission facilities that 

could more efficiently or cost-effectively 

meet the transmission needs identified 

through Long-Term Regional 

Transmission Planning, in turn helping 

to ensure just and reasonable 

Commission-jurisdictional rates. 

X. Proposed Compliance Procedures 

430. Given the necessity to coordinate 

with the relevant state entities and other 

stakeholders on the proposed reforms, 

we propose an extended compliance 

period. We propose to require that each 

public utility transmission provider 

submit a compliance filing within eight 

months of the effective date of any final 

rule in this proceeding revising its 

OATT and other document(s) subject to 

the Commission’s jurisdiction as 

necessary to demonstrate that it meets 

the proposed requirements set forth in 


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676See Appendix B for the proposed pro forma 

Attachment K consistent with this NOPR. 

677Order No. 888, FERC Stats. & Regs. ¶ 31,036 

at 31,760–63. 

678 44 U.S.C. 3507(d). 

679 5 CFR 1320.11. 

680The transmission service provider (TSP) 

function is a NERC registration function which is 

similar to the transmission provider that is 

referenced in the pro forma OATT. The TSP 

function is being used as a proxy to estimate the 

number of transmission providers that are impacted 

by this proposed rulemaking. 

681The number of entities listed from the NERC 

Compliance Registry reflects the omission of the 

Texas RE registered entities. Note that 41 

transmission owners in non-RTO/ISO regions are 

also transmission service providers, so in total there 

are 125 entities subject to this proposed rulemaking. 

682 ‘‘Burden’’ is the total time, effort, or financial 

resources expended by persons to generate, 

maintain, retain, or disclose or provide information 

to or for a Federal agency. For further explanation 

of what is included in the information collection 

burden, refer to 5 CFR 1320.3. 

this NOPR and are included in any final 

rule in this proceeding.676

431. The Commission would assess 

whether each compliance filing satisfies 

the proposed requirements outlined 

above and issue additional orders as 

necessary to ensure that each public 

utility transmission provider meets the 

requirements of any final rule in this 

proceeding. 

432. We propose that transmission 

providers that are not public utilities 

would have to adopt the requirements of 

this NOPR as a condition of maintaining 

the status of their safe harbor tariff or 

otherwise satisfying the reciprocity 

requirement of Order No. 888.677

433. The Commission will ensure that 

jurisdictional entities comply with these 

NOPR requirements upon final action of 

the Commission and has the authority to 

conduct audits to evaluate such 

compliance. Section 302(C) of the 

Federal Power Act allows the 

Commission staff to examine the books, 

accounts, memoranda, and records of 

any person who controls directly or 

indirectly, a licensee or public utility 

subject to the jurisdiction of the 

Commission insofar as they relate to 

transactions with or the business of 

such licensee or public utility. 

XI. Information Collection Statement 

434. The information collection 

requirements contained in this NOPR 

are subject to review by the Office of 

Management and Budget (OMB) under 

section 3507(d) of the Paperwork 

Reduction Act of 1995.678 OMB’s 

regulations require approval of certain 

information collection requirements 

imposed by agency rules.679 Upon 

approval of a collection of information, 

OMB will assign an OMB control 

number and expiration date. 

Respondents subject to the filing 

requirements of this rule will not be 

penalized for failing to respond to these 

collections of information unless the 

collections of information display a 

valid OMB control number. 

435. This NOPR would, pursuant to 

section 206 of the FPA, reform the 

Commission’s pro forma OATT and the 

Commission’s pro forma LGIP to correct 

deficiencies in the Commission’s 

existing regional transmission planning 

and cost allocation requirements so that 

the transmission system can better 

support wholesale power markets and 

thereby ensure that Commissionjurisdictional rates remain just and 

reasonable and not unduly 

discriminatory or preferential. 

436. Interested persons may obtain 

information on the reporting 

requirements by contacting Ellen 

Brown, Office of the Executive Director, 

Federal Energy Regulatory Commission, 

888 First Street NE, Washington, DC 

20426 via email (DataClearance@

ferc.gov) or telephone (202) 502–8663). 

437. The Commission solicits 

comments on the Commission’s need for 

this information, whether the 

information will have practical utility, 

the accuracy of the burden estimates, 

ways to enhance the quality, utility, and 

clarity of the information to be collected 

or retained, and any suggested methods 

for minimizing respondents’ burden, 

including the use of automated 

information techniques. 

438. Please send comments 

concerning the collections of 

information and the associated burden 

estimates to the Office of Information 

and Regulatory Affairs, Office of 

Management and Budget, through 

www.reginfo.gov/public/do/PRAMain. 

Attention: Federal Energy Regulatory 

Commission Desk Officer. Please 

identify the OMB Control Numbers 

1902–0233 and 1902–0096 in the 

subject line of your comments. 

Comments should be sent within 60 

days of publication of this notice in the 

Federal Register. 

439. Please submit a copy of your 

comments on the information 

collections to the Commission via the 

eFiling link on the Commission’s 

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

Comments on the information collection 

that are sent to FERC should refer to 

Docket No. RM21–17–000. 

440. Title: Electric Transmission 

Facilities (FERC–917) and Electric Rate 

Schedules and Tariff Filings (FERC– 

516). 

441. Action: Proposed revision of 

collections of information in accordance 

with Docket No. RM21–17–000 and 

request for comments. 

442. OMB Control Nos.: 1902–0233 

(FERC–917) and 1902–0096 (FERC– 

516). 

443. Respondents: Public utility 

transmission providers, including 

RTOs/ISOs, and public utility 

transmission owners. 

444. Frequency of Information 

Collection: One time during Year 1. 

Occasional times during subsequent 

years, at least once every three years. 

445. Necessity of Information: The 

reforms in this Proposed Rule will 

correct deficiencies in the Commission’s 

existing regional transmission planning 

and cost allocation requirements so that 

the transmission system can better 

support wholesale power markets and 

thereby ensure that Commissionjurisdictional rates remain just and 

reasonable and not unduly 

discriminatory or preferential. 

446. Internal Review: The 

Commission has reviewed the changes 

and has determined that such changes 

are necessary. These requirements 

conform to the Commission’s need for 

efficient information collection, 

communication, and management 

within the energy industry. The 

Commission has specific, objective 

support for the burden estimates 

associated with the information 

collection requirements. 

447. Our estimates are based on the 

NERC Compliance Registry as of March 

3, 2022, which indicates that there are 

48 transmission service providers 680

and 118 transmission owners that are 

registered within the United States and 

are subject to this proposed 

rulemaking.681

448. Public Reporting Burden: The 

burden and cost estimates below are 

based on the need for applicable entities 

to revise documentation, already 

required by the Commission’s pro forma 

OATT and the Commission’s pro forma 

LGIP. 

449. The Commission estimates that 

the NOPR would affect the burden 682

and cost of FERC–917 and FERC–516 as 

follows: 


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683 In the table, Year 1 figures are one-time 

implementation hours and cost. ‘‘Subsequent years’’ 

show ongoing burdens and costs starting in Year 2. 

684The hourly cost (for salary plus benefits) uses 

the figures from the Bureau of Labor Statistics (BLS) 

for three positions involved in the reporting and 

recordkeeping requirements. These figures include 

salary (based on BLS data for May 2020, https:// 

bls.gov/oes/current/naics2_22.htm) and benefits 

(based on BLS data for December 2020; issued 

March 18, 2021, https://www.bls.gov/news.release/ 

ecec.nr0.htm) and are Manager (Occupation Code 

11–0000, $97.89/hour), Electrical Engineer 

(Occupation Code 17–2071, $72.15/hour), and File 

Clerk (Occupation Code 43–4071, $35.83/hour). The 

hourly cost for the reporting requirements ($85.00) 

is an average of the hourly cost (wages plus 

benefits) of a manager and engineer. The hourly 

cost for recordkeeping requirements uses the cost of 

a file clerk. 

685Reguls. Implementing the Nat’l Envt’l Pol’y 

Act, Ord. No. 486, 52 FR 47897 (Dec. 17, 1987), 

FERC Stats. & Regs. 30,783 (1987) (cross-referenced 

at 41 FERC ¶ 61,284). 

686 18 CFR 380.4(a)(15). 

687 5 U.S.C. 601–612. 

688 13 CFR 121.201. 

689The RFA definition of ‘‘small entity’’ refers to 

the definition provided in the Small Business Act, 

which defines a ‘‘small business concern’’ as a 

business that is independently owned and operated 

and that is not dominant in its field of operation. 

The Small Business Administrations’ regulations at 

13 CFR 121.201 define the threshold for a small 

Electric Bulk Power Transmission and Control 

entity (NAICS code 221121) to be 500 employees. 

See 5 U.S.C. 601(3), citing to section 3 of the Small 

Business Act, 15 U.S.C. 632. 

PROPOSED CHANGES IN NOPR IN DOCKET NO. RM21–17–000 683

Area of modification Annual number of 

respondents 

Total annual 

estimated 

number of 

responses 

Average burden hours 

& cost 684 per response 

Total estimated 

burden hours & 

total estimated cost 

(column C × column D) 

A B C D E 

FERC–917, Electric Transmission Facilities 

(OMB Control No. 1902–0233) 

Participate in Long-Term Regional Transmission 

Planning, which includes developing LongTerm Scenarios, evaluating the benefits of regional transmission facilities, and establishing 

criteria in consultation with states to select 

transmission facilities in the regional transmission plan for purposes of cost allocation.

125 (TSPs and TOs) .... 125 Year 1: 150 hours; $11,275 ........

Subsequent Years: 50 hours per 

year; $3,758 per year.

Year 1: 18,750 hours; 

$1,409,363. 

Subsequent Years: 6,250 hours 

per year; $469,788 per year. 

Revise the regional transmission planning process to enhance transparency of local transmission planning and identifying potential opportunities to right-size replacement transmission facilities.

125 (TSPs and TOs) .... 125 Year 1: 20 hours; $1,208 ............

Subsequent Years: 50 hours per 

year; $3,758 per year.

Year 1: 2,500 hours; $151,038. 

Subsequent Years: 6,250 hours 

per year; $469,788 per year. 

Seek agreement from the states to establish a 

Long-Term Regional Transmission Cost Allocation Method and/or a State Agreement Process.

125 (TSPs and TOs) .... 125 Year 1: 150 hours; $11,275 ........

Subsequent Years: 50 hours per 

year; $3,758 per year.

Year 1: 18,750 hours; 

$1,409,363. 

Subsequent Years: 6,250 hours 

per year; $469,788 per year. 

Consider in the regional transmission planning 

processes regional transmission facilities that 

address certain interconnection-related needs.

125 (TSPs and TOs) .... 125 Year 1: 50 hours; $3,758 ............

Subsequent Years: 0 hours per 

year; $0 per year.

Year 1: 6,250 hours; $469,750. 

Subsequent Years: 0 hours per 

year; $0 per year. 

Revise interregional transmission coordination 

procedures to reflect Long-Term Regional 

Transmission Planning.

125 (TSPs and TOs) .... 125 Year 1: 50 hours; $3,758 ............

Subsequent Years: 25 hours per 

year; $1,715 per year.

Year 1: 6,250 hours; $469,750. 

Subsequent Years: 3,125 hours 

per year; $214,375 per year. 

FERC–516, Electric Rate Schedules and Tariff Filings 

(OMB Control No. 1902–0096) 

Revise LGIP to indicate the consideration in the 

regional transmission planning processes of regional transmission facilities that address certain interconnection-related needs.

125 (TSPs and TOs) .... 125 Year 1: 30 hours; $2,058 ............

Subsequent Years: 0 hours per 

year; $0 per year.

Year 1: 3,750 hours; $257,288. 

Subsequent Years: 0 hours per 

year; $0 per year. 

450. Our estimates conservatively 

assume the maximum number of 

respondents and burdens. We 

acknowledge that the actual burdens for 

some respondents may be lower than 

estimated, and that other respondents 

may incur the maximum burdens. We 

seek comment on the estimates in the 

burden table and on the assumptions 

described here. 

XII. Environmental Analysis 

451. The Commission is required to 

prepare an Environmental Assessment 

or an Environmental Impact Statement 

for any action that may have a 

significant adverse effect on the human 

environment.685 We conclude that 

neither an Environmental Assessment 

nor an Environmental Impact Statement 

is required for this Proposed Rule under 

section 380.4(a)(15) of the Commission’s 

regulations, which provides a 

categorical exemption for approval of 

actions under sections 205 and 206 of 

the FPA relating to the filing of 

schedules containing all rates and 

charges for the transmission or sale of 

electric energy subject to the 

Commission’s jurisdiction, plus the 

classification, practices, contracts and 

regulations that affect rates, charges, 

classifications, and services.686

XIII. Regulatory Flexibility Act 

[Analysis or Certification] 

452. The Regulatory Flexibility Act of 

1980 (RFA) 687 generally requires a 

description and analysis of proposed 

rules that will have significant 

economic impact on a substantial 

number of small entities. The Small 

Business Administration (SBA) sets the 

threshold for what constitutes a small 

business. Under SBA’s size 

standards,688 RTOs/ISOs, planning 

regions, and transmission owners all fall 

under the category of Electric Bulk 

Power Transmission and Control 

(NAICS code 221121), with a size 

threshold of 500 employees (including 

the entity and its associates).689

453. The six RTOs/ISOs (SPP, MISO, 

PJM, ISO–NE, NYISO, and CAISO) each 

employ more than 500 employees and 

are not considered small. 

454. We estimate that 119 additional 

transmission providers and 

transmission owners are affected by the 

NOPR. Using the list of transmission 

service providers and transmission 

owners from the NERC Registry (dated 

March 3, 2022), we estimate that 

approximately 68% of those entities are 

small entities. 


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690U.S. Small Business Administration, A Guide 

for Government Agencies How to Comply with the 

Regulatory Flexibility Act, at 18 (May 2012), https:// www.sba.gov/sites/default/files/advocacy/rfaguide_

0512_0.pdf. 

455. We estimate additional one-time 

costs associated with the NOPR (as 

shown in the table above) of: 

—$31,274 for each transmission 

provider and transmission owner 

(FERC–917) 

—$2,058 for each transmission provider 

and transmission owner (FERC–516) 

456. Therefore, the estimated 

additional one-time implementation 

cost in Year 1 per entity is $33,332. 

457. We estimate additional recurring 

costs in subsequent years (starting in 

Year 2) associated with the NOPR (as 

shown in the table above) of: 

—$12,989 for each transmission 

provider and transmission owner 

(FERC–917) 

—$0 for each transmission provider and 

transmission owner (FERC–516) 

458. Therefore, the estimated 

recurring costs per entity in subsequent 

years are $12,989 per year. 

459. According to SBA guidance, the 

determination of significance of impact 

‘‘should be seen as relative to the size 

of the business, the size of the 

competitor’s business, and the impact 

the regulation has on larger 

competitors.’’ 690 We do not consider the 

estimated cost to be a significant 

economic impact. As a result, we certify 

that the proposals in this NOPR will not 

have a significant economic impact on 

a substantial number of small entities. 

XIV. Comment Procedures 

460. The Commission invites 

interested persons to submit comments 

on the matters and issues proposed in 

this notice to be adopted, including any 

related matters or alternative proposals 

that commenters may wish to discuss. 

Comments are due July 18, 2022 and 

Reply Comments are due August 17, 

2022. 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. 

461. 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. 

462. 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. 

XV. Document Availability 

463. 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). 

464. From the Commission’s Home 

Page on the internet, this information is 

available on eLibrary. The full text of 

this document is available on eLibrary 

in PDF and Microsoft Word format for 

viewing, printing, and/or downloading. 

To access this document in eLibrary, 

type the docket number excluding the 

last three digits of this document in the 

docket number field. 

465. 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. 

Commissioner Danly is dissenting 

with a separate statement attached. 

Commissioner Christie is concurring 

with a separate statement attached. 

Commission Phillips is concurring 

with a separate statement attached. 

Issued: April 21, 2022. 

Debbie-Anne A. Reese, 

Deputy Secretary. 

Note: The following appendices will not be 

published in the Code of Federal Regulations. 

Appendix A: Abbreviated Names of 

Commenters 

Abbreviation Commenter 

Aaron Litz .................................................... Aaron Litz. 

ACEG ........................................................... Americans for a Clean Energy Grid. 

ACORE ........................................................ American Council on Renewable Energy. 

ACPA and ESA ........................................... American Clean Power Association and the U.S. Energy Storage Association. 

AEE .............................................................. Advanced Energy Economy. 

Advanced Power ......................................... Advanced Power Alliance. 

AEP .............................................................. American Electric Power Service Corporation. 

AES Ohio ..................................................... Dayton Power and Light. 

Alabama Commission .................................. Alabama Public Service Commission. 

Amazon ........................................................ Amazon Energy LLC. 

Ameren ........................................................ Ameren Services Company. 

American Farmland Trust ............................ American Farmland Trust. 

American Municipal Power .......................... American Municipal Power, Inc. 

Ample ........................................................... Ample, Inc. 

Anbaric ......................................................... Anbaric Development Partners, LLC. 

APPA ........................................................... American Public Power Association. 

Arizona Commission .................................... Arizona Corporation Commission. 

Arizona Public Service ................................ Arizona Public Service Company. 

Avangrid ....................................................... Avangrid. 

Berkshire ...................................................... Berkshire Hathaway Energy Company. 


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Abbreviation Commenter 

BP ................................................................ BP America Inc. 

Bridgelink ..................................................... Bridgelink Investments, LLC. 

Business Council for Sustainable Energy ... Business Council for Sustainable Energy. 

CAISO .......................................................... California Independent System Operator Corporation. 

California Commission ................................. California Public Utilities Commission. 

California Municipal Utilities ........................ California Municipal Utilities Association. 

California Water ........................................... California Department of Water Resources State Water Project. 

CBD ............................................................. The Center for Biological Diversity. 

Center for Sustainable Energy .................... Center for Sustainable Energy. 

Certain TDUs ............................................... Alliant Energy Corporate Services, Inc. Consumers Energy Company, DTE Electric Company. 

Competitive Energy ..................................... Competitive Energy Services, LLC. 

Citizens Energy ........................................... Citizens Energy Corporation. 

City of New York ......................................... City of New York. 

Competition Coalition .................................. Electricity Transmission Competition Coalition. 

Competitive Power ...................................... Competitive Power Ventures, Inc. 

Consumers .................................................. Consumer Organizations. 

Electricity Consumers Resource Council .... Electricity Consumers Resource Council. 

CTC Global .................................................. CTC Global Corporation. 

District of Columbia’s Office of the People’s 

Counsel.

Office of the People’s Counsel for the District of Columbia. 

Dominion ...................................................... Dominion Energy Services, Inc. 

Duke ............................................................ Duke Energy Corporation. 

Duquesne Light ........................................... Duquesne Light Company. 

East Kentucky .............................................. East Kentucky Power Cooperative, Inc. 

EDF .............................................................. EDF Renewables, Inc. 

EDP Renewables ........................................ EDP Renewables North America LLC. 

EEI ............................................................... Edison Electric Institute. 

El Paso Electric ........................................... El Paso Electric Company. 

Enel .............................................................. Enel North America, Inc. 

Entergy ........................................................ Entergy Services, LLC. 

Environmental Advocates ............................ Center for Renewables Integration, Defenders of Wildlife, Environmental Law & Policy Center, National Audubon Society, National Wildlife Federation, and Vote Solar. 

EPSA ........................................................... Electric Power Supply Association. 

Eversource ................................................... Eversource Energy Service Company. 

Exelon .......................................................... Exelon Corporation. 

Grid United .................................................. Grid United LLC. 

Handy Law ................................................... Set Handy, Handy Law. 

Harvard ELI ................................................. Harvard Electricity Law Initiative. 

Idaho Power ................................................ Idaho Power Company. 

Indiana Commission .................................... Indiana Utility Regulatory Commission. 

Indicated PJM TOs ...................................... PJM Transmission Owners. 

Industrial Customers .................................... Industrial Customer Organizations. 

Iowa Consumer Advocate ........................... Iowa Office of Consumer Advocate. 

ISO–NE ........................................................ ISO New England Inc. 

ITC ............................................................... International Transmission Company. 

Kansas Commission .................................... Kansas Corporation Commission. 

Land Trust ................................................... Land Trust Alliance. 

LPPC ........................................................... Large Public Power Council. 

Law Students ............................................... Students of Law at the University of Minnesota Law School. 

LG&E/KU ..................................................... Louisville Gas and Electric Company and Kentucky Utilities Company.

Louisiana Commission ................................ Louisiana Public Service Commission. 

LS Power ..................................................... LS Power Grid, LLC. 

Macro Grid ................................................... Macro Grid Initiative. 

Massachusetts Attorney General ................ Massachusetts Attorney General Maura Healey. 

Massachusetts DOER ................................. Massachusetts Department of Energy Resources. 

Maryland Commission ................................. Maryland Public Service Commission. 

Maryland Energy Admin .............................. Maryland Energy Administration. 

Michigan Commission ................................. Michigan Public Service Commission. 

Minnesota Commerce ................................. Minnesota Department of Commerce. 

MISO ............................................................ Midcontinent Independent System Operator, Inc. 

MISO TOs .................................................... MISO Transmission Owners. 

Mississippi Commission .............................. Mississippi Public Service Commission and the Mississippi Public Utilities Staff. 

Missouri Farm Bureau ................................. Missouri Farm Bureau Federation. 

Montana QF Developers ............................. Clenera, LLC and Greenfields Irrigation District. 

NARUC ........................................................ National Association of Regulatory Utility Commissioners. 

NASEO ........................................................ National Association of State Energy Officials. 

NASUCA ...................................................... National Association of State Utility Consumer Advocates. 

National Grid ................................................ National Grid Plc. 

Nature Conservancy .................................... The Nature Conservancy. 

New England for Offshore Wind ................. New England for Offshore Wind. 

Nebraska Commission ................................ Nebraska Power Review Board. 

NEPOOL ...................................................... New England Power Pool Participants Committee. 

NERC ........................................................... North American Electric Reliability Corporation. 

NESCOE ...................................................... New England States Committee on Electricity. 


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Abbreviation Commenter 

New England Systems ................................ New England Consumer-Owned Systems. 

New Jersey Commission ............................. New Jersey Board of Public Utilities. 

NewSun ....................................................... NewSun Energy LLC. 

NextEra ........................................................ NextEra Energy, Inc. 

Niskanen ...................................................... Niskanen Center. 

North Carolina Commission ........................ North Carolina Utilities Commission. 

North Carolina Commission Staff ................ North Carolina Utilities Commission Public Staff. 

North Dakota Commission .......................... North Dakota Public Service Commission. 

Northern VA Coop ....................................... Northern Virginia Electric Cooperative. 

Northwest and Intermountain ...................... Northwest & Intermountain Power Producers Coalition. 

NRECA ........................................................ National Rural Electric Cooperative Association. 

NY Commission and NYSERDA ................. New York Public Service Commission and New York State Energy Research and Development Authority. 

NY TOs ........................................................ New York Transmission Owners. 

NYISO .......................................................... New York Independent System Operator, Inc. 

Ohio Commission ........................................ Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate. 

Ohio Consumers .......................................... Ohio Consumers’ Counsel. 

Oklahoma Commission ............................... Oklahoma Corporation Commission. 

Oklahoma Gas and Electric ........................ Oklahoma Gas and Electric Company. 

Omaha Public Power ................................... Omaha Public Power District. 

OMS ............................................................. Organization of MISO States. 

Oregon Commission .................................... Public Utility Commission of Oregon. 

Orsted .......................................................... Orsted North America. 

Pennsylvania Commission .......................... Pennsylvania Public Utility Commission. 

PG&E ........................................................... Pacific Gas and Electric. 

Pine Gate ..................................................... Pine Gate Renewables, LLC. 

PIOs ............................................................. Public Interest Organizations. 

PJM .............................................................. PJM Interconnection, L.L.C. 

PJM Market Monitor .................................... Monitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor of PJM Interconnection, L.L.C. 

Indicated PJM TOs ...................................... PJM Transmission Owners. 

Policy Integrity ............................................. Institute for Policy Integrity. 

Potomac Economics .................................... Potomac Economics, Ltd. 

PPL .............................................................. PPL Electric Utilities Corporation. 

PSEG ........................................................... PSEG Companies. 

Public Citizen ............................................... Public Citizen, Inc. 

Public Systems ............................................ Massachusetts Municipal Wholesale Electric Company, New Hampshire Electric Cooperative, Inc., 

Connecticut Municipal Electric Energy Cooperative, and Vermont Public Power Supply Authority. 

QCo ............................................................. Q Coefficient, Inc. 

R Street ....................................................... R Street Institute. 

Rail Electrification ........................................ Rail Electrification Council. 

REBA ........................................................... Renewable Energy Buyers Alliance. 

Resale Iowa ................................................. Resale Power Group of Iowa. 

Resilient Societies ....................................... Foundation for Resilient Societies. 

RMI .............................................................. RMI. 

Ron Belval ................................................... Ron Belval. 

SAFE ........................................................... SAFE. 

SoCal Edison ............................................... Southern California Edison Company. 

SDG&E ........................................................ San Diego Gas & Electric Company. 

SEIA ............................................................. Solar Energy Industries Association. 

SERTP ......................................................... Sponsors of the Southeastern Regional Transmission Planning Process. 

Shell ............................................................. Shell Energy North America. 

Six Cities ...................................................... Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California. 

Sorgo ........................................................... Sorgo Fuels & Chemicals, Inc. 

Southern ...................................................... Southern Company Services, Inc. 

SPP .............................................................. Southwest Power Pool, Inc. 

SPP Market Monitor .................................... Southwest Power Pool Market Monitoring Unit. 

SPP RSC ..................................................... Southwest Power Pool Regional State Committee. 

State Agencies ............................................ State Agencies (CT, DE, MD, DC, IL, MN, MI, MA, NJ, OR, PA, RI, VT). 

State Legislatures ........................................ National Conference of State Legislatures. 

State of Idaho .............................................. Idaho Governor’s Office of Energy & Mineral Resources. 

State of Massachusetts ............................... Commonwealth of Massachusetts Department of Energy Resources. 

State of New York ....................................... New York State Department of State Utility Intervention Unit. 

State of Tennessee ..................................... State of Tennessee. 

State of Washington .................................... Jay Inslee, Governor, State of Washington. 

State Wildlife Agencies ................................ Association of Fish & Wildlife Agencies. 

TANC ........................................................... Transmission Agency of Northern California. 

TAPS ........................................................... Transmission Access Policy Study Group. 

Tenaska ....................................................... Tenaska, Inc. 

Tom Pike ..................................................... Tom R Pike. 

Transmission Dependent Utilities ................ Transmission Dependent Utility Systems. 

Union of Concerned Scientists .................... Union of Concerned Scientists. 

US Chamber of Commerce ......................... US Chamber of Commerce. 

U.S. DOE ..................................................... United States Department of Energy. 


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Abbreviation Commenter 

US DOI ........................................................ US Department of Interior. 

Utah Commission ........................................ Utah Public Service Commission. 

VEIR ............................................................ VEIR Inc. 

Vermont Electric .......................................... Vermont Electric Power Company. 

Vistra ............................................................ Vistra Corp. 

WATT Coalition ........................................... WATT Coalition. 

WIRES ......................................................... WIRES. 

Xcel .............................................................. Xcel Energy Services Inc. 

Appendix B: Pro Forma Open Access 

Transmission Tariff Attachment K 

Note: Proposed deletions are in brackets 

and proposed additions are in italics. 

Attachment K 

Transmission Planning Process 

Local Transmission Planning 

The Transmission Provider shall establish 

a coordinated, open, and transparent local 

transmission planning process with its 

Network and Firm Point-to-Point 

Transmission Customers and other interested 

parties to ensure that the Transmission 

System is planned to meet the needs of both 

the Transmission Provider and its Network 

and Firm Point-to-Point Transmission 

Customers on a comparable and not unduly 

discriminatory basis. The Transmission 

Provider’s coordinated, open, and 

transparent local transmission planning 

process shall be provided as an attachment 

to the Transmission Provider’s Tariff. The 

Transmission Provider’s local transmission 

planning process shall satisfy the following 

nine principles, as defined in Order No. 890: 

Coordination, openness, transparency, 

information exchange, comparability, dispute 

resolution, regional participation, economic 

planning studies, and cost allocation for new 

transmission projects. The local transmission 

planning process also shall include the 

procedures and mechanisms for considering 

transmission needs driven by Public Policy 

Requirements consistent with Order No. 

1000. The local transmission planning 

process also shall provide a mechanism for 

the recovery and allocation of transmission 

planning costs consistent with Order No. 

890. The description of the Transmission 

Provider’s local transmission planning 

process must include sufficient detail to 

enable Transmission Customers to 

understand: 

(i) The process for consulting with 

customers; 

(ii) The notice procedures and anticipated 

frequency of meetings; 

(iii) The methodology, criteria, and 

processes used to develop a transmission 

plan; 

(iv) The method of disclosure of criteria, 

assumptions, and data underlying a 

transmission plan; 

(v) The obligations of and methods for 

Transmission Customers to submit data to 

the Transmission Provider; 

(vi) The dispute resolution process; 

(vii) The Transmission Provider’s study 

procedures for economic upgrades to address 

congestion or the integration of new 

resources; 

(viii) The Transmission Provider’s 

procedures and mechanisms for considering 

transmission needs driven by Public Policy 

Requirements, consistent with Order No. 

1000; and 

(ix) The relevant cost allocation method or 

methods. 

Regional Transmission Planning 

The Transmission Provider shall 

participate in a regional transmission 

planning process through which 

transmission facilities and non-transmission 

alternatives may be proposed and evaluated. 

The regional transmission planning process 

also shall develop a regional transmission 

plan that identifies the transmission facilities 

necessary to meet the needs of transmission 

providers and transmission customers in the 

transmission planning region. The regional 

transmission planning process must be 

consistent with the provision of Commissionjurisdictional services at rates, terms, and 

conditions that are just and reasonable and 

not unduly discriminatory or preferential, as 

described in Order No. 1000 and Order No. 

[final rule]. The regional transmission 

planning process shall be described in an 

attachment to the Transmission Provider’s 

Tariff. 

The Transmission Provider’s regional 

transmission planning process shall satisfy 

the following seven principles, as set out and 

explained in Order Nos. 890 and 1000: 

Coordination, openness, transparency, 

information exchange, comparability, dispute 

resolution, and economic planning studies. 

The regional transmission planning process 

also shall include the procedures and 

mechanisms for considering transmission 

needs driven by Public Policy Requirements, 

consistent with Order No. 1000. The regional 

transmission planning process shall provide 

a mechanism for the recovery and allocation 

of ‘‘transmission planning costs’’ consistent 

with Order No. 890 and Order No. 1000. 

The regional transmission planning 

process shall include a clear enrollment 

process for public and non-public utility 

transmission providers that make the choice 

to become part of a transmission planning 

region. The regional transmission planning 

process shall be clear that enrollment will 

subject enrollees to cost allocation if they are 

found to be beneficiaries of new transmission 

facilities selected in the regional 

transmission plan for purposes of cost 

allocation. Each Transmission Provider shall 

maintain a list of enrolled entities in the 

Transmission Provider’s Tariff. 

As part of the regional transmission 

planning process, the Transmission Providers 

in each transmission planning region will 

conduct Long-Term Regional Transmission 

Planning, meaning regional transmission 

planning on a sufficiently long-term, forwardlooking basis to identify transmission needs 

driven by changes in the resource mix and 

demand, evaluate transmission facilities to 

meet such needs, and identify and evaluate 

transmission facilities for potential selection 

in the regional transmission plan for 

purposes of cost allocation as the more 

efficient or cost-effective transmission 

facilities to meet such needs. As part of this 

Long-Term Regional Transmission Planning, 

the Transmission Providers in each 

transmission planning region will: (1) 

Identify transmission needs driven by 

changes in the resource mix and demand 

through the development of Long-Term 

Scenarios that satisfy the requirements set 

forth in Order No. [final rule]; (2) evaluate 

the benefits of regional transmission facilities 

to meet transmission needs driven by 

changes in the resource mix and demand 

over a time horizon that covers, at a 

minimum, 20 years starting from the 

estimated in-service date of the transmission 

facilities; and (3) establish transparent and 

not unduly discriminatory criteria to select 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation that more efficiently or costeffectively address transmission needs driven 

by changes in the resource mix and demand 

in collaboration with states and other 

stakeholders. 

When developing Long-Term Scenarios, 

the Transmission Providers in each 

transmission planning region must: (1) Use a 

transmission planning horizon no less than 

20 years into the future; (2) reassess and 

revise Long-Term Scenarios including to 

reassess whether the data inputs and factors 

incorporated in their previously developed 

Long-Term Scenarios need to be updated and 

then revise their Long-Term Scenarios as 

needed to reflect updated data inputs and 

factors at least every three years, and 

complete the development of Long-Term 

Scenarios within three years, before the next 

three-year assessment commences; (3) 

incorporate, at a minimum, the seven 

categories of factors identified in Order No. 

[final rule] that may drive transmission needs 

driven by changes in the resource mix and 

demand; (4) develop a plausible and diverse 

set of at least four Long-Term Scenarios; (5) 

use ‘‘best available data’’ (as defined in 

Order No. [final rule]) in developing LongTerm Scenarios; and (6) consider whether to 

identify geographic zones with the potential 

for development of large amounts of new 

generation. The process through which the 

Transmission Providers develop Long-Term 

Scenarios also must comply with the 


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following six transmission planning 

principles established in Order No. 890: 

Coordination; openness; transparency; 

information exchange; comparability; and 

dispute resolution. 

The Transmission Providers in each 

transmission planning region must identify 

the benefits they will use in Long-Term 

Regional Transmission Planning, how they 

will calculate those benefits, and how the 

benefits will reasonably reflect the benefits of 

regional transmission facilities to meet 

identified transmission needs driven by 

changes in the resource mix and demand. 

The following set of Long-Term Regional 

Transmission Benefits may be useful for 

Transmission Providers in each transmission 

planning region in evaluating transmission 

facilities for selection in the regional 

transmission plan for purposes of cost 

allocation as the more efficient or costeffective solutions to meet transmission 

needs driven by changes in the resource mix 

and demand: (1) Avoided or deferred 

reliability transmission projects and aging 

infrastructure replacement; (2) either reduced 

loss of load probability or reduced planning 

reserve margin; (3) production cost savings; 

(4) reduced transmission energy losses; (5) 

reduced congestion due to transmission 

outages; (6) mitigation of extreme events and 

system contingencies; (7) mitigation of 

weather and load uncertainty; (8) capacity 

cost benefits from reduced peak energy 

losses; (9) deferred generation capacity 

investments; (10) access to lower-cost 

generation; (11) increased competition; and 

(12) increased market liquidity. 

Table 1—Long-Term Regional Transmission Benefits 

Benefit Description 

Avoided or deferred reliability transmission facilities and aging transmission infrastructure replacement.Reduced costs of avoided or delayed transmission investment otherwise required to address reliability needs or replace aging transmission facilities. 

Reduced loss of load probability [OR next benefit] ................................. Reduced frequency of loss of load events by providing additional pathways for connecting generation resources with load (if planning reserve margin is constant), resulting in benefit of reduced expected 

unserved energy by customer value of lost load. 

Reduced planning reserve margin [OR prior benefit] .............................. While holding loss of load probabilities constant, system operators can 

reduce their resource adequacy requirements (i.e., planning reserve 

margins), resulting in a benefit of reduced capital cost of generation 

needed to meet resource adequacy requirements. 

Production cost savings ........................................................................... Reduction in production costs, including savings in fuel and other variable operating costs of power generation, that are realized when 

transmission facilities allow for the increased dispatch of suppliers 

that have lower incremental costs of production, displacing highercost supplies; also reduction in market prices as lower-cost suppliers 

set market clearing prices; when adjusted to account for purchases 

and sales outside the region, called adjusted production cost savings. 

Reduced transmission energy losses ...................................................... Reduced energy losses incurred in transmittal of power from generation to loads, thereby reducing total energy necessary to meet demand. 

Reduced congestion due to transmission outages .................................. Reduced production costs during transmission outages that significantly increase transmission congestion. 

Mitigation of extreme events and system contingencies ......................... Reduced production costs during extreme events, such as unusual 

weather conditions, fuel shortages, and multiple or sustained generation and transmission outages, through more robust transmission 

system reducing high-cost generation and emergency procurements 

necessary to support the system. 

Mitigation of weather and load uncertainty .............................................. Reduced production costs during higher than normal load conditions or 

significant shifts in regional weather patterns. 

Capacity cost benefits from reduced peak energy losses ....................... Reduced energy losses during peak load reduces generation capacity 

investment needed to meet the peak load and transmission losses. 

Deferred generation capacity investments ............................................... Reduced costs of needed generation capacity investments through expanded import capability into resource-constrained areas. 

Access to lower-cost generation .............................................................. Reduced total cost of generation due to ability to locate units in a more 

economically efficient location (e.g., low permitting costs, low-cost 

sites on which plants can be built, access to existing infrastructure, 

low labor costs, low fuel costs, access to valuable natural resources, 

locations with high-quality renewable energy resources). 

Increased competition .............................................................................. Reduced bid prices in wholesale electricity markets due to increased 

competition among generators and reduced overall market concentration/market power. 

Increased market liquidity ......................................................................... Reduced transaction costs (e.g., bid-ask spreads) of bilateral transactions, increased price transparency, increased efficiency of risk 

management, improved contracting, and better clarity for long-term 

transmission planning and investment decisions through increased 

number of buyers and sellers able to transact with each other as a 

result of transmission expansion. 

As part of Long-Term Regional 

Transmission Planning, the Transmission 

Providers in each transmission planning 

region must include (1) transparent and not 

unduly discriminatory criteria, which seek to 

maximize benefits to consumers over time 

without over-building transmission facilities, 

to identify and evaluate transmission 

facilities for potential selection in the 

regional transmission plan for purposes of 

cost allocation that address transmission 

needs driven by changes in the resource mix 

and demand; and (2) a process to coordinate 

with relevant state entities in developing 

such criteria. 

If the Transmission Providers include a 

portfolio approach in selecting transmission 

facilities in the regional transmission plan for 


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purposes of cost allocation that address 

transmission needs driven by changes in the 

resource mix and demand, then the 

Transmission Providers must include 

provisions describing whether the selection 

criteria would be used for Long-Term 

Regional Transmission Planning universally 

to address transmission needs driven by 

changes in the resource mix and demand or 

would be used only in certain specified 

instances. 

The Transmission Providers in each 

transmission planning region shall include in 

their tariffs either (1) a Long-Term Regional 

Transmission Cost Allocation Method to 

allocate the costs of Long-Term Regional 

Transmission Facilities, or (2) a State 

Agreement Process by which one or more 

relevant state entities may voluntarily agree 

to a cost allocation method, or (3) a 

combination thereof. A Long-Term Regional 

Transmission Cost Allocation Method is an 

ex ante regional cost allocation method that 

applies to a transmission facility identified as 

part of Long-Term Regional Transmission 

Planning and selected in the regional 

transmission plan for purposes of cost 

allocation to address transmission needs 

driven by changes in the resource mix and 

demand (Long-Term Regional Transmission 

Facility). The developer of a Long-Term 

Regional Transmission Facility would be 

entitled to use the Long-Term Regional 

Transmission Cost Allocation Method if it is 

the applicable cost allocation method. A 

State Agreement Process is an ex post cost 

allocation process, which may apply to an 

individual Long-Term Regional Transmission 

Facility or a portfolio of such Facilities 

grouped together for purposes of cost 

allocation. After a Long-Term Regional 

Transmission Facility is selected in the 

regional transmission plan for purposes of 

cost allocation, the State Agreement Process 

would be followed to establish a cost 

allocation method for that facility (if 

agreement can be reached). If the 

Commission subsequently approves the cost 

allocation method that results from the State 

Agreement Process, the developer of the 

Long-Term Regional Transmission Facility 

would be entitled to use that cost allocation 

method if it is the applicable method. The 

Long-Term Regional Transmission Cost 

Allocation Method and any cost allocation 

method resulting from the State Agreement 

Process for Long-Term Regional 

Transmission Facilities must comply with the 

existing six Order No. 1000 regional cost 

allocation principles. 

Transmission Providers in each 

transmission planning region must seek the 

agreement of relevant state entities within the 

transmission planning region regarding the 

Long-Term Regional Transmission Cost 

Allocation Method, State Agreement Process. 

The regional transmission planning 

processes must give a state or states a period 

of time to negotiate a cost allocation method 

for a transmission facility that is selected in 

the Long Term Regional Transmission Plan 

for purposes of cost allocation to address 

transmission needs driven by changes in the 

resource mix and demand that is different 

than the regional cost allocation method 

(alternate cost allocation method related to 

transmission needs driven by changes in the 

resource mix and demand). 

The Transmission Providers in each 

transmission planning region shall consider 

in regional transmission planning and cost 

allocation processes whether selecting 

transmission facilities in the regional 

transmission plan for purposes of cost 

allocation that incorporate dynamic line 

ratings, as defined in 18 CFR 35.28(b)(14), or 

advanced power flow control devices would 

be more efficient or cost-effective than 

regional transmission facilities that do not 

incorporate these technologies. Specifically, 

such consideration must include both: (1) 

First, whether incorporating dynamic line 

ratings or advanced power flow control 

devices into existing transmission facilities 

could meet the same regional transmission 

need more efficiently or cost-effectively than 

other potential transmission facilities; and (2) 

second, when evaluating transmission 

facilities for potential selection in the 

regional transmission plan for purposes of 

cost allocation, the Transmission Providers 

in each transmission planning region must 

also consider whether incorporating dynamic 

line ratings and advanced power flow control 

devices as part of any potential regional 

transmission facility would be more efficient 

of cost-effective. 

This requirement applies in all of the 

Transmission Provider’s regional 

transmission planning processes, including 

the regional transmission planning processes 

for near-term regional transmission needs 

and Long-Term Regional Transmission 

Planning required in Order No. [final rule]. 

The costs of transmission facilities that 

incorporate dynamic line ratings or advanced 

power flow control devices that are selected 

in the regional transmission plan for 

purposes of cost allocation will be allocated 

using the applicable regional cost allocation 

method. The Transmission Provider’s 

evaluation process must culminate in a 

determination that is sufficiently detailed for 

stakeholders to understand why a particular 

transmission facility was selected or not 

selected in the regional transmission plan for 

purposes of cost allocation. This process 

must include the consideration of dynamic 

line ratings and advanced power flow control 

devices and why they were not incorporated 

into selected regional transmission facilities. 

The description of the regional 

transmission planning process must include 

sufficient detail to enable Transmission 

Customers to understand: 

(i) The process for enrollment in the 

regional transmission planning process; 

(ii) The process for consulting with 

customers; 

(iii) The notice procedures and anticipated 

frequency of meetings; 

(iv) The methodology, criteria, and 

processes used to develop a transmission 

plan; 

(v) The method of disclosure of criteria, 

assumptions, and data underlying a 

transmission plan; 

(vi) The obligations of and methods for 

transmission customers to submit data; 

(vii) The process for submission of data by 

nonincumbent developers of transmission 

projects that wish to participate in the 

regional transmission planning process and 

seek regional cost allocation; 

(viii) The process for submission of data by 

merchant transmission developers that wish 

to participate in the regional transmission 

planning process; 

(ix) The dispute resolution process; 

(x) The study procedures for economic 

upgrades to address congestion or the 

integration of new resources; and 

[The procedures and mechanisms for 

considering transmission needs driven by 

Public Policy Requirements, consistent with 

Order No. 1000; and] 

(xi) The relevant cost allocation method or 

methods. 

The regional transmission planning 

process must include a cost allocation 

method or methods that satisfy the six 

regional cost allocation principles set forth in 

Order No. 1000. 

Enhanced Transparency of Local 

Transmission Planning Inputs in the 

Regional Transmission Planning Process 

The regional transmission planning 

process must include at least three 

stakeholder meetings concerning the local 

transmission planning process of each 

Transmission Provider that is a member of 

the transmission planning region before each 

Transmission Provider’s local transmission 

planning information can be incorporated 

into the transmission planning region’s 

planning models: 

(1) A stakeholder meeting to review the 

criteria, assumptions, and models related to 

each Transmission Provider’s local 

transmission planning (Assumptions 

Meeting); 

(2) No fewer than 25 calendar days after 

the Assumptions Meeting, a stakeholder 

meeting to review identified reliability 

criteria violations and other transmission 

needs that drive the need for local 

transmission facilities (Needs Meeting); and 

(3) No fewer than 25 calendar days after 

the Needs Meeting, a stakeholder meeting to 

review potential solutions to those reliability 

criteria violations and other transmission 

needs (Solutions Meeting). 

Identifying Potential Opportunities to RightSize Replacement Transmission Facilities 

As part of each Long-Term Regional 

Transmission Planning cycle, Transmission 

Providers in each transmission planning 

region shall evaluate whether transmission 

facilities operating at or above 230 kV that 

an individual Transmission Provider that 

owns the transmission facility anticipates 

replacing in-kind with a new transmission 

facility during the next 10 years can be 

‘‘right-sized’’ to more efficiently or costeffectively address regional transmission 

needs identified in Long-Term Regional 

Transmission Planning. ‘‘Right-sizing’’ 

means the process of modifying a 

Transmission Provider’s in-kind replacement 

of an existing transmission facility to 

increase that facility’s transfer capability. 

The process to identify potential 

opportunities to right-size replacement 

transmission facilities must follow the 

process outlined in Order No. [final rule]. 


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Interregional Transmission Coordination 

The Transmission Provider, through its 

regional transmission planning process, must 

coordinate with the public utility 

transmission providers in each neighboring 

transmission planning region within its 

interconnection to address transmission 

planning coordination issues related to 

interregional transmission facilities. The 

interregional transmission coordination 

procedures must include a detailed 

description of the process for coordination 

between public utility transmission providers 

in neighboring transmission planning regions 

(i) with respect to each interregional 

transmission facility that is proposed to be 

located in both transmission planning 

regions and (ii) to identify possible 

interregional transmission facilities that 

could address transmission needs more 

efficiently or cost-effectively than separate 

regional transmission facilities. The 

interregional transmission coordination 

procedures shall be described in an 

attachment to the Transmission Provider’s 

Tariff. 

The Transmission Provider must ensure 

that the following requirements are included 

in any applicable interregional transmission 

coordination procedures: 

(1) A commitment to coordinate and share 

the results of each transmission planning 

region’s regional transmission plans 

(including information regarding the 

respective transmission needs identified in 

Long-Term Regional Transmission Planning 

and potential transmission facilities to meet 

those needs) to identify possible interregional 

transmission facilities that could address 

transmission needs more efficiently or costeffectively than separate regional 

transmission facilities, as well as a procedure 

for doing so; 

(2) A formal procedure to identify and 

jointly evaluate transmission facilities that 

are proposed to be located in both 

transmission planning regions, including 

those that may be more efficient or costeffective transmission solutions to 

transmission needs identified through LongTerm Regional Transmission Planning; 

(3) An agreement to exchange, at least 

annually, planning data and information; and 

(4) A commitment to maintain a website or 

email list for the communication of 

information related to the coordinated 

planning process. 

The Transmission Provider must work 

with transmission providers located in 

neighboring transmission planning regions to 

develop a mutually agreeable method or 

methods for allocating between the two 

transmission planning regions the costs of a 

new interregional transmission facility that is 

located within both transmission planning 

regions. Such cost allocation method or 

methods must satisfy the six interregional 

cost allocation principles set forth in Order 

No. 1000 and must be included in the 

Transmission Provider’s Tariff. 

Appendix C: Pro Forma LGIP 

Note: Proposed deletions are in brackets 

and proposed additions are in italics. 

Standard Large Generator Interconnection 

Procedures (LGIP) Including Standard Large 

Generator Interconnection Agreement 

(LGIA); Standard Large Generator 

Interconnection Procedures (LGIP) 

(Applicable to Generating Facilities That 

Exceed 20 MW) 

Table of Contents 

Section 1. Definitions 

Section 2. Scope and Application 

2.1 Application of Standard Large 

Generator Interconnection Procedures 

2.2 Comparability 

2.3 Base Case Data 

2.4 No Applicability to Transmission 

Service 

Section 3. Interconnection Requests 

3.1 General 

3.2 Identification of Types of 

Interconnection Services 

3.2.1 Energy Resource Interconnection 

Service 

3.2.1.1 The Product 

3.2.1.2 The Study 

3.2.2 Network Resource Interconnection 

Service 

3.2.2.1 The Product 

3.2.2.2 The Study 

3.3 Utilization of Surplus Interconnection 

Service 

3.3.1 Surplus Interconnection Service 

Request 

3.4 Valid Interconnection Request 

3.4.1 Initiating an Interconnection 

Request 

3.4.2 Acknowledgment of 

Interconnection Request 

3.4.3 Deficiencies in Interconnection 

Request 

3.4.4 Scoping Meeting 

3.5 OASIS Posting 

3.5.1

3.5.2 Requirement to Post 

Interconnection Study Metrics 

3.5.2.1 Interconnection Feasibility 

Studies Processing Time 

3.5.2.2 Interconnection System Impact 

Studies Time 

3.5.2.3 Interconnection Facilities Studies 

Processing Time 

3.5.2.4 Interconnection Service Requests 

Withdrawn From Interconnection Queue 

3.6 Coordination With Affected Systems 

3.7 Withdrawal 

3.8 Identification of Contingent Facilities 

3.10 Repeat Network Upgrades for 

Consideration in the Regional 

Transmission Planning Process 

Section 4. Queue Position 

4.1 General 

4.2 Clustering 

4.3 Transferability of Queue Position 

4.4 Modifications 

Section 5. Procedures for Interconnection 

Requests Submitted Prior to Effective 

Date of Standard Large Generator 

Interconnection Procedures 

5.1 Queue Position for Pending Requests 

5.2 New Transmission Provider 

Section 6. Interconnection Feasibility Study 

6.1 Interconnection Feasibility Study 

Agreement 

6.2 Scope of Interconnection Feasibility 

Study 

6.3 Interconnection Feasibility Study 

Procedures 

6.4 Re-Study 

Section 7. Interconnection System Impact 

Study 

7.1 Interconnection System Impact Study 

Agreement 

7.2 Execution of Interconnection System 

Impact Study Agreement 

7.3 Scope of Interconnection System 

Impact Study 

7.4 Interconnection System Impact Study 

Procedures 

7.5 Meeting With Transmission Provider 

7.6 Re-Study 

Section 8. Interconnection Facilities Study 

8.1 Interconnection Facilities Study 

Agreement 

8.2 Scope of Interconnection Facilities 

Study 

8.3 Interconnection Facilities Study 

Procedures 

8.4 Meeting With Transmission Provider 

8.5 Re-Study 

Section 9. Engineering & Procurement (‘E&P’) 

Agreement 

Section 10. Optional Interconnection Study 

10.1 Optional Interconnection Study 

Agreement 

10.2 Scope of Optional Interconnection 

Study 

10.3 Optional Interconnection Study 

Procedures 

Section 11. Standard Large Generator 

Interconnection Agreement (LGIA) 

11.1 Tender 

11.2 Negotiation 

11.3 Execution and Filing 

11.4 Commencement of Interconnection 

Activities 

Section 12. Construction of Transmission 

Provider’s Interconnection Facilities and 

Network Upgrades 

12.1 Schedule 

12.2 Construction Sequencing 

12.2.1 General 

12.2.2 Advance Construction of Network 

Upgrades That Are an Obligation of an 

Entity Other Than Interconnection 

Customer 

12.2.3 Advancing Construction of 

Network Upgrades That Are Part of an 

Expansion Plan of the Transmission 

Provider 

12.2.4 Amended Interconnection System 

Impact Study 

Section 13. Miscellaneous 

13.1 Confidentiality 

13.1.1 Scope 

13.1.2 Release of Confidential 

Information 

13.1.3 Rights 

13.1.4 No Warranties 

13.1.5 Standard of Care 

13.1.6 Order of Disclosure 

13.1.7 Remedies 

13.1.8 Disclosure to FERC or Its Staff 

13.2 Delegation of Responsibility 

13.3 Obligation for Study Costs 

13.4 Third Parties Conducting Studies 

13.5 Disputes 

13.5.1 Submission 

13.5.2 External Arbitration Procedures 

13.5.3 Arbitration Decisions 

13.5.4 Costs 

13.5.5 Non-Binding Dispute Resolution 

Procedures 

13.6 Local Furnishing Bonds 


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13.6.1 Transmission Providers That Own 

Facilities Financed by Local Furnishing 

Bonds 

13.6.2 Alternative Procedures for 

Requesting Interconnection Service 

Appendix 1—Interconnection Request for a 

Large Generating Facility 

Appendix 2—Interconnection Feasibility 

Study Agreement 

Appendix 3—Interconnection System Impact 

Study Agreement 

Appendix 4—Interconnection Facilities 

Study Agreement 

Appendix 5—Optional Interconnection 

Study Agreement 

Appendix 6—Standard Large Generator 

Interconnection Agreement 

Appendix 7—Interconnection Procedures for 

a Wind Generating Plant 

Section 1. Definitions 

Adverse System Impact shall mean the 

negative effects due to technical or 

operational limits on conductors or 

equipment being exceeded that may 

compromise the safety and reliability of the 

electric system. 

Affected System shall mean an electric 

system other than the Transmission 

Provider’s Transmission System that may be 

affected by the proposed interconnection. 

Affected System Operator shall mean the 

entity that operates an Affected System. 

Affiliate shall mean, with respect to a 

corporation, partnership or other entity, each 

such other corporation, partnership or other 

entity that directly or indirectly, through one 

or more intermediaries, controls, is 

controlled by, or is under common control 

with, such corporation, partnership or other 

entity. 

Ancillary Services shall mean those 

services that are necessary to support the 

transmission of capacity and energy from 

resources to loads while maintaining reliable 

operation of the Transmission Provider’s 

Transmission System in accordance with 

Good Utility Practice. 

Applicable Laws and Regulations shall 

mean all duly promulgated applicable 

federal, state and local laws, regulations, 

rules, ordinances, codes, decrees, judgments, 

directives, or judicial or administrative 

orders, permits and other duly authorized 

actions of any Governmental Authority. 

Applicable Reliability Council shall mean 

the reliability council applicable to the 

Transmission System to which the 

Generating Facility is directly 

interconnected. 

Applicable Reliability Standards shall 

mean the requirements and guidelines of 

NERC, the Applicable Reliability Council, 

and the Control Area of the Transmission 

System to which the Generating Facility is 

directly interconnected. 

Base Case shall mean the base case power 

flow, short circuit, and stability data bases 

used for the Interconnection Studies by the 

Transmission Provider or Interconnection 

Customer. 

Breach shall mean the failure of a Party to 

perform or observe any material term or 

condition of the Standard Large Generator 

Interconnection Agreement. 

Breaching Party shall mean a Party that is 

in Breach of the Standard Large Generator 

Interconnection Agreement. 

Business Day shall mean Monday through 

Friday, excluding Federal Holidays. 

Calendar Day shall mean any day 

including Saturday, Sunday or a Federal 

Holiday. 

Clustering shall mean the process whereby 

a group of Interconnection Requests is 

studied together, instead of serially, for the 

purpose of conducting the Interconnection 

System Impact Study. 

Commercial Operation shall mean the 

status of a Generating Facility that has 

commenced generating electricity for sale, 

excluding electricity generated during Trial 

Operation. 

Commercial Operation Date of a unit shall 

mean the date on which the Generating 

Facility commences Commercial Operation 

as agreed to by the Parties pursuant to 

Appendix E to the Standard Large Generator 

Interconnection Agreement. 

Confidential Information shall mean any 

confidential, proprietary or trade secret 

information of a plan, specification, pattern, 

procedure, design, device, list, concept, 

policy or compilation relating to the present 

or planned business of a Party, which is 

designated as confidential by the Party 

supplying the information, whether 

conveyed orally, electronically, in writing, 

through inspection, or otherwise. 

Contingent Facilities shall mean those 

unbuilt Interconnection Facilities and 

Network Upgrades upon which the 

Interconnection Request’s costs, timing, and 

study findings are dependent, and if delayed 

or not built, could cause a need for ReStudies of the Interconnection Request or a 

reassessment of the Interconnection Facilities 

and/or Network Upgrades and/or costs and 

timing. 

Control Area shall mean an electrical 

system or systems bounded by 

interconnection metering and telemetry, 

capable of controlling generation to maintain 

its interchange schedule with other Control 

Areas and contributing to frequency 

regulation of the interconnection. A Control 

Area must be certified by an Applicable 

Reliability Council. 

Default shall mean the failure of a 

Breaching Party to cure its Breach in 

accordance with Article 17 of the Standard 

Large Generator Interconnection Agreement. 

Dispute Resolution shall mean the 

procedure for resolution of a dispute between 

the Parties in which they will first attempt 

to resolve the dispute on an informal basis. 

Distribution System shall mean the 

Transmission Provider’s facilities and 

equipment used to transmit electricity to 

ultimate usage points such as homes and 

industries directly from nearby generators or 

from interchanges with higher voltage 

transmission networks which transport bulk 

power over longer distances. The voltage 

levels at which distribution systems operate 

differ among areas. 

Distribution Upgrades shall mean the 

additions, modifications, and upgrades to the 

Transmission Provider’s Distribution System 

at or beyond the Point of Interconnection to 

facilitate interconnection of the Generating 

Facility and render the transmission service 

necessary to effect Interconnection 

Customer’s wholesale sale of electricity in 

interstate commerce. Distribution Upgrades 

do not include Interconnection Facilities. 

Effective Date shall mean the date on 

which the Standard Large Generator 

Interconnection Agreement becomes effective 

upon execution by the Parties subject to 

acceptance by FERC, or if filed unexecuted, 

upon the date specified by FERC. 

Emergency Condition shall mean a 

condition or situation: (1) That in the 

judgment of the Party making the claim is 

imminently likely to endanger life or 

property; or (2) that, in the case of a 

Transmission Provider, is imminently likely 

(as determined in a non-discriminatory 

manner) to cause a material adverse effect on 

the security of, or damage to Transmission 

Provider’s Transmission System, 

Transmission Provider’s Interconnection 

Facilities or the electric systems of others to 

which the Transmission Provider’s 

Transmission System is directly connected; 

or (3) that, in the case of Interconnection 

Customer, is imminently likely (as 

determined in a non-discriminatory manner) 

to cause a material adverse effect on the 

security of, or damage to, the Generating 

Facility or Interconnection Customer’s 

Interconnection Facilities. System restoration 

and black start shall be considered 

Emergency Conditions; provided that 

Interconnection Customer is not obligated by 

the Standard Large Generator Interconnection 

Agreement to possess black start capability. 

Energy Resource Interconnection Service 

shall mean an Interconnection Service that 

allows the Interconnection Customer to 

connect its Generating Facility to the 

Transmission Provider’s Transmission 

System to be eligible to deliver the 

Generating Facility’s electric output using the 

existing firm or nonfirm capacity of the 

Transmission Provider’s Transmission 

System on an as available basis. Energy 

Resource Interconnection Service in and of 

itself does not convey transmission service. 

Engineering & Procurement (E&P) 

Agreement shall mean an agreement that 

authorizes the Transmission Provider to 

begin engineering and procurement of long 

lead-time items necessary for the 

establishment of the interconnection in order 

to advance the implementation of the 

Interconnection Request. 

Environmental Law shall mean Applicable 

Laws or Regulations relating to pollution or 

protection of the environment or natural 

resources. 

Federal Power Act shall mean the Federal 

Power Act, as amended, 16 U.S.C. 791a et 

seq. 

FERC shall mean the Federal Energy 

Regulatory Commission (Commission) or its 

successor. 

Force Majeure shall mean any act of God, 

labor disturbance, act of the public enemy, 

war, insurrection, riot, fire, storm or flood, 

explosion, breakage or accident to machinery 

or equipment, any order, regulation or 

restriction imposed by governmental, 

military or lawfully established civilian 

authorities, or any other cause beyond a 

Party’s control. A Force Majeure event does 


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not include acts of negligence or intentional 

wrongdoing by the Party claiming Force 

Majeure. 

Generating Facility shall mean 

Interconnection Customer’s device for the 

production and/or storage for later injection 

of electricity identified in the 

Interconnection Request, but shall not 

include the Interconnection Customer’s 

Interconnection Facilities. 

Generating Facility Capacity shall mean 

the net capacity of the Generating Facility 

and the aggregate net capacity of the 

Generating Facility where it includes 

multiple energy production devices. 

Good Utility Practice shall mean any of the 

practices, methods and acts engaged in or 

approved by a significant portion of the 

electric industry during the relevant time 

period, or any of the practices, methods and 

acts which, in the exercise of reasonable 

judgment in light of the facts known at the 

time the decision was made, could have been 

expected to accomplish the desired result at 

a reasonable cost consistent with good 

business practices, reliability, safety and 

expedition. Good Utility Practice is not 

intended to be limited to the optimum 

practice, method, or act to the exclusion of 

all others, but rather to be acceptable 

practices, methods, or acts generally accepted 

in the region. 

Governmental Authority shall mean any 

federal, state, local or other governmental 

regulatory or administrative agency, court, 

commission, department, board, or other 

governmental subdivision, legislature, 

rulemaking board, tribunal, or other 

governmental authority having jurisdiction 

over the Parties, their respective facilities, or 

the respective services they provide, and 

exercising or entitled to exercise any 

administrative, executive, police, or taxing 

authority or power; provided, however, that 

such term does not include Interconnection 

Customer, Transmission Provider, or any 

Affiliate thereof. 

Hazardous Substances shall mean any 

chemicals, materials or substances defined as 

or included in the definition of ‘‘hazardous 

substances,’’ ‘‘hazardous wastes,’’ 

‘‘hazardous materials,’’ ‘‘hazardous 

constituents,’’ ‘‘restricted hazardous 

materials,’’ ‘‘extremely hazardous 

substances,’’ ‘‘toxic substances,’’ ‘‘radioactive 

substances,’’ ‘‘contaminants,’’ ‘‘pollutants,’’ 

‘‘toxic pollutants’’ or words of similar 

meaning and regulatory effect under any 

applicable Environmental Law, or any other 

chemical, material or substance, exposure to 

which is prohibited, limited or regulated by 

any applicable Environmental Law. 

Initial Synchronization Date shall mean 

the date upon which the Generating Facility 

is initially synchronized and upon which 

Trial Operation begins. 

In-Service Date shall mean the date upon 

which the Interconnection Customer 

reasonably expects it will be ready to begin 

use of the Transmission Provider’s 

Interconnection Facilities to obtain back feed 

power. 

Interconnection Customer shall mean any 

entity, including the Transmission Provider, 

Transmission Owner or any of the Affiliates 

or subsidiaries of either, that proposes to 

interconnect its Generating Facility with the 

Transmission Provider’s Transmission 

System. 

Interconnection Customer’s 

Interconnection Facilities shall mean all 

facilities and equipment, as identified in 

Appendix A of the Standard Large Generator 

Interconnection Agreement, that are located 

between the Generating Facility and the 

Point of Change of Ownership, including any 

modification, addition, or upgrades to such 

facilities and equipment necessary to 

physically and electrically interconnect the 

Generating Facility to the Transmission 

Provider’s Transmission System. 

Interconnection Customer’s Interconnection 

Facilities are sole use facilities. 

Interconnection Facilities shall mean the 

Transmission Provider’s Interconnection 

Facilities and the Interconnection Customer’s 

Interconnection Facilities. Collectively, 

Interconnection Facilities include all 

facilities and equipment between the 

Generating Facility and the Point of 

Interconnection, including any modification, 

additions or upgrades that are necessary to 

physically and electrically interconnect the 

Generating Facility to the Transmission 

Provider’s Transmission System. 

Interconnection Facilities are sole use 

facilities and shall not include Distribution 

Upgrades, Stand Alone Network Upgrades or 

Network Upgrades. 

Interconnection Facilities Study shall mean 

a study conducted by the Transmission 

Provider or a third party consultant for the 

Interconnection Customer to determine a list 

of facilities (including Transmission 

Provider’s Interconnection Facilities and 

Network Upgrades as identified in the 

Interconnection System Impact Study), the 

cost of those facilities, and the time required 

to interconnect the Generating Facility with 

the Transmission Provider’s Transmission 

System. The scope of the study is defined in 

Section 8 of the Standard Large Generator 

Interconnection Procedures. 

Interconnection Facilities Study Agreement 

shall mean the form of agreement contained 

in Appendix 4 of the Standard Large 

Generator Interconnection Procedures for 

conducting the Interconnection Facilities 

Study. 

Interconnection Feasibility Study shall 

mean a preliminary evaluation of the system 

impact and cost of interconnecting the 

Generating Facility to the Transmission 

Provider’s Transmission System, the scope of 

which is described in Section 6 of the 

Standard Large Generator Interconnection 

Procedures. 

Interconnection Feasibility Study 

Agreement shall mean the form of agreement 

contained in Appendix 2 of the Standard 

Large Generator Interconnection Procedures 

for conducting the Interconnection 

Feasibility Study. 

Interconnection Request shall mean an 

Interconnection Customer’s request, in the 

form of Appendix 1 to the Standard Large 

Generator Interconnection Procedures, in 

accordance with the Tariff, to interconnect a 

new Generating Facility, or to increase the 

capacity of, or make a Material Modification 

to the operating characteristics of, an existing 

Generating Facility that is interconnected 

with the Transmission Provider’s 

Transmission System. 

Interconnection Service shall mean the 

service provided by the Transmission 

Provider associated with interconnecting the 

Interconnection Customer’s Generating 

Facility to the Transmission Provider’s 

Transmission System and enabling it to 

receive electric energy and capacity from the 

Generating Facility at the Point of 

Interconnection, pursuant to the terms of the 

Standard Large Generator Interconnection 

Agreement and, if applicable, the 

Transmission Provider’s Tariff. 

Interconnection Study shall mean any of 

the following studies: The Interconnection 

Feasibility Study, the Interconnection System 

Impact Study, and the Interconnection 

Facilities Study described in the Standard 

Large Generator Interconnection Procedures. 

Interconnection System Impact Study shall 

mean an engineering study that evaluates the 

impact of the proposed interconnection on 

the safety and reliability of Transmission 

Provider’s Transmission System and, if 

applicable, an Affected System. The study 

shall identify and detail the system impacts 

that would result if the Generating Facility 

were interconnected without project 

modifications or system modifications, 

focusing on the Adverse System Impacts 

identified in the Interconnection Feasibility 

Study, or to study potential impacts, 

including but not limited to those identified 

in the Scoping Meeting as described in the 

Standard Large Generator Interconnection 

Procedures. 

Interconnection System Impact Study 

Agreement shall mean the form of agreement 

contained in Appendix 3 of the Standard 

Large Generator Interconnection Procedures 

for conducting the Interconnection System 

Impact Study. 

IRS shall mean the Internal Revenue 

Service. 

Joint Operating Committee shall be a group 

made up of representatives from 

Interconnection Customers and the 

Transmission Provider to coordinate 

operating and technical considerations of 

Interconnection Service. 

Large Generating Facility shall mean a 

Generating Facility having a Generating 

Facility Capacity of more than 20 MW. 

Loss shall mean any and all losses relating 

to injury to or death of any person or damage 

to property, demand, suits, recoveries, costs 

and expenses, court costs, attorney fees, and 

all other obligations by or to third parties, 

arising out of or resulting from the other 

Party’s performance, or non-performance of 

its obligations under the Standard Large 

Generator Interconnection Agreement on 

behalf of the indemnifying Party, except in 

cases of gross negligence or intentional 

wrongdoing by the indemnifying Party. 

Material Modification shall mean those 

modifications that have a material impact on 

the cost or timing of any Interconnection 

Request with a later queue priority date. 

Metering Equipment shall mean all 

metering equipment installed or to be 

installed at the Generating Facility pursuant 

to the Standard Large Generator 

Interconnection Agreement at the metering 

points, including but not limited to 


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instrument transformers, MWh-meters, data 

acquisition equipment, transducers, remote 

terminal unit, communications equipment, 

phone lines, and fiber optics. 

NERC shall mean the North American 

Electric Reliability Council or its successor 

organization. 

Network Resource shall mean any 

designated generating resource owned, 

purchased, or leased by a Network Customer 

under the Network Integration Transmission 

Service Tariff. Network Resources do not 

include any resource, or any portion thereof, 

that is committed for sale to third parties or 

otherwise cannot be called upon to meet the 

Network Customer’s Network Load on a noninterruptible basis. 

Network Resource Interconnection Service 

shall mean an Interconnection Service that 

allows the Interconnection Customer to 

integrate its Large Generating Facility with 

the Transmission Provider’s Transmission 

System (1) in a manner comparable to that in 

which the Transmission Provider integrates 

its generating facilities to serve native load 

customers; or (2) in an RTO or ISO with 

market based congestion management, in the 

same manner as Network Resources. Network 

Resource Interconnection Service in and of 

itself does not convey transmission service. 

Network Upgrades shall mean the 

additions, modifications, and upgrades to the 

Transmission Provider’s Transmission 

System required at or beyond the point at 

which the Interconnection Facilities connect 

to the Transmission Provider’s Transmission 

System to accommodate the interconnection 

of the Large Generating Facility to the 

Transmission Provider’s Transmission 

System. 

Notice of Dispute shall mean a written 

notice of a dispute or claim that arises out 

of or in connection with the Standard Large 

Generator Interconnection Agreement or its 

performance. 

Optional Interconnection Study shall mean 

a sensitivity analysis based on assumptions 

specified by the Interconnection Customer in 

the Optional Interconnection Study 

Agreement. 

Optional Interconnection Study Agreement 

shall mean the form of agreement contained 

in Appendix 5 of the Standard Large 

Generator Interconnection Procedures for 

conducting the Optional Interconnection 

Study. 

Party or Parties shall mean Transmission 

Provider, Transmission Owner, 

Interconnection Customer or any 

combination of the above. 

Permissible Technological Advancement 

[Transmission Provider inserts definition 

here]. 

Point of Change of Ownership shall mean 

the point, as set forth in Appendix A to the 

Standard Large Generator Interconnection 

Agreement, where the Interconnection 

Customer’s Interconnection Facilities 

connect to the Transmission Provider’s 

Interconnection Facilities. 

Point of Interconnection shall mean the 

point, as set forth in Appendix A to the 

Standard Large Generator Interconnection 

Agreement, where the Interconnection 

Facilities connect to the Transmission 

Provider’s Transmission System. 

Provisional Interconnection Service shall 

mean Interconnection Service provided by 

Transmission Provider associated with 

interconnecting the Interconnection 

Customer’s Generating Facility to 

Transmission Provider’s Transmission 

System and enabling that Transmission 

System to receive electric energy and 

capacity from the Generating Facility at the 

Point of Interconnection, pursuant to the 

terms of the Provisional Large Generator 

Interconnection Agreement and, if 

applicable, the Tariff. 

Provisional Large Generator 

Interconnection Agreement shall mean the 

interconnection agreement for Provisional 

Interconnection Service established between 

Transmission Provider and/or the 

Transmission Owner and the Interconnection 

Customer. This agreement shall take the form 

of the Large Generator Interconnection 

Agreement, modified for provisional 

purposes. 

Queue Position shall mean the order of a 

valid Interconnection Request, relative to all 

other pending valid Interconnection 

Requests, that is established based upon the 

date and time of receipt of the valid 

Interconnection Request by the Transmission 

Provider. 

Reasonable Efforts shall mean, with 

respect to an action required to be attempted 

or taken by a Party under the Standard Large 

Generator Interconnection Agreement, efforts 

that are timely and consistent with Good 

Utility Practice and are otherwise 

substantially equivalent to those a Party 

would use to protect its own interests. 

Scoping Meeting shall mean the meeting 

between representatives of the 

Interconnection Customer and Transmission 

Provider conducted for the purpose of 

discussing alternative interconnection 

options, to exchange information including 

any transmission data and earlier study 

evaluations that would be reasonably 

expected to impact such interconnection 

options, to analyze such information, and to 

determine the potential feasible Points of 

Interconnection. 

Site Control shall mean documentation 

reasonably demonstrating: (1) Ownership of, 

a leasehold interest in, or a right to develop 

a site for the purpose of constructing the 

Generating Facility; (2) an option to purchase 

or acquire a leasehold site for such purpose; 

or (3) an exclusivity or other business 

relationship between Interconnection 

Customer and the entity having the right to 

sell, lease or grant Interconnection Customer 

the right to possess or occupy a site for such 

purpose. 

Small Generating Facility shall mean a 

Generating Facility that has a Generating 

Facility Capacity of no more than 20 MW. 

Stand Alone Network Upgrades shall mean 

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. If the 

Transmission Provider and Interconnection 

Customer disagree about whether a particular 

Network Upgrade is a Stand Alone Network 

Upgrade, the Transmission Provider must 

provide the Interconnection Customer a 

written technical explanation outlining why 

the Transmission Provider does not consider 

the Network Upgrade to be a Stand Alone 

Network Upgrade within 15 days of its 

determination. 

Standard Large Generator Interconnection 

Agreement (LGIA) shall mean the form of 

interconnection agreement applicable to an 

Interconnection Request pertaining to a Large 

Generating Facility that is included in the 

Transmission Provider’s Tariff. 

Standard Large Generator Interconnection 

Procedures (LGIP) shall mean the 

interconnection procedures applicable to an 

Interconnection Request pertaining to a Large 

Generating Facility that are included in the 

Transmission Provider’s Tariff. 

Surplus Interconnection Service shall mean 

any unneeded portion of Interconnection 

Service established in a Large Generator 

Interconnection Agreement, such that if 

Surplus Interconnection Service is utilized, 

the total amount of Interconnection Service 

at the Point of Interconnection would remain 

the same. 

System Protection Facilities shall mean the 

equipment, including necessary protection 

signal communications equipment, required 

to protect (1) the Transmission Provider’s 

Transmission System from faults or other 

electrical disturbances occurring at the 

Generating Facility and (2) the Generating 

Facility from faults or other electrical system 

disturbances occurring on the Transmission 

Provider’s Transmission System or on other 

delivery systems or other generating systems 

to which the Transmission Provider’s 

Transmission System is directly connected. 

Tariff shall mean the Transmission 

Provider’s Tariff through which open access 

transmission service and Interconnection 

Service are offered, as filed with FERC, and 

as amended or supplemented from time to 

time, or any successor tariff. 

Transmission Owner shall mean an entity 

that owns, leases or otherwise possesses an 

interest in the portion of the Transmission 

System at the Point of Interconnection and 

may be a Party to the Standard Large 

Generator Interconnection Agreement to the 

extent necessary. 

Transmission Provider shall mean the 

public utility (or its designated agent) that 

owns, controls, or operates transmission or 

distribution facilities used for the 

transmission of electricity in interstate 

commerce and provides transmission service 

under the Tariff. The term Transmission 

Provider should be read to include the 

Transmission Owner when the Transmission 

Owner is separate from the Transmission 

Provider. 

Transmission Provider’s Interconnection 

Facilities shall mean all facilities and 

equipment owned, controlled, or operated by 

the Transmission Provider from the Point of 

Change of Ownership to the Point of 

Interconnection as identified in Appendix A 

to the Standard Large Generator 

Interconnection Agreement, including any 


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modifications, additions or upgrades to such 

facilities and equipment. Transmission 

Provider’s Interconnection Facilities are sole 

use facilities and shall not include 

Distribution Upgrades, Stand Alone Network 

Upgrades or Network Upgrades. 

Transmission System shall mean the 

facilities owned, controlled or operated by 

the Transmission Provider or Transmission 

Owner that are used to provide transmission 

service under the Tariff. 

Trial Operation shall mean the period 

during which Interconnection Customer is 

engaged in on-site test operations and 

commissioning of the Generating Facility 

prior to Commercial Operation. 

Section 2. Scope and Application 

2.1 Application of Standard Large 

Generator Interconnection Procedures 

Sections 2 through 13 apply to processing 

an Interconnection Request pertaining to a 

Large Generating Facility. 

2.2 Comparability 

Transmission Provider shall receive, 

process and analyze all Interconnection 

Requests in a timely manner as set forth in 

this LGIP. Transmission Provider will use the 

same Reasonable Efforts in processing and 

analyzing Interconnection Requests from all 

Interconnection Customers, whether the 

Generating Facilities are owned by 

Transmission Provider, its subsidiaries or 

Affiliates or others. 

2.3 Base Case Data 

Transmission Provider shall maintain base 

power flow, short circuit and stability 

databases, including all underlying 

assumptions, and contingency list on either 

its OASIS site or a password-protected 

website, subject to confidentiality provisions 

in LGIP Section 13.1. In addition, 

Transmission Provider shall maintain 

network models and underlying assumptions 

on either its OASIS site or a passwordprotected website. Such network models and 

underlying assumptions should reasonably 

represent those used during the most recent 

interconnection study and be representative 

of current system conditions. If Transmission 

Provider posts this information on a 

password-protected website, a link to the 

information must be provided on 

Transmission Provider’s OASIS site. 

Transmission Provider is permitted to require 

that Interconnection Customers, OASIS site 

users and password-protected website users 

sign a confidentiality agreement before the 

release of commercially sensitive information 

or Critical Energy Infrastructure Information 

in the Base Case data. Such databases and 

lists, hereinafter referred to as Base Cases, 

shall include all (1) generation projects and 

(2) transmission projects, including merchant 

transmission projects that are proposed for 

the Transmission System for which a 

transmission expansion plan has been 

submitted and approved by the applicable 

authority. 

2.4 No Applicability to Transmission 

Service 

Nothing in this LGIP shall constitute a 

request for transmission service or confer 

upon an Interconnection Customer any right 

to receive transmission service. 

Section 3. Interconnection Requests 

3.1 General 

An Interconnection Customer shall submit 

to Transmission Provider an Interconnection 

Request in the form of Appendix 1 to this 

LGIP and a refundable deposit of $10,000. 

Transmission Provider shall apply the 

deposit toward the cost of an Interconnection 

Feasibility Study. Interconnection Customer 

shall submit a separate Interconnection 

Request for each site and may submit 

multiple Interconnection Requests for a 

single site. Interconnection Customer must 

submit a deposit with each Interconnection 

Request even when more than one request is 

submitted for a single site. An 

Interconnection Request to evaluate one site 

at two different voltage levels shall be treated 

as two Interconnection Requests. 

At Interconnection Customer’s option, 

Transmission Provider and Interconnection 

Customer will identify alternative Point(s) of 

Interconnection and configurations at the 

Scoping Meeting to evaluate in this process 

and attempt to eliminate alternatives in a 

reasonable fashion given resources and 

information available. Interconnection 

Customer will select the definitive Point(s) of 

Interconnection to be studied no later than 

the execution of the Interconnection 

Feasibility Study Agreement. 

Transmission Provider shall have a process 

in place to consider requests for 

Interconnection Service below the Generating 

Facility Capacity. These requests for 

Interconnection Service shall be studied at 

the level of Interconnection Service 

requested for purposes of Interconnection 

Facilities, Network Upgrades, and associated 

costs, but may be subject to other studies at 

the full Generating Facility Capacity to 

ensure safety and reliability of the system, 

with the study costs borne by the 

Interconnection Customer. If after the 

additional studies are complete, 

Transmission Provider determines that 

additional Network Upgrades are necessary, 

then Transmission Provider must: (1) Specify 

which additional Network Upgrade costs are 

based on which studies; and (2) provide a 

detailed explanation of why the additional 

Network Upgrades are necessary. Any 

Interconnection Facility and/or Network 

Upgrade costs required for safety and 

reliability also would be borne by the 

Interconnection Customer. Interconnection 

Customers may be subject to additional 

control technologies as well as testing and 

validation of those technologies consistent 

with Article 6 of the LGIA. The necessary 

control technologies and protection systems 

shall be established in Appendix C of that 

executed, or requested to be filed 

unexecuted, LGIA. 

3.2 Identification of Types of 

Interconnection Services 

At the time the Interconnection Request is 

submitted, Interconnection Customer must 

request either Energy Resource 

Interconnection Service or Network Resource 

Interconnection Service, as described; 

provided, however, any Interconnection 

Customer requesting Network Resource 

Interconnection Service may also request that 

it be concurrently studied for Energy 

Resource Interconnection Service, up to the 

point when an Interconnection Facility Study 

Agreement is executed. Interconnection 

Customer may then elect to proceed with 

Network Resource Interconnection Service or 

to proceed under a lower level of 

interconnection service to the extent that 

only certain upgrades will be completed. 

3.2.1 Energy Resource Interconnection 

Service 

3.2.1.1 The Product 

Energy Resource Interconnection Service 

allows Interconnection Customer to connect 

the Large Generating Facility to the 

Transmission System and be eligible to 

deliver the Large Generating Facility’s output 

using the existing firm or non-firm capacity 

of the Transmission System on an ‘‘as 

available’’ basis. Energy Resource 

Interconnection Service does not in and of 

itself convey any right to deliver electricity 

to any specific customer or Point of Delivery. 

3.2.1.2 The Study 

The study consists of short circuit/fault 

duty, steady state (thermal and voltage) and 

stability analyses. The short circuit/fault duty 

analysis would identify direct 

Interconnection Facilities required and the 

Network Upgrades necessary to address short 

circuit issues associated with the 

Interconnection Facilities. The stability and 

steady state studies would identify necessary 

upgrades to allow full output of the proposed 

Large Generating Facility and would also 

identify the maximum allowed output, at the 

time the study is performed, of the 

interconnecting Large Generating Facility 

without requiring additional Network 

Upgrades. 

3.2.2 Network Resource Interconnection 

Service 

3.2.2.1 The Product 

Transmission Provider must conduct the 

necessary studies and construct the Network 

Upgrades needed to integrate the Large 

Generating Facility (1) in a manner 

comparable to that in which Transmission 

Provider integrates its generating facilities to 

serve native load customers; or (2) in an ISO 

or RTO with market based congestion 

management, in the same manner as Network 

Resources. Network Resource 

Interconnection Service Allows 

Interconnection Customer’s Large Generating 

Facility to be designated as a Network 

Resource, up to the Large Generating 

Facility’s full output, on the same basis as 

existing Network Resources interconnected 

to Transmission Provider’s Transmission 

System, and to be studied as a Network 

Resource on the assumption that such a 

designation will occur. 

3.2.2.2 The Study 

The Interconnection Study for Network 

Resource Interconnection Service shall 

assure that Interconnection Customer’s Large 

Generating Facility meets the requirements 

for Network Resource Interconnection 

Service and as a general matter, that such 


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Large Generating Facility’s interconnection is 

also studied with Transmission Provider’s 

Transmission System at peak load, under a 

variety of severely stressed conditions, to 

determine whether, with the Large 

Generating Facility at full output, the 

aggregate of generation in the local area can 

be delivered to the aggregate of load on 

Transmission Provider’s Transmission 

System, consistent with Transmission 

Provider’s reliability criteria and procedures. 

This approach assumes that some portion of 

existing Network Resources are displaced by 

the output of Interconnection Customer’s 

Large Generating Facility. Network Resource 

Interconnection Service in and of itself does 

not convey any right to deliver electricity to 

any specific customer or Point of Delivery. 

The Transmission Provider may also study 

the Transmission System under non-peak 

load conditions. However, upon request by 

the Interconnection Customer, the 

Transmission Provider must explain in 

writing to the Interconnection Customer why 

the study of non-peak load conditions is 

required for reliability purposes. 

3.3 Utilization of Surplus Interconnection 

Service 

Transmission Provider must provide a 

process that allows an Interconnection 

Customer to utilize or transfer Surplus 

Interconnection Service at an existing Point 

of Interconnection. The original 

Interconnection Customer or one of its 

affiliates shall have priority to utilize Surplus 

Interconnection Service. If the existing 

Interconnection Customer or one of its 

affiliates does not exercise its priority, then 

that service may be made available to other 

potential Interconnection Customers. 

3.3.1 Surplus Interconnection Service 

Requests 

Surplus Interconnection Service requests 

may be made by the existing Interconnection 

Customer whose Generating Facility is 

already interconnected or one of its affiliates. 

Surplus Interconnection Service requests also 

may be made by another Interconnection 

Customer. Transmission Provider shall 

provide a process for evaluating 

Interconnection Requests for Surplus 

Interconnection Service. Studies for Surplus 

Interconnection Service shall consist of 

reactive power, short circuit/fault duty, 

stability analyses, and any other appropriate 

studies. Steady-state (thermal/voltage) 

analyses may be performed as necessary to 

ensure that all required reliability conditions 

are studied. If the Surplus Interconnection 

Service was not studied under off-peak 

conditions, off-peak steady state analyses 

shall be performed to the required level 

necessary to demonstrate reliable operation 

of the Surplus Interconnection Service. If the 

original System Impact Study is not available 

for the Surplus Interconnection Service, both 

off-peak and peak analysis may need to be 

performed for the existing Generating Facility 

associated with the request for Surplus 

Interconnection Service. The reactive power, 

short circuit/fault duty, stability, and steadystate analyses for Surplus Interconnection 

Service will identify any additional 

Interconnection Facilities and/or Network 

Upgrades necessary. 

3.4 Valid Interconnection Request 

3.4.1 Initiating an Interconnection Request 

To initiate an Interconnection Request, 

Interconnection Customer must submit all of 

the following: (i) A $10,000 deposit, (ii) a 

completed application in the form of 

Appendix 1, and (iii) demonstration of Site 

Control or a posting of an additional deposit 

of $10,000. Such deposits shall be applied 

toward any Interconnection Studies pursuant 

to the Interconnection Request. If 

Interconnection Customer demonstrates Site 

Control within the cure period specified in 

Section 3.4.3 after submitting its 

Interconnection Request, the additional 

deposit shall be refundable; otherwise, all 

such deposit(s), additional and initial, 

become non-refundable. 

The expected In-Service Date of the new 

Large Generating Facility or increase in 

capacity of the existing Generating Facility 

shall be no more than the process window for 

the regional expansion planning period (or in 

the absence of a regional planning process, 

the process window for Transmission 

Provider’s expansion planning period) not to 

exceed seven years from the date the 

Interconnection Request is received by 

Transmission Provider, unless 

Interconnection Customer demonstrates that 

engineering, permitting and construction of 

the new Large Generating Facility or increase 

in capacity of the existing Generating Facility 

will take longer than the regional expansion 

planning period. The In-Service Date may 

succeed the date the Interconnection Request 

is received by Transmission Provider by a 

period up to ten years, or longer where 

Interconnection Customer and Transmission 

Provider agree, such agreement not to be 

unreasonably withheld. 

3.4.2 Acknowledgment of Interconnection 

Request 

Transmission Provider shall acknowledge 

receipt of the Interconnection Request within 

five (5) Business Days of receipt of the 

request and attach a copy of the received 

Interconnection Request to the 

acknowledgement. 

3.4.3 Deficiencies in Interconnection 

Request 

An Interconnection Request will not be 

considered to be a valid request until all 

items in Section 3.4.1 have been received by 

Transmission Provider. If an Interconnection 

Request fails to meet the requirements set 

forth in Section 3.4.1, Transmission Provider 

shall notify Interconnection Customer within 

five (5) Business Days of receipt of the initial 

Interconnection Request of the reasons for 

such failure and that the Interconnection 

Request does not constitute a valid request. 

Interconnection Customer shall provide 

Transmission Provider the additional 

requested information needed to constitute a 

valid request within ten (10) Business Days 

after receipt of such notice. Failure by 

Interconnection Customer to comply with 

this Section 3.4.3 shall be treated in 

accordance with Section 3.7. 

3.4.4 Scoping Meeting 

Within ten (10) Business Days after receipt 

of a valid Interconnection Request, 

Transmission Provider shall establish a date 

agreeable to Interconnection Customer for the 

Scoping Meeting, and such date shall be no 

later than thirty (30) Calendar Days from 

receipt of the valid Interconnection Request, 

unless otherwise mutually agreed upon by 

the Parties. 

The purpose of the Scoping Meeting shall 

be to discuss alternative interconnection 

options, to exchange information including 

any transmission data that would reasonably 

be expected to impact such interconnection 

options, to analyze such information and to 

determine the potential feasible Points of 

Interconnection. Transmission Provider and 

Interconnection Customer will bring to the 

meeting such technical data, including, but 

not limited to: (i) General facility loadings, 

(ii) general instability issues, (iii) general 

short circuit issues, (iv) general voltage 

issues, and (v) general reliability issues as 

may be reasonably required to accomplish 

the purpose of the meeting. Transmission 

Provider and Interconnection Customer will 

also bring to the meeting personnel and other 

resources as may be reasonably required to 

accomplish the purpose of the meeting in the 

time allocated for the meeting. On the basis 

of the meeting, Interconnection Customer 

shall designate its Point of Interconnection, 

pursuant to Section 6.1, and one or more 

available alternative Point(s) of 

Interconnection. The duration of the meeting 

shall be sufficient to accomplish its purpose. 

3.5. OASIS Posting 

3.5.1 

Transmission Provider will maintain on its 

OASIS a list of all Interconnection Requests. 

The list will identify, for each 

Interconnection Request: (i) The maximum 

summer and winter megawatt electrical 

output; (ii) the location by county and state; 

(iii) the station or transmission line or lines 

where the interconnection will be made; (iv) 

the projected In-Service Date; (v) the status 

of the Interconnection Request, including 

Queue Position; (vi) the type of 

Interconnection Service being requested; and 

(vii) the availability of any studies related to 

the Interconnection Request; (viii) the date of 

the Interconnection Request; (ix) the type of 

Generating Facility to be constructed 

(combined cycle, base load or combustion 

turbine and fuel type); and (x) for 

Interconnection Requests that have not 

resulted in a completed interconnection, an 

explanation as to why it was not completed. 

Except in the case of an Affiliate, the list will 

not disclose the identity of Interconnection 

Customer until Interconnection Customer 

executes an LGIA or requests that 

Transmission Provider file an unexecuted 

LGIA with FERC. Before holding a Scoping 

Meeting with its Affiliate, Transmission 

Provider shall post on OASIS an advance 

notice of its intent to do so. Transmission 

Provider shall post to its OASIS site any 

deviations from the study timelines set forth 

herein. Interconnection Study reports and 

Optional Interconnection Study reports shall 

be posted to Transmission Provider’s OASIS 

site subsequent to the meeting between 

Interconnection Customer and Transmission 

Provider to discuss the applicable study 

results. Transmission Provider shall also post 

any known deviations in the Large 

Generating Facility’s In-Service Date. 


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3.5.2 Requirement To Post Interconnection 

Study Metrics 

Transmission Provider will maintain on its 

OASIS or its website summary statistics 

related to processing Interconnection Studies 

pursuant to Interconnection Requests, 

updated quarterly. If Transmission Provider 

posts this information on its website, a link 

to the information must be provided on 

Transmission Provider’s OASIS site. For each 

calendar quarter, Transmission Providers 

must calculate and post the information 

detailed in sections 3.5.2.1 through 3.5.2.4. 

3.5.2.1 Interconnection Feasibility Studies 

Processing Time 

(A) Number of Interconnection Requests 

that had Interconnection Feasibility Studies 

completed within Transmission Provider’s 

coordinated region during the reporting 

quarter, 

(B) Number of Interconnection Requests 

that had Interconnection Feasibility Studies 

completed within Transmission Provider’s 

coordinated region during the reporting 

quarter that were completed more than 

[timeline as listed in Transmission Provider’s 

LGIP] after receipt by Transmission Provider 

of the Interconnection Customer’s executed 

Interconnection Feasibility Study Agreement, 

(C) At the end of the reporting quarter, the 

number of active valid Interconnection 

Requests with ongoing incomplete 

Interconnection Feasibility Studies where 

such Interconnection Requests had executed 

Interconnection Feasibility Study 

Agreements received by Transmission 

Provider more than [timeline as listed in 

Transmission Provider’s LGIP] before the 

reporting quarter end, 

(D) Mean time (in days), Interconnection 

Feasibility Studies completed within 

Transmission Provider’s coordinated region 

during the reporting quarter, from the date 

when Transmission Provider received the 

executed Interconnection Feasibility Study 

Agreement to the date when Transmission 

Provider provided the completed 

Interconnection Feasibility Study to the 

Interconnection Customer, 

(E) Percentage of Interconnection 

Feasibility Studies exceeding [timeline as 

listed in Transmission Provider’s LGIP] to 

complete this reporting quarter, calculated as 

the sum of 3.5.2.1(B) plus 3.5.2.1(C) divided 

by the sum of 3.5.2.1(A) plus 3.5.2.1(C)). 

3.5.2.2 Interconnection System Impact 

Studies Processing Time 

(A) Number of Interconnection Requests 

that had Interconnection System Impact 

Studies completed within Transmission 

Provider’s coordinated region during the 

reporting quarter, 

(B) Number of Interconnection Requests 

that had Interconnection System Impact 

Studies completed within Transmission 

Provider’s coordinated region during the 

reporting quarter that were completed more 

than [timeline as listed in Transmission 

Provider’s LGIP] after receipt by 

Transmission Provider of the Interconnection 

Customer’s executed Interconnection System 

Impact Study Agreement, 

(C) At the end of the reporting quarter, the 

number of active valid Interconnection 

Requests with ongoing incomplete System 

Impact Studies where such Interconnection 

Requests had executed Interconnection 

System Impact Study Agreements received 

by Transmission Provider more than 

[timeline as listed in Transmission Provider’s 

LGIP] before the reporting quarter end, 

(D) Mean time (in days), Interconnection 

System Impact Studies completed within 

Transmission Provider’s coordinated region 

during the reporting quarter, from the date 

when Transmission Provider received the 

executed Interconnection System Impact 

Study Agreement to the date when 

Transmission Provider provided the 

completed Interconnection System Impact 

Study to the Interconnection Customer, 

(E) Percentage of Interconnection System 

Impact Studies exceeding [timeline as listed 

in Transmission Provider’s LGIP] to complete 

this reporting quarter, calculated as the sum 

of 3.5.2.2(B) plus 3.5.2.2(C) divided by the 

sum of 3.5.2.2(A) plus 3.5.2.2(C)). 

3.5.2.3 Interconnection Facilities Studies 

Processing Time 

(A) Number of Interconnection Requests 

that had Interconnection Facilities Studies 

that are completed within Transmission 

Provider’s coordinated region during the 

reporting quarter, 

(B) Number of Interconnection Requests 

that had Interconnection Facilities Studies 

that are completed within Transmission 

Provider’s coordinated region during the 

reporting quarter that were completed more 

than [timeline as listed in Transmission 

Provider’s LGIP] after receipt by 

Transmission Provider of the Interconnection 

Customer’s executed Interconnection 

Facilities Study Agreement, 

(C) At the end of the reporting quarter, the 

number of active valid Interconnection 

Service requests with ongoing incomplete 

Interconnection Facilities Studies where 

such Interconnection Requests had executed 

Interconnection Facilities Studies Agreement 

received by Transmission Provider more than 

[timeline as listed in Transmission Provider’s 

LGIP] before the reporting quarter end, 

(D) Mean time (in days), for 

Interconnection Facilities Studies completed 

within Transmission Provider’s coordinated 

region during the reporting quarter, 

calculated from the date when Transmission 

Provider received the executed 

Interconnection Facilities Study Agreement 

to the date when Transmission Provider 

provided the completed Interconnection 

Facilities Study to the Interconnection 

Customer, 

(E) Percentage of delayed Interconnection 

Facilities Studies this reporting quarter, 

calculated as the sum of 3.5.2.3(B) plus 

3.5.2.3(C) divided by the sum of 3.5.2.3(A) 

plus 3.5.2.3(C)). 

3.5.2.4 Interconnection Service Requests 

Withdrawn From Interconnection Queue 

(A) Number of Interconnection Requests 

withdrawn from Transmission Provider’s 

interconnection queue during the reporting 

quarter, 

(B) Number of Interconnection Requests 

withdrawn from Transmission Provider’s 

interconnection queue during the reporting 

quarter before completion of any 

interconnection studies or execution of any 

interconnection study agreements, 

(C) Number of Interconnection Requests 

withdrawn from Transmission Provider’s 

interconnection queue during the reporting 

quarter before completion of an 

Interconnection System Impact Study, 

(D) Number of Interconnection Requests 

withdrawn from Transmission Provider’s 

interconnection queue during the reporting 

quarter before completion of an 

Interconnection Facilities Study, 

(E) Number of Interconnection Requests 

withdrawn from Transmission Provider’s 

interconnection queue after execution of a 

generator interconnection agreement or 

Interconnection Customer requests the filing 

of an unexecuted, new interconnection 

agreement, 

(F) Mean time (in days), for all withdrawn 

Interconnection Requests, from the date 

when the request was determined to be valid 

to when Transmission Provider received the 

request to withdraw from the queue. 

3.5.3 

Transmission Provider is required to post 

on OASIS or its website the measures in 

paragraph 3.5.2.1(A) through paragraph 

3.5.2.4(F) for each calendar quarter within 30 

days of the end of the calendar quarter. 

Transmission Provider will keep the 

quarterly measures posted on OASIS or its 

website for three calendar years with the first 

required report to be in the first quarter of 

2020. If Transmission Provider retains this 

information on its website, a link to the 

information must be provided on 

Transmission Provider’s OASIS site. 

3.5.4 

In the event that any of the values 

calculated in paragraphs 3.5.2.1(E), 3.5.2.2(E) 

or 3.5.2.3(E) exceeds 25 percent for two 

consecutive calendar quarters, Transmission 

Provider will have to comply with the 

measures below for the next four consecutive 

calendar quarters and must continue 

reporting this information until Transmission 

Provider reports four consecutive calendar 

quarters without the values calculated in 

3.5.2.1(E), 3.5.2.2(E) or 3.5.2.3(E) exceeding 

25 percent for two consecutive calendar 

quarters: 

(i) Transmission Provider must submit a 

report to the Commission describing the 

reason for each study or group of clustered 

studies pursuant to an Interconnection 

Request that exceeded its deadline (i.e., 45, 

90 or 180 days) for completion (excluding 

any allowance for Reasonable Efforts). 

Transmission Provider must describe the 

reasons for each study delay and any steps 

taken to remedy these specific issues and, if 

applicable, prevent such delays in the future. 

The report must be filed at the Commission 

within 45 days of the end of the calendar 

quarter. 

(ii) Transmission Provider shall aggregate 

the total number of employee-hours and third 

party consultant hours expended towards 

interconnection studies within its 

coordinated region that quarter and post on 

OASIS or its website. If Transmission 

Provider posts this information on its 

website, a link to the information must be 

provided on Transmission Provider’s OASIS 

site. This information is to be posted within 

30 days of the end of the calendar quarter. 


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3.6 Coordination With Affected Systems 

Transmission Provider will coordinate the 

conduct of any studies required to determine 

the impact of the Interconnection Request on 

Affected Systems with Affected System 

Operators and, if possible, include those 

results (if available) in its applicable 

Interconnection Study within the time frame 

specified in this LGIP. Transmission Provider 

will include such Affected System Operators 

in all meetings held with Interconnection 

Customer as required by this LGIP. 

Interconnection Customer will cooperate 

with Transmission Provider in all matters 

related to the conduct of studies and the 

determination of modifications to Affected 

Systems. A Transmission Provider which 

may be an Affected System shall cooperate 

with Transmission Provider with whom 

interconnection has been requested in all 

matters related to the conduct of studies and 

the determination of modifications to 

Affected Systems. 

3.7 Withdrawal 

Interconnection Customer may withdraw 

its Interconnection Request at any time by 

written notice of such withdrawal to 

Transmission Provider. In addition, if 

Interconnection Customer fails to adhere to 

all requirements of this LGIP, except as 

provided in Section 13.5 (Disputes), 

Transmission Provider shall deem the 

Interconnection Request to be withdrawn and 

shall provide written notice to 

Interconnection Customer of the deemed 

withdrawal and an explanation of the reasons 

for such deemed withdrawal. Upon receipt of 

such written notice, Interconnection 

Customer shall have fifteen (15) Business 

Days in which to either respond with 

information or actions that cures the 

deficiency or to notify Transmission Provider 

of its intent to pursue Dispute Resolution. 

Withdrawal shall result in the loss of 

Interconnection Customer’s Queue Position. 

If an Interconnection Customer disputes the 

withdrawal and loss of its Queue Position, 

then during Dispute Resolution, 

Interconnection Customer’s Interconnection 

Request is eliminated from the queue until 

such time that the outcome of Dispute 

Resolution would restore its Queue Position. 

An Interconnection Customer that withdraws 

or is deemed to have withdrawn its 

Interconnection Request shall pay to 

Transmission Provider all costs that 

Transmission Provider prudently incurs with 

respect to that Interconnection Request prior 

to Transmission Provider’s receipt of notice 

described above. Interconnection Customer 

must pay all monies due to Transmission 

Provider before it is allowed to obtain any 

Interconnection Study data or results. 

Transmission Provider shall (i) update the 

OASIS Queue Position posting and (ii) 

refund to Interconnection Customer any 

portion of Interconnection Customer’s 

deposit or study payments that exceeds the 

costs that Transmission Provider has 

incurred, including interest calculated in 

accordance with section 35.19a(a)(2) of 

FERC’s regulations. In the event of such 

withdrawal, Transmission Provider, subject 

to the confidentiality provisions of Section 

13.1, shall provide, at Interconnection 

Customer’s request, all information that 

Transmission Provider developed for any 

completed study conducted up to the date of 

withdrawal of the Interconnection Request. 

3.8 Identification of Contingent Facilities 

Transmission Provider shall post in this 

section a method for identifying the 

Contingent Facilities to be provided to 

Interconnection Customer at the conclusion 

of the System Impact Study and included in 

Interconnection Customer’s Large Generator 

Interconnection Agreement. The method 

shall be sufficiently transparent to determine 

why a specific Contingent Facility was 

identified and how it relates to the 

Interconnection Request. Transmission 

Provider shall also provide, upon request of 

the Interconnection Customer, the estimated 

Interconnection Facility and/or Network 

Upgrade costs and estimated in-service 

completion time of each identified 

Contingent Facility when this information is 

readily available and not commercially 

sensitive. 

3.10 Repeat Network Upgrades for 

Consideration in the Regional Transmission 

Planning Process 

If Transmission Provider: (1) Identifies a 

Network Upgrade with an interconnection 

study estimated cost of at least $30 million 

or with a voltage of at least 200 kV as 

necessary to accomplish an interconnection 

and the underlying interconnection request 

related to such Network Upgrade is 

withdrawn; (2) if, within five years of that 

withdrawal, Transmission Provider identifies 

a Network Upgrade with an interconnection 

study estimated cost of at least $30 million 

or with a voltage of at least 200 kV to address 

a similar interconnection-related need as 

specified in (1) and the underlying 

interconnection request with cost 

responsibility for the second identified 

Network Upgrade is withdrawn; and (3) a 

similar interconnection-related need is not 

addressed by any Network Upgrade 

described in Appendix A of any executed 

Large Generator Interconnection Agreement 

or any Large Generator Interconnection 

Agreement that an Interconnection Customer 

has requested that Transmission Provider file 

with the Commission unexecuted, then 

Transmission Provider shall consider the 

interconnection-related need addressed by 

the Network Upgrade(s) that Transmission 

Provider identified in the interconnection 

queue cycles specified in (1) and (2) in LongTerm Regional Transmission Planning. 

Section 4. Queue Position 

4.1 General 

Transmission Provider shall assign a 

Queue Position based upon the date and time 

of receipt of the valid Interconnection 

Request; provided that, if the sole reason an 

Interconnection Request is not valid is the 

lack of required information on the 

application form, and Interconnection 

Customer provides such information in 

accordance with Section 3.4.3, then 

Transmission Provider shall assign 

Interconnection Customer a Queue Position 

based on the date the application form was 

originally filed. Moving a Point of 

Interconnection shall result in a lowering of 

Queue Position if it is deemed a Material 

Modification under Section 4.4.3. 

The Queue Position of each 

Interconnection Request will be used to 

determine the order of performing the 

Interconnection Studies and determination of 

cost responsibility for the facilities necessary 

to accommodate the Interconnection Request. 

A higher queued Interconnection Request is 

one that has been placed ‘‘earlier’’ in the 

queue in relation to another Interconnection 

Request that is lower queued. 

Transmission Provider may allocate the 

cost of the common upgrades for clustered 

Interconnection Requests without regard to 

Queue Position. 

4.2 Clustering 

At Transmission Provider’s option, 

Interconnection Requests may be studied 

serially or in clusters for the purpose of the 

Interconnection System Impact Study. 

Clustering shall be implemented on the 

basis of Queue Position. If Transmission 

Provider elects to study Interconnection 

Requests using Clustering, all 

Interconnection Requests received within a 

period not to exceed one hundred and eighty 

(180) Calendar Days, hereinafter referred to 

as the ‘‘Queue Cluster Window’’ shall be 

studied together without regard to the nature 

of the underlying Interconnection Service, 

whether Energy Resource Interconnection 

Service or Network Resource Interconnection 

Service. The deadline for completing all 

Interconnection System Impact Studies for 

which an Interconnection System Impact 

Study Agreement has been executed during 

a Queue Cluster Window shall be in 

accordance with Section 7.4, for all 

Interconnection Requests assigned to the 

same Queue Cluster Window. Transmission 

Provider may study an Interconnection 

Request separately to the extent warranted by 

Good Utility Practice based upon the 

electrical remoteness of the proposed Large 

Generating Facility. 

Clustering Interconnection System Impact 

Studies shall be conducted in such a manner 

to ensure the efficient implementation of the 

applicable regional transmission expansion 

plan in light of the Transmission System’s 

capabilities at the time of each study. 

The Queue Cluster Window shall have a 

fixed time interval based on fixed annual 

opening and closing dates. Any changes to 

the established Queue Cluster Window 

interval and opening or closing dates shall be 

announced with a posting on Transmission 

Provider’s OASIS beginning at least one 

hundred and eighty (180) Calendar Days in 

advance of the change and continuing 

thereafter through the end date of the first 

Queue Cluster Window that is to be 

modified. 

4.3 Transferability of Queue Position 

An Interconnection Customer may transfer 

its Queue Position to another entity only if 

such entity acquires the specific Generating 

Facility identified in the Interconnection 

Request and the Point of Interconnection 

does not change. 


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4.4 Modifications 

Interconnection Customer shall submit to 

Transmission Provider, in writing, 

modifications to any information provided in 

the Interconnection Request. Interconnection 

Customer shall retain its Queue Position if 

the modifications are in accordance with 

Sections 4.4.1, 4.4.2 or 4.4.5, or are 

determined not to be Material Modifications 

pursuant to Section 4.4.3. 

Notwithstanding the above, during the 

course of the Interconnection Studies, either 

Interconnection Customer or Transmission 

Provider may identify changes to the planned 

interconnection that may improve the costs 

and benefits (including reliability) of the 

interconnection, and the ability of the 

proposed change to accommodate the 

Interconnection Request. To the extent the 

identified changes are acceptable to 

Transmission Provider and Interconnection 

Customer, such acceptance not to be 

unreasonably withheld, Transmission 

Provider shall modify the Point of 

Interconnection and/or configuration in 

accordance with such changes and proceed 

with any re-studies necessary to do so in 

accordance with Section 6.4, Section 7.6 and 

Section 8.5 as applicable and Interconnection 

Customer shall retain its Queue Position. 

4.4.1 

Prior to the return of the executed 

Interconnection System Impact Study 

Agreement to Transmission Provider, 

modifications permitted under this Section 

shall include specifically: (a) A decrease of 

up to 60 percent of electrical output (MW) of 

the proposed project, through either (1) a 

decrease in plant size or (2) a decrease in 

Interconnection Service level (consistent 

with the process described in Section 3.1) 

accomplished by applying Transmission 

Provider-approved injection-limiting 

equipment; (b) modifying the technical 

parameters associated with the Large 

Generating Facility technology or the Large 

Generating Facility step-up transformer 

impedance characteristics; and (c) modifying 

the interconnection configuration. For plant 

increases, the incremental increase in plant 

output will go to the end of the queue for the 

purposes of cost allocation and study 

analysis. 

4.4.2 

Prior to the return of the executed 

Interconnection Facility Study Agreement to 

Transmission Provider, the modifications 

permitted under this Section shall include 

specifically: (a) Additional 15 percent 

decrease of electrical output of the proposed 

project through either (1) a decrease in plant 

size (MW) or (2) a decrease in 

Interconnection Service level (consistent 

with the process described in Section 3.1) 

accomplished by applying Transmission 

Provider-approved injection-limiting 

equipment; (b) Large Generating Facility 

technical parameters associated with 

modifications to Large Generating Facility 

technology and transformer impedances; 

provided, however, the incremental costs 

associated with those modifications are the 

responsibility of the requesting 

Interconnection Customer; and (c) a 

Permissible Technological Advancement for 

the Large Generating Facility after the 

submission of the Interconnection Request. 

Section 4.4.6 specifies a separate 

technological change procedure including 

the requisite information and process that 

will be followed to assess whether the 

Interconnection Customer’s proposed 

technological advancement under Section 

4.4.2(c) is a Material Modification. Section 1 

contains a definition of Permissible 

Technological Advancement. 

4.4.3 

Prior to making any modification other 

than those specifically permitted by Sections 

4.4.1, 4.4.2, and 4.4.5, Interconnection 

Customer may first request that Transmission 

Provider evaluate whether such modification 

is a Material Modification. In response to 

Interconnection Customer’s request, 

Transmission Provider shall evaluate the 

proposed modifications prior to making them 

and inform Interconnection Customer in 

writing of whether the modifications would 

constitute a Material Modification. Any 

change to the Point of Interconnection, 

except those deemed acceptable under 

Sections 4.4.1, 6.1, 7.2 or so allowed 

elsewhere, shall constitute a Material 

Modification. Interconnection Customer may 

then withdraw the proposed modification or 

proceed with a new Interconnection Request 

for such modification. 

4.4.4 

Upon receipt of Interconnection 

Customer’s request for modification 

permitted under this Section 4.4, 

Transmission Provider shall commence and 

perform any necessary additional studies as 

soon as practicable, but in no event shall 

Transmission Provider commence such 

studies later than thirty (30) Calendar Days 

after receiving notice of Interconnection 

Customer’s request. Any additional studies 

resulting from such modification shall be 

done at Interconnection Customer’s cost. 

4.4.5 

Extensions of less than three (3) 

cumulative years in the Commercial 

Operation Date of the Large Generating 

Facility to which the Interconnection Request 

relates are not material and should be 

handled through construction sequencing. 

4.4.6 Technological Change Procedures 

[Insert technological change procedure 

here] 

Section 5. Procedures for Interconnection 

Requests Submitted Prior to Effective Date of 

Standard Large Generator Interconnection 

Procedures 

5.1 Queue Position for Pending Requests 

5.1.1 

Any Interconnection Customer assigned a 

Queue Position prior to the effective date of 

this LGIP shall retain that Queue Position. 

5.1.1.1 

If an Interconnection Study Agreement has 

not been executed as of the effective date of 

this LGIP, then such Interconnection Study, 

and any subsequent Interconnection Studies, 

shall be processed in accordance with this 

LGIP. 

5.1.1.2 

If an Interconnection Study Agreement has 

been executed prior to the effective date of 

this LGIP, such Interconnection Study shall 

be completed in accordance with the terms 

of such agreement. With respect to any 

remaining studies for which an 

Interconnection Customer has not signed an 

Interconnection Study Agreement prior to the 

effective date of the LGIP, Transmission 

Provider must offer Interconnection 

Customer the option of either continuing 

under Transmission Provider’s existing 

interconnection study process or going 

forward with the completion of the necessary 

Interconnection Studies (for which it does 

not have a signed Interconnection Studies 

Agreement) in accordance with this LGIP. 

5.1.1.3 

If an LGIA has been submitted to FERC for 

approval before the effective date of the LGIP, 

then the LGIA would be grandfathered. 

5.1.2 Transition Period 

To the extent necessary, Transmission 

Provider and Interconnection Customers with 

an outstanding request (i.e., an 

Interconnection Request for which an LGIA 

has not been submitted to FERC for approval 

as of the effective date of this LGIP) shall 

transition to this LGIP within a reasonable 

period of time not to exceed sixty (60) 

Calendar Days. The use of the term 

‘‘outstanding request’’ herein shall mean any 

Interconnection Request, on the effective date 

of this LGIP: (i) That has been submitted but 

not yet accepted by Transmission Provider; 

(ii) where the related interconnection 

agreement has not yet been submitted to 

FERC for approval in executed or unexecuted 

form, (iii) where the relevant Interconnection 

Study Agreements have not yet been 

executed, or (iv) where any of the relevant 

Interconnection Studies are in process but 

not yet completed. Any Interconnection 

Customer with an outstanding request as of 

the effective date of this LGIP may request a 

reasonable extension of any deadline, 

otherwise applicable, if necessary to avoid 

undue hardship or prejudice to its 

Interconnection Request. A reasonable 

extension shall be granted by Transmission 

Provider to the extent consistent with the 

intent and process provided for under this 

LGIP. 

5.2 New Transmission Provider 

If Transmission Provider transfers control 

of its Transmission System to a successor 

Transmission Provider during the period 

when an Interconnection Request is pending, 

the original Transmission Provider shall 

transfer to the successor Transmission 

Provider any amount of the deposit or 

payment with interest thereon that exceeds 

the cost that it incurred to evaluate the 

request for interconnection. Any difference 

between such net amount and the deposit or 

payment required by this LGIP shall be paid 

by or refunded to the Interconnection 

Customer, as appropriate. The original 

Transmission Provider shall coordinate with 

the successor Transmission Provider to 

complete any Interconnection Study, as 

appropriate, that the original Transmission 

Provider has begun but has not completed. If 


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Transmission Provider has tendered a draft 

LGIA to Interconnection Customer but 

Interconnection Customer has not either 

executed the LGIA or requested the filing of 

an unexecuted LGIA with FERC, unless 

otherwise provided, Interconnection 

Customer must complete negotiations with 

the successor Transmission Provider. 

Section 6. Interconnection Feasibility Study 

6.1 Interconnection Feasibility Study 

Agreement 

Simultaneously with the acknowledgement 

of a valid Interconnection Request 

Transmission Provider shall provide to 

Interconnection Customer an Interconnection 

Feasibility Study Agreement in the form of 

Appendix 2. The Interconnection Feasibility 

Study Agreement shall specify that 

Interconnection Customer is responsible for 

the actual cost of the Interconnection 

Feasibility Study. Within five (5) Business 

Days following the Scoping Meeting 

Interconnection Customer shall specify for 

inclusion in the attachment to the 

Interconnection Feasibility Study Agreement 

the Point(s) of Interconnection and any 

reasonable alternative Point(s) of 

Interconnection. Within five (5) Business 

Days following Transmission Provider’s 

receipt of such designation, Transmission 

Provider shall tender to Interconnection 

Customer the Interconnection Feasibility 

Study Agreement signed by Transmission 

Provider, which includes a good faith 

estimate of the cost for completing the 

Interconnection Feasibility Study. 

Interconnection Customer shall execute and 

deliver to Transmission Provider the 

Interconnection Feasibility Study Agreement 

along with a $10,000 deposit no later than 

thirty (30) Calendar Days after its receipt. 

On or before the return of the executed 

Interconnection Feasibility Study Agreement 

to Transmission Provider, Interconnection 

Customer shall provide the technical data 

called for in Appendix 1, Attachment A. 

If the Interconnection Feasibility Study 

uncovers any unexpected result(s) not 

contemplated during the Scoping Meeting, a 

substitute Point of Interconnection identified 

by either Interconnection Customer or 

Transmission Provider, and acceptable to the 

other, such acceptance not to be 

unreasonably withheld, will be substituted 

for the designated Point of Interconnection 

specified above without loss of Queue 

Position, and Re-studies shall be completed 

pursuant to Section 6.4 as applicable. For the 

purpose of this Section 6.1, if Transmission 

Provider and Interconnection Customer 

cannot agree on the substituted Point of 

Interconnection, then Interconnection 

Customer may direct that one of the 

alternatives as specified in the 

Interconnection Feasibility Study Agreement, 

as specified pursuant to Section 3.4.4, shall 

be the substitute. 

If Interconnection Customer and 

Transmission Provider agree to forgo the 

Interconnection Feasibility Study, 

Transmission Provider will initiate an 

Interconnection System Impact Study under 

Section 7 of this LGIP and apply the $10,000 

deposit towards the Interconnection System 

Impact Study. 

6.2 Scope of Interconnection Feasibility 

Study 

The Interconnection Feasibility Study shall 

preliminarily evaluate the feasibility of the 

proposed interconnection to the 

Transmission System. 

The Interconnection Feasibility Study will 

consider the Base Case as well as all 

generating facilities (and with respect to (iii), 

any identified Network Upgrades) that, on 

the date the Interconnection Feasibility 

Study is commenced: (i) Are directly 

interconnected to the Transmission System; 

(ii) are interconnected to Affected Systems 

and may have an impact on the 

Interconnection Request; (iii) have a pending 

higher queued Interconnection Request to 

interconnect to the Transmission System; 

and (iv) have no Queue Position but have 

executed an LGIA or requested that an 

unexecuted LGIA be filed with FERC. The 

Interconnection Feasibility Study will consist 

of a power flow and short circuit analysis. 

The Interconnection Feasibility Study will 

provide a list of facilities and a non-binding 

good faith estimate of cost responsibility and 

a non-binding good faith estimated time to 

construct. 

6.3 Interconnection Feasibility Study 

Procedures 

Transmission Provider shall utilize 

existing studies to the extent practicable 

when it performs the study. Transmission 

Provider shall use Reasonable Efforts to 

complete the Interconnection Feasibility 

Study no later than forty-five (45) Calendar 

Days after Transmission Provider receives the 

fully executed Interconnection Feasibility 

Study Agreement. At the request of 

Interconnection Customer or at any time 

Transmission Provider determines that it will 

not meet the required time frame for 

completing the Interconnection Feasibility 

Study, Transmission Provider shall notify 

Interconnection Customer as to the schedule 

status of the Interconnection Feasibility 

Study. If Transmission Provider is unable to 

complete the Interconnection Feasibility 

Study within that time period, it shall notify 

Interconnection Customer and provide an 

estimated completion date with an 

explanation of the reasons why additional 

time is required. Upon request, Transmission 

Provider shall provide Interconnection 

Customer supporting documentation, 

workpapers and relevant power flow, short 

circuit and stability databases for the 

Interconnection Feasibility Study, subject to 

confidentiality arrangements consistent with 

Section 13.1. 

Transmission Provider shall study the 

Interconnection Request at the level of 

service requested by the Interconnection 

Customer, unless otherwise required to study 

the full Generating Facility Capacity due to 

safety or reliability concerns. 

6.3.1 Meeting With Transmission Provider 

Within ten (10) Business Days of providing 

an Interconnection Feasibility Study report to 

Interconnection Customer, Transmission 

Provider and Interconnection Customer shall 

meet to discuss the results of the 

Interconnection Feasibility Study. 

6.4 Re-Study 

If Re-Study of the Interconnection 

Feasibility Study is required due to a higher 

queued project dropping out of the queue, or 

a modification of a higher queued project 

subject to Section 4.4, or re-designation of the 

Point of Interconnection pursuant to Section 

6.1 Transmission Provider shall notify 

Interconnection Customer in writing. Such 

Re-Study shall take not longer than forty-five 

(45) Calendar Days from the date of the 

notice. Any cost of Re-Study shall be borne 

by the Interconnection Customer being restudied. 

Section 7. Interconnection System Impact 

Study 

7.1 Interconnection System Impact Study 

Agreement 

Unless otherwise agreed, pursuant to the 

Scoping Meeting provided in Section 3.4.4, 

simultaneously with the delivery of the 

Interconnection Feasibility Study to 

Interconnection Customer, Transmission 

Provider shall provide to Interconnection 

Customer an Interconnection System Impact 

Study Agreement in the form of Appendix 3 

to this LGIP. The Interconnection System 

Impact Study Agreement shall provide that 

Interconnection Customer shall compensate 

Transmission Provider for the actual cost of 

the Interconnection System Impact Study. 

Within three (3) Business Days following the 

Interconnection Feasibility Study results 

meeting, Transmission Provider shall provide 

to Interconnection Customer a non-binding 

good faith estimate of the cost and timeframe 

for completing the Interconnection System 

Impact Study. 

7.2 Execution of Interconnection System 

Impact Study Agreement 

Interconnection Customer shall execute the 

Interconnection System Impact Study 

Agreement and deliver the executed 

Interconnection System Impact Study 

Agreement to Transmission Provider no later 

than thirty (30) Calendar Days after its receipt 

along with demonstration of Site Control, 

and a $50,000 deposit. 

If Interconnection Customer does not 

provide all such technical data when it 

delivers the Interconnection System Impact 

Study Agreement, Transmission Provider 

shall notify Interconnection Customer of the 

deficiency within five (5) Business Days of 

the receipt of the executed Interconnection 

System Impact Study Agreement and 

Interconnection Customer shall cure the 

deficiency within ten (10) Business Days of 

receipt of the notice, provided, however, 

such deficiency does not include failure to 

deliver the executed Interconnection System 

Impact Study Agreement or deposit. 

If the Interconnection System Impact Study 

uncovers any unexpected result(s) not 

contemplated during the Scoping Meeting 

and the Interconnection Feasibility Study, a 

substitute Point of Interconnection identified 

by either Interconnection Customer or 

Transmission Provider, and acceptable to the 

other, such acceptance not to be 

unreasonably withheld, will be substituted 

for the designated Point of Interconnection 

specified above without loss of Queue 

Position, and restudies shall be completed 


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pursuant to Section 7.6 as applicable. For the 

purpose of this Section 7.2, if Transmission 

Provider and Interconnection Customer 

cannot agree on the substituted Point of 

Interconnection, then Interconnection 

Customer may direct that one of the 

alternatives as specified in the 

Interconnection Feasibility Study Agreement, 

as specified pursuant to Section 3.4.4, shall 

be the substitute. 

7.3 Scope of Interconnection System Impact 

Study 

The Interconnection System Impact Study 

shall evaluate the impact of the proposed 

interconnection on the reliability of the 

Transmission System. The Interconnection 

System Impact Study will consider the Base 

Case as well as all generating facilities (and 

with respect to (iii) below, any identified 

Network Upgrades associated with such 

higher queued interconnection) that, on the 

date the Interconnection System Impact 

Study is commenced: (i) Are directly 

interconnected to the Transmission System; 

(ii) are interconnected to Affected Systems 

and may have an impact on the 

Interconnection Request; (iii) have a pending 

higher queued Interconnection Request to 

interconnect to the Transmission System; 

and (iv) have no Queue Position but have 

executed an LGIA or requested that an 

unexecuted LGIA be filed with FERC. 

The Interconnection System Impact Study 

will consist of a short circuit analysis, a 

stability analysis, and a power flow analysis. 

The Interconnection System Impact Study 

will state the assumptions upon which it is 

based; state the results of the analyses; and 

provide the requirements or potential 

impediments to providing the requested 

interconnection service, including a 

preliminary indication of the cost and length 

of time that would be necessary to correct 

any problems identified in those analyses 

and implement the interconnection. For 

purposes of determining necessary 

Interconnection Facilities and Network 

Upgrades, the System Impact Study shall 

consider the level of Interconnection Service 

requested by the Interconnection Customer, 

unless otherwise required to study the full 

Generating Facility Capacity due to safety or 

reliability concerns. The Interconnection 

System Impact Study will provide a list of 

facilities that are required as a result of the 

Interconnection Request and a non-binding 

good faith estimate of cost responsibility and 

a non-binding good faith estimated time to 

construct. 

7.4 Interconnection System Impact Study 

Procedures 

Impact Study with any Affected System 

that is affected by the Interconnection 

Request pursuant to Section 3.6 above. 

Transmission Provider shall utilize existing 

studies to the extent practicable when it 

performs the study. Transmission Provider 

shall use Reasonable Efforts to complete the 

Interconnection System Impact Study within 

ninety (90) Calendar Days after the receipt of 

the Interconnection System Impact Study 

Agreement or notification to proceed, study 

payment, and technical data. If Transmission 

Provider uses Clustering, Transmission 

Provider shall use Reasonable Efforts to 

deliver a completed Interconnection System 

Impact Study within ninety (90) Calendar 

Days after the close of the Queue Cluster 

Window. 

At the request of Interconnection Customer 

or at any time Transmission Provider 

determines that it will not meet the required 

time frame for completing the 

Interconnection System Impact Study, 

Transmission Provider shall notify 

Interconnection Customer as to the schedule 

status of the Interconnection System Impact 

Study. If Transmission Provider is unable to 

complete the Interconnection System Impact 

Study within the time period, it shall notify 

Interconnection Customer and provide an 

estimated completion date with an 

explanation of the reasons why additional 

time is required. Upon request, Transmission 

Provider shall provide Interconnection 

Customer all supporting documentation, 

workpapers and relevant pre-Interconnection 

Request and post-Interconnection Request 

power flow, short circuit and stability 

databases for the Interconnection System 

Impact Study, subject to confidentiality 

arrangements consistent with Section 13.1. 

7.5 Meeting With Transmission Provider 

Within ten (10) Business Days of providing 

an Interconnection System Impact Study 

report to Interconnection Customer, 

Transmission Provider and Interconnection 

Customer shall meet to discuss the results of 

the Interconnection System Impact Study. 

7.6 Re-Study 

If Re-Study of the Interconnection System 

Impact Study is required due to a higher 

queued project dropping out of the queue, or 

a modification of a higher queued project 

subject to 4.4, or re-designation of the Point 

of Interconnection pursuant to Section 7.2 

Transmission Provider shall notify 

Interconnection Customer in writing. Such 

Re-Study shall take no longer than sixty (60) 

Calendar Days from the date of notice. Any 

cost of Re-Study shall be borne by the 

Interconnection Customer being re-studied. 

Section 8. Interconnection Facilities Study 

8.1 Interconnection Facilities Study 

Agreement 

Simultaneously with the delivery of the 

Interconnection System Impact Study to 

Interconnection Customer, Transmission 

Provider shall provide to Interconnection 

Customer an Interconnection Facilities Study 

Agreement in the form of Appendix 4 to this 

LGIP. The Interconnection Facilities Study 

Agreement shall provide that Interconnection 

Customer shall compensate Transmission 

Provider for the actual cost of the 

Interconnection Facilities Study. Within 

three (3) Business Days following the 

Interconnection System Impact Study results 

meeting, Transmission Provider shall provide 

to Interconnection Customer a non-binding 

good faith estimate of the cost and timeframe 

for completing the Interconnection Facilities 

Study. Interconnection Customer shall 

execute the Interconnection Facilities Study 

Agreement and deliver the executed 

Interconnection Facilities Study Agreement 

to Transmission Provider within thirty (30) 

Calendar Days after its receipt, together with 

the required technical data and the greater of 

$100,000 or Interconnection Customer’s 

portion of the estimated monthly cost of 

conducting the Interconnection Facilities 

Study. 

8.1.1

Transmission Provider shall invoice 

Interconnection Customer on a monthly basis 

for the work to be conducted on the 

Interconnection Facilities Study each month. 

Interconnection Customer shall pay invoiced 

amounts within thirty (30) Calendar Days of 

receipt of invoice. Transmission Provider 

shall continue to hold the amounts on 

deposit until settlement of the final invoice. 

8.2 Scope of Interconnection Facilities 

Study 

The Interconnection Facilities Study shall 

specify and estimate the cost of the 

equipment, engineering, procurement and 

construction work needed to implement the 

conclusions of the Interconnection System 

Impact Study in accordance with Good 

Utility Practice to physically and electrically 

connect the Interconnection Facility to the 

Transmission System. The Interconnection 

Facilities Study shall also identify the 

electrical switching configuration of the 

connection equipment, including, without 

limitation: The transformer, switchgear, 

meters, and other station equipment; the 

nature and estimated cost of any 

Transmission Provider’s Interconnection 

Facilities and Network Upgrades necessary to 

accomplish the interconnection; and an 

estimate of the time required to complete the 

construction and installation of such 

facilities. The Facilities Study will also 

identify any potential control equipment for 

requests for Interconnection Service that are 

lower than the Generating Facility Capacity. 

8.3 Interconnection Facilities Study 

Procedures 

Transmission Provider shall coordinate the 

Interconnection Facilities Study with any 

Affected System pursuant to Section 3.6 

above. Transmission Provider shall utilize 

existing studies to the extent practicable in 

performing the Interconnection Facilities 

Study. Transmission Provider shall use 

Reasonable Efforts to complete the study and 

issue a draft Interconnection Facilities Study 

report to Interconnection Customer within 

the following number of days after receipt of 

an executed Interconnection Facilities Study 

Agreement: Ninety (90) Calendar Days, with 

no more than a ±20 percent cost estimate 

contained in the report; or one hundred 

eighty (180) Calendar Days, if 

Interconnection Customer requests a ±10 

percent cost estimate. 

At the request of Interconnection Customer 

or at any time Transmission Provider 

determines that it will not meet the required 

time frame for completing the 

Interconnection Facilities Study, 

Transmission Provider shall notify 

Interconnection Customer as to the schedule 

status of the Interconnection Facilities Study. 

If Transmission Provider is unable to 

complete the Interconnection Facilities Study 

and issue a draft Interconnection Facilities 

Study report within the time required, it 


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shall notify Interconnection Customer and 

provide an estimated completion date and an 

explanation of the reasons why additional 

time is required. 

Interconnection Customer may, within 

thirty (30) Calendar Days after receipt of the 

draft report, provide written comments to 

Transmission Provider, which Transmission 

Provider shall include in the final report. 

Transmission Provider shall issue the final 

Interconnection Facilities Study report 

within fifteen (15) Business Days of receiving 

Interconnection Customer’s comments or 

promptly upon receiving Interconnection 

Customer’s statement that it will not provide 

comments. Transmission Provider may 

reasonably extend such fifteen-day period 

upon notice to Interconnection Customer if 

Interconnection Customer’s comments 

require Transmission Provider to perform 

additional analyses or make other significant 

modifications prior to the issuance of the 

final Interconnection Facilities Report. Upon 

request, Transmission Provider shall provide 

Interconnection Customer supporting 

documentation, workpapers, and databases 

or data developed in the preparation of the 

Interconnection Facilities Study, subject to 

confidentiality arrangements consistent with 

Section 13.1. 

8.4 Meeting With Transmission Provider 

Within ten (10) Business Days of providing 

a draft Interconnection Facilities Study 

report to Interconnection Customer, 

Transmission Provider and Interconnection 

Customer shall meet to discuss the results of 

the Interconnection Facilities Study. 

8.5 Re-Study 

If Re-Study of the Interconnection 

Facilities Study is required due to a higher 

queued project dropping out of the queue or 

a modification of a higher queued project 

pursuant to Section 4.4, Transmission 

Provider shall so notify Interconnection 

Customer in writing. Such Re-Study shall 

take no longer than sixty (60) Calendar Days 

from the date of notice. Any cost of Re-Study 

shall be borne by the Interconnection 

Customer being re-studied. 

Section 9. Engineering & Procurement (‘E&P’) 

Agreement 

Prior to executing an LGIA, an 

Interconnection Customer may, in order to 

advance the implementation of its 

interconnection, request and Transmission 

Provider shall offer the Interconnection 

Customer, an E&P Agreement that authorizes 

Transmission Provider to begin engineering 

and procurement of long lead-time items 

necessary for the establishment of the 

interconnection. However, Transmission 

Provider shall not be obligated to offer an 

E&P Agreement if Interconnection Customer 

is in Dispute Resolution as a result of an 

allegation that Interconnection Customer has 

failed to meet any milestones or comply with 

any prerequisites specified in other parts of 

the LGIP. The E&P Agreement is an optional 

procedure and it will not alter the 

Interconnection Customer’s Queue Position 

or In-Service Date. The E&P Agreement shall 

provide for Interconnection Customer to pay 

the cost of all activities authorized by 

Interconnection Customer and to make 

advance payments or provide other 

satisfactory security for such costs. 

Interconnection Customer shall pay the 

cost of such authorized activities and any 

cancellation costs for equipment that is 

already ordered for its interconnection, 

which cannot be mitigated as hereafter 

described, whether or not such items or 

equipment later become unnecessary. If 

Interconnection Customer withdraws its 

application for interconnection or either 

Party terminates the E&P Agreement, to the 

extent the equipment ordered can be 

canceled under reasonable terms, 

Interconnection Customer shall be obligated 

to pay the associated cancellation costs. To 

the extent that the equipment cannot be 

reasonably canceled, Transmission Provider 

may elect: (i) To take title to the equipment, 

in which event Transmission Provider shall 

refund Interconnection Customer any 

amounts paid by Interconnection Customer 

for such equipment and shall pay the cost of 

delivery of such equipment, or (ii) to transfer 

title to and deliver such equipment to 

Interconnection Customer, in which event 

Interconnection Customer shall pay any 

unpaid balance and cost of delivery of such 

equipment. 

Section 10. Optional Interconnection Study 

10.1 Optional Interconnection Study 

Agreement 

On or after the date when Interconnection 

Customer receives Interconnection System 

Impact Study results, Interconnection 

Customer may request, and Transmission 

Provider shall perform a reasonable number 

of Optional Studies. The request shall 

describe the assumptions that 

Interconnection Customer wishes 

Transmission Provider to study within the 

scope described in Section 10.2. Within five 

(5) Business Days after receipt of a request for 

an Optional Interconnection Study, 

Transmission Provider shall provide to 

Interconnection Customer an Optional 

Interconnection Study Agreement in the form 

of Appendix 5. 

The Optional Interconnection Study 

Agreement shall: (i) Specify the technical 

data that Interconnection Customer must 

provide for each phase of the Optional 

Interconnection Study, (ii) specify 

Interconnection Customer’s assumptions as 

to which Interconnection Requests with 

earlier queue priority dates will be excluded 

from the Optional Interconnection Study case 

and assumptions as to the type of 

interconnection service for Interconnection 

Requests remaining in the Optional 

Interconnection Study case, and (iii) 

Transmission Provider’s estimate of the cost 

of the Optional Interconnection Study. To the 

extent known by Transmission Provider, 

such estimate shall include any costs 

expected to be incurred by any Affected 

System whose participation is necessary to 

complete the Optional Interconnection 

Study. Notwithstanding the above, 

Transmission Provider shall not be required 

as a result of an Optional Interconnection 

Study request to conduct any additional 

Interconnection Studies with respect to any 

other Interconnection Request. 

Interconnection Customer shall execute the 

Optional Interconnection Study Agreement 

within ten (10) Business Days of receipt and 

deliver the Optional Interconnection Study 

Agreement, the technical data and a $10,000 

deposit to Transmission Provider. 

10.2 Scope of Optional Interconnection 

Study 

The Optional Interconnection Study will 

consist of a sensitivity analysis based on the 

assumptions specified by Interconnection 

Customer in the Optional Interconnection 

Study Agreement. The Optional 

Interconnection Study will also identify 

Transmission Provider’s Interconnection 

Facilities and the Network Upgrades, and the 

estimated cost thereof, that may be required 

to provide transmission service or 

Interconnection Service based upon the 

results of the Optional Interconnection 

Study. The Optional Interconnection Study 

shall be performed solely for informational 

purposes. Transmission Provider shall use 

Reasonable Efforts to coordinate the study 

with any Affected Systems that may be 

affected by the types of Interconnection 

Services that are being studied. Transmission 

Provider shall utilize existing studies to the 

extent practicable in conducting the Optional 

Interconnection Study. 

10.3 Optional Interconnection Study 

Procedures 

The executed Optional Interconnection 

Study Agreement, the prepayment, and 

technical and other data called for therein 

must be provided to Transmission Provider 

within ten (10) Business Days of 

Interconnection Customer receipt of the 

Optional Interconnection Study Agreement. 

Transmission Provider shall use Reasonable 

Efforts to complete the Optional 

Interconnection Study within a mutually 

agreed upon time period specified within the 

Optional Interconnection Study Agreement. 

If Transmission Provider is unable to 

complete the Optional Interconnection Study 

within such time period, it shall notify 

Interconnection Customer and provide an 

estimated completion date and an 

explanation of the reasons why additional 

time is required. Any difference between the 

study payment and the actual cost of the 

study shall be paid to Transmission Provider 

or refunded to Interconnection Customer, as 

appropriate. Upon request, Transmission 

Provider shall provide Interconnection 

Customer supporting documentation and 

workpapers and databases or data developed 

in the preparation of the Optional 

Interconnection Study, subject to 

confidentiality arrangements consistent with 

Section 13.1. 

Section 11. Standard Large Generator 

Interconnection Agreement (LGIA) 

11.1 Tender 

Interconnection Customer shall tender 

comments on the draft Interconnection 

Facilities Study Report within thirty (30) 

Calendar Days of receipt of the report. Within 

thirty (30) Calendar Days after the comments 

are submitted, Transmission Provider shall 

tender a draft LGIA, together with draft 

appendices. The draft LGIA shall be in the 


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form of Transmission Provider’s FERCapproved standard form LGIA, which is in 

Appendix 6. Interconnection Customer shall 

execute and return the completed draft 

appendices within thirty (30) Calendar Days. 

11.2 Negotiation 

Notwithstanding Section 11.1, at the 

request of Interconnection Customer 

Transmission Provider shall begin 

negotiations with Interconnection Customer 

concerning the appendices to the LGIA at any 

time after Interconnection Customer executes 

the Interconnection Facilities Study 

Agreement. Transmission Provider and 

Interconnection Customer shall negotiate 

concerning any disputed provisions of the 

appendices to the draft LGIA for not more 

than sixty (60) Calendar Days after tender of 

the final Interconnection Facilities Study 

Report. If Interconnection Customer 

determines that negotiations are at an 

impasse, it may request termination of the 

negotiations at any time after tender of the 

draft LGIA pursuant to Section 11.1 and 

request submission of the unexecuted LGIA 

with FERC or initiate Dispute Resolution 

procedures pursuant to Section 13.5. If 

Interconnection Customer requests 

termination of the negotiations, but within 

sixty (60) Calendar Days thereafter fails to 

request either the filing of the unexecuted 

LGIA or initiate Dispute Resolution, it shall 

be deemed to have withdrawn its 

Interconnection Request. Unless otherwise 

agreed by the Parties, if Interconnection 

Customer has not executed the LGIA, 

requested filing of an unexecuted LGIA, or 

initiated Dispute Resolution procedures 

pursuant to Section 13.5 within sixty (60) 

Calendar Days of tender of draft LGIA, it 

shall be deemed to have withdrawn its 

Interconnection Request. Transmission 

Provider shall provide to Interconnection 

Customer a final LGIA within fifteen (15) 

Business Days after the completion of the 

negotiation process. 

11.3 Execution and Filing 

Within fifteen (15) Business Days after 

receipt of the final LGIA, Interconnection 

Customer shall provide Transmission 

Provider (A) reasonable evidence that 

continued Site Control or (B) posting of 

$250,000, non-refundable additional security, 

which shall be applied toward future 

construction costs. At the same time, 

Interconnection Customer also shall provide 

reasonable evidence that one or more of the 

following milestones in the development of 

the Large Generating Facility, at 

Interconnection Customer election, has been 

achieved: (i) The execution of a contract for 

the supply or transportation of fuel to the 

Large Generating Facility; (ii) the execution 

of a contract for the supply of cooling water 

to the Large Generating Facility; (iii) 

execution of a contract for the engineering 

for, procurement of major equipment for, or 

construction of, the Large Generating 

Facility; (iv) execution of a contract for the 

sale of electric energy or capacity from the 

Large Generating Facility; or (v) application 

for an air, water, or land use permit. 

Interconnection Customer shall either: (i) 

Execute two originals of the tendered LGIA 

and return them to Transmission Provider; or 

(ii) request in writing that Transmission 

Provider file with FERC an LGIA in 

unexecuted form. As soon as practicable, but 

not later than ten (10) Business Days after 

receiving either the two executed originals of 

the tendered LGIA (if it does not conform 

with a FERC-approved standard form of 

interconnection agreement) or the request to 

file an unexecuted LGIA, Transmission 

Provider shall file the LGIA with FERC, 

together with its explanation of any matters 

as to which Interconnection Customer and 

Transmission Provider disagree and support 

for the costs that Transmission Provider 

proposes to charge to Interconnection 

Customer under the LGIA. An unexecuted 

LGIA should contain terms and conditions 

deemed appropriate by Transmission 

Provider for the Interconnection Request. If 

the Parties agree to proceed with design, 

procurement, and construction of facilities 

and upgrades under the agreed-upon terms of 

the unexecuted LGIA, they may proceed 

pending FERC action. 

11.4 Commencement of Interconnection 

Activities 

If Interconnection Customer executes the 

final LGIA, Transmission Provider and 

Interconnection Customer shall perform their 

respective obligations in accordance with the 

terms of the LGIA, subject to modification by 

FERC. Upon submission of an unexecuted 

LGIA, Interconnection Customer and 

Transmission Provider shall promptly 

comply with the unexecuted LGIA, subject to 

modification by FERC. 

Section 12. Construction of Transmission 

Provider’s Interconnection Facilities and 

Network Upgrades 

12.1 Schedule 

Transmission Provider and Interconnection 

Customer shall negotiate in good faith 

concerning a schedule for the construction of 

Transmission Provider’s Interconnection 

Facilities and the Network Upgrades. 

12.2 Construction Sequencing 

12.2.1 General 

In general, the In-Service Date of an 

Interconnection Customers seeking 

interconnection to the Transmission System 

will determine the sequence of construction 

of Network Upgrades. 

12.2.2 Advance Construction of Network 

Upgrades That Are an Obligation of an Entity 

Other Than Interconnection Customer 

An Interconnection Customer with an 

LGIA, in order to maintain its In-Service 

Date, may request that Transmission Provider 

advance to the extent necessary the 

completion of Network Upgrades that: (i) 

Were assumed in the Interconnection Studies 

for such Interconnection Customer, (ii) are 

necessary to support such In-Service Date, 

and (iii) would otherwise not be completed, 

pursuant to a contractual obligation of an 

entity other than Interconnection Customer 

that is seeking interconnection to the 

Transmission System, in time to support 

such In-Service Date. Upon such request, 

Transmission Provider will use Reasonable 

Efforts to advance the construction of such 

Network Upgrades to accommodate such 

request; provided that Interconnection 

Customer commits to pay Transmission 

Provider: (i) Any associated expediting costs 

and (ii) the cost of such Network Upgrades. 

Transmission Provider will refund to 

Interconnection Customer both the 

expediting costs and the cost of Network 

Upgrades, in accordance with Article 11.4 of 

the LGIA. Consequently, the entity with a 

contractual obligation to construct such 

Network Upgrades shall be obligated to pay 

only that portion of the costs of the Network 

Upgrades that Transmission Provider has not 

refunded to Interconnection Customer. 

Payment by that entity shall be due on the 

date that it would have been due had there 

been no request for advance construction. 

Transmission Provider shall forward to 

Interconnection Customer the amount paid 

by the entity with a contractual obligation to 

construct the Network Upgrades as payment 

in full for the outstanding balance owed to 

Interconnection Customer. Transmission 

Provider then shall refund to that entity the 

amount that it paid for the Network 

Upgrades, in accordance with Article 11.4 of 

the LGIA. 

12.2.3 Advancing Construction of Network 

Upgrades That Are Part of an Expansion Plan 

of the Transmission Provider 

An Interconnection Customer with an 

LGIA, in order to maintain its In-Service 

Date, may request that Transmission Provider 

advance to the extent necessary the 

completion of Network Upgrades that: (i) Are 

necessary to support such In-Service Date 

and (ii) would otherwise not be completed, 

pursuant to an expansion plan of 

Transmission Provider, in time to support 

such In-Service Date. Upon such request, 

Transmission Provider will use Reasonable 

Efforts to advance the construction of such 

Network Upgrades to accommodate such 

request; provided that Interconnection 

Customer commits to pay Transmission 

Provider any associated expediting costs. 

Interconnection Customer shall be entitled to 

transmission credits, if any, for any 

expediting costs paid. 

12.2.4 Amended Interconnection System 

Impact Study 

An Interconnection System Impact Study 

will be amended to determine the facilities 

necessary to support the requested In-Service 

Date. This amended study will include those 

transmission and Large Generating Facilities 

that are expected to be in service on or before 

the requested In-Service Date. 

Section 13. Miscellaneous 

13.1 Confidentiality 

Confidential Information shall include, 

without limitation, all information relating to 

a Party’s technology, research and 

development, business affairs, and pricing, 

and any information supplied by either of the 

Parties to the other prior to the execution of 

an LGIA. 

Information is Confidential Information 

only if it is clearly designated or marked in 

writing as confidential on the face of the 

document, or, if the information is conveyed 

orally or by inspection, if the Party providing 


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the information orally informs the Party 

receiving the information that the 

information is confidential. 

If requested by either Party, the other Party 

shall provide in writing, the basis for 

asserting that the information referred to in 

this Article warrants confidential treatment, 

and the requesting Party may disclose such 

writing to the appropriate Governmental 

Authority. Each Party shall be responsible for 

the costs associated with affording 

confidential treatment to its information. 

13.1.1 Scope 

Confidential Information shall not include 

information that the receiving Party can 

demonstrate: (1) Is generally available to the 

public other than as a result of a disclosure 

by the receiving Party; (2) was in the lawful 

possession of the receiving Party on a nonconfidential basis before receiving it from the 

disclosing Party; (3) was supplied to the 

receiving Party without restriction by a third 

party, who, to the knowledge of the receiving 

Party after due inquiry, was under no 

obligation to the disclosing Party to keep 

such information confidential; (4) was 

independently developed by the receiving 

Party without reference to Confidential 

Information of the disclosing Party; (5) is, or 

becomes, publicly known, through no 

wrongful act or omission of the receiving 

Party or Breach of the LGIA; or (6) is 

required, in accordance with Section 13.1.6, 

Order of Disclosure, to be disclosed by any 

Governmental Authority or is otherwise 

required to be disclosed by law or subpoena, 

or is necessary in any legal proceeding 

establishing rights and obligations under the 

LGIA. Information designated as Confidential 

Information will no longer be deemed 

confidential if the Party that designated the 

information as confidential notifies the other 

Party that it no longer is confidential. 

13.1.2 Release of Confidential Information 

Neither Party shall release or disclose 

Confidential Information to any other person, 

except to its Affiliates (limited by the 

Standards of Conduct requirements), 

employees, consultants, or to parties who 

may be or considering providing financing to 

or equity participation with Interconnection 

Customer, or to potential purchasers or 

assignees of Interconnection Customer, on a 

need-to-know basis in connection with these 

procedures, unless such person has first been 

advised of the confidentiality provisions of 

this Section 13.1 and has agreed to comply 

with such provisions. Notwithstanding the 

foregoing, a Party providing Confidential 

Information to any person shall remain 

primarily responsible for any release of 

Confidential Information in contravention of 

this Section 13.1. 

13.1.3 Rights 

Each Party retains all rights, title, and 

interest in the Confidential Information that 

each Party discloses to the other Party. The 

disclosure by each Party to the other Party of 

Confidential Information shall not be deemed 

a waiver by either Party or any other person 

or entity of the right to protect the 

Confidential Information from public 

disclosure. 

13.1.4 No Warranties 

By providing Confidential Information, 

neither Party makes any warranties or 

representations as to its accuracy or 

completeness. In addition, by supplying 

Confidential Information, neither Party 

obligates itself to provide any particular 

information or Confidential Information to 

the other Party nor to enter into any further 

agreements or proceed with any other 

relationship or joint venture. 

13.1.5 Standard of Care 

Each Party shall use at least the same 

standard of care to protect Confidential 

Information it receives as it uses to protect 

its own Confidential Information from 

unauthorized disclosure, publication or 

dissemination. Each Party may use 

Confidential Information solely to fulfill its 

obligations to the other Party under these 

procedures or its regulatory requirements. 

13.1.6 Order of Disclosure 

If a court or a Government Authority or 

entity with the right, power, and apparent 

authority to do so requests or requires either 

Party, by subpoena, oral deposition, 

interrogatories, requests for production of 

documents, administrative order, or 

otherwise, to disclose Confidential 

Information, that Party shall provide the 

other Party with prompt notice of such 

request(s) or requirement(s) so that the other 

Party may seek an appropriate protective 

order or waive compliance with the terms of 

the LGIA. Notwithstanding the absence of a 

protective order or waiver, the Party may 

disclose such Confidential Information 

which, in the opinion of its counsel, the 

Party is legally compelled to disclose. Each 

Party will use Reasonable Efforts to obtain 

reliable assurance that confidential treatment 

will be accorded any Confidential 

Information so furnished. 

13.1.7 Remedies 

The Parties agree that monetary damages 

would be inadequate to compensate a Party 

for the other Party’s Breach of its obligations 

under this Section 13.1. Each Party 

accordingly agrees that the other Party shall 

be entitled to equitable relief, by way of 

injunction or otherwise, if the first Party 

Breaches or threatens to Breach its 

obligations under this Section 13.1, which 

equitable relief shall be granted without bond 

or proof of damages, and the receiving Party 

shall not plead in defense that there would 

be an adequate remedy at law. Such remedy 

shall not be deemed an exclusive remedy for 

the Breach of this Section 13.1, but shall be 

in addition to all other remedies available at 

law or in equity. The Parties further 

acknowledge and agree that the covenants 

contained herein are necessary for the 

protection of legitimate business interests 

and are reasonable in scope. No Party, 

however, shall be liable for indirect, 

incidental, or consequential or punitive 

damages of any nature or kind resulting from 

or arising in connection with this Section 

13.1. 

13.1.8 Disclosure to FERC, Its Staff, or a 

State 

Notwithstanding anything in this Section 

13.1 to the contrary, and pursuant to 18 CFR 

1b.20, if FERC or its staff, during the course 

of an investigation or otherwise, requests 

information from one of the Parties that is 

otherwise required to be maintained in 

confidence pursuant to the LGIP, the Party 

shall provide the requested information to 

FERC or its staff, within the time provided 

for in the request for information. In 

providing the information to FERC or its 

staff, the Party must, consistent with 18 CFR 

388.112, request that the information be 

treated as confidential and non-public by 

FERC and its staff and that the information 

be withheld from public disclosure. Parties 

are prohibited from notifying the other Party 

prior to the release of the Confidential 

Information to FERC or its staff. The Party 

shall notify the other Party to the LGIA when 

it is notified by FERC or its staff that a 

request to release Confidential Information 

has been received by FERC, at which time 

either of the Parties may respond before such 

information would be made public, pursuant 

to 18 CFR 388.112. Requests from a state 

regulatory body conducting a confidential 

investigation shall be treated in a similar 

manner, consistent with applicable state 

rules and regulations. 

13.1.9 

Subject to the exception in Section 13.1.8, 

any information that a Party claims is 

competitively sensitive, commercial or 

financial information (‘‘Confidential 

Information’’) shall not be disclosed by the 

other Party to any person not employed or 

retained by the other Party, except to the 

extent disclosure is (i) required by law; (ii) 

reasonably deemed by the disclosing Party to 

be required to be disclosed in connection 

with a dispute between or among the Parties, 

or the defense of litigation or dispute; (iii) 

otherwise permitted by consent of the other 

Party, such consent not to be unreasonably 

withheld; or (iv) necessary to fulfill its 

obligations under this LGIP or as a 

transmission service provider or a Control 

Area operator including disclosing the 

Confidential Information to an RTO or ISO or 

to a subregional, regional or national 

reliability organization or planning group. 

The Party asserting confidentiality shall 

notify the other Party in writing of the 

information it claims is confidential. Prior to 

any disclosures of the other Party’s 

Confidential Information under this 

subparagraph, or if any third party or 

Governmental Authority makes any request 

or demand for any of the information 

described in this subparagraph, the 

disclosing Party agrees to promptly notify the 

other Party in writing and agrees to assert 

confidentiality and cooperate with the other 

Party in seeking to protect the Confidential 

Information from public disclosure by 

confidentiality agreement, protective order or 

other reasonable measures. 

13.1.10 

This provision shall not apply to any 

information that was or is hereafter in the 

public domain (except as a result of a Breach 

of this provision). 

13.1.11 

Transmission Provider shall, at 

Interconnection Customer’s election, destroy, 


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in a confidential manner, or return the 

Confidential Information provided at the 

time of Confidential Information is no longer 

needed. 

13.2 Delegation of Responsibility 

Transmission Provider may use the 

services of subcontractors as it deems 

appropriate to perform its obligations under 

this LGIP. Transmission Provider shall 

remain primarily liable to Interconnection 

Customer for the performance of such 

subcontractors and compliance with its 

obligations of this LGIP. The subcontractor 

shall keep all information provided 

confidential and shall use such information 

solely for the performance of such obligation 

for which it was provided and no other 

purpose. 

13.3 Obligation for Study Costs 

Transmission Provider shall charge and 

Interconnection Customer shall pay the 

actual costs of the Interconnection Studies. 

Any difference between the study deposit 

and the actual cost of the applicable 

Interconnection Study shall be paid by or 

refunded, except as otherwise provided 

herein, to Interconnection Customer or offset 

against the cost of any future Interconnection 

Studies associated with the applicable 

Interconnection Request prior to beginning of 

any such future Interconnection Studies. Any 

invoices for Interconnection Studies shall 

include a detailed and itemized accounting 

of the cost of each Interconnection Study. 

Interconnection Customer shall pay any such 

undisputed costs within thirty (30) Calendar 

Days of receipt of an invoice therefor. 

Transmission Provider shall not be obligated 

to perform or continue to perform any studies 

unless Interconnection Customer has paid all 

undisputed amounts in compliance herewith. 

13.4 Third Parties Conducting Studies 

If (i) at the time of the signing of an 

Interconnection Study Agreement there is 

disagreement as to the estimated time to 

complete an Interconnection Study, (ii) 

Interconnection Customer receives notice 

pursuant to Sections 6.3, 7.4 or 8.3 that 

Transmission Provider will not complete an 

Interconnection Study within the applicable 

timeframe for such Interconnection Study, or 

(iii) Interconnection Customer receives 

neither the Interconnection Study nor a 

notice under Sections 6.3, 7.4 or 8.3 within 

the applicable timeframe for such 

Interconnection Study, then Interconnection 

Customer may require Transmission Provider 

to utilize a third party consultant reasonably 

acceptable to Interconnection Customer and 

Transmission Provider to perform such 

Interconnection Study under the direction of 

Transmission Provider. At other times, 

Transmission Provider may also utilize a 

third party consultant to perform such 

Interconnection Study, either in response to 

a general request of Interconnection 

Customer, or on its own volition. 

In all cases, use of a third party consultant 

shall be in accord with Article 26 of the LGIA 

(Subcontractors) and limited to situations 

where Transmission Provider determines that 

doing so will help maintain or accelerate the 

study process for Interconnection Customer’s 

pending Interconnection Request and not 

interfere with Transmission Provider’s 

progress on Interconnection Studies for other 

pending Interconnection Requests. In cases 

where Interconnection Customer requests use 

of a third party consultant to perform such 

Interconnection Study, Interconnection 

Customer and Transmission Provider shall 

negotiate all of the pertinent terms and 

conditions, including reimbursement 

arrangements and the estimated study 

completion date and study review deadline. 

Transmission Provider shall convey all 

workpapers, data bases, study results and all 

other supporting documentation prepared to 

date with respect to the Interconnection 

Request as soon as soon as practicable upon 

Interconnection Customer’s request subject to 

the confidentiality provision in Section 13.1. 

In any case, such third party contract may be 

entered into with either Interconnection 

Customer or Transmission Provider at 

Transmission Provider’s discretion. In the 

case of (iii) Interconnection Customer 

maintains its right to submit a claim to 

Dispute Resolution to recover the costs of 

such third party study. Such third party 

consultant shall be required to comply with 

this LGIP, Article 26 of the LGIA 

(Subcontractors), and the relevant Tariff 

procedures and protocols as would apply if 

Transmission Provider were to conduct the 

Interconnection Study and shall use the 

information provided to it solely for purposes 

of performing such services and for no other 

purposes. Transmission Provider shall 

cooperate with such third party consultant 

and Interconnection Customer to complete 

and issue the Interconnection Study in the 

shortest reasonable time. 

13.5 Disputes 

13.5.1 Submission 

In the event either Party has a dispute, or 

asserts a claim, that arises out of or in 

connection with the LGIA, the LGIP, or their 

performance, such Party (the ‘‘disputing 

Party’’) shall provide the other Party with 

written notice of the dispute or claim 

(‘‘Notice of Dispute’’). Such dispute or claim 

shall be referred to a designated senior 

representative of each Party for resolution on 

an informal basis as promptly as practicable 

after receipt of the Notice of Dispute by the 

other Party. In the event the designated 

representatives are unable to resolve the 

claim or dispute through unassisted or 

assisted negotiations within thirty (30) 

Calendar Days of the other Party’s receipt of 

the Notice of Dispute, such claim or dispute 

may, upon mutual agreement of the Parties, 

be submitted to arbitration and resolved in 

accordance with the arbitration procedures 

set forth below. In the event the Parties do 

not agree to submit such claim or dispute to 

arbitration, each Party may exercise whatever 

rights and remedies it may have in equity or 

at law consistent with the terms of this LGIA. 

13.5.2 External Arbitration Procedures 

Any arbitration initiated under these 

procedures shall be conducted before a single 

neutral arbitrator appointed by the Parties. If 

the Parties fail to agree upon a single 

arbitrator within ten (10) Calendar Days of 

the submission of the dispute to arbitration, 

each Party shall choose one arbitrator who 

shall sit on a three-member arbitration panel. 

The two arbitrators so chosen shall within 

twenty (20) Calendar Days select a third 

arbitrator to chair the arbitration panel. In 

either case, the arbitrators shall be 

knowledgeable in electric utility matters, 

including electric transmission and bulk 

power issues, and shall not have any current 

or past substantial business or financial 

relationships with any party to the arbitration 

(except prior arbitration). The arbitrator(s) 

shall provide each of the Parties an 

opportunity to be heard and, except as 

otherwise provided herein, shall conduct the 

arbitration in accordance with the 

Commercial Arbitration Rules of the 

American Arbitration Association 

(‘‘Arbitration Rules’’) and any applicable 

FERC regulations or RTO rules; provided, 

however, in the event of a conflict between 

the Arbitration Rules and the terms of this 

Section 13, the terms of this Section 13 shall 

prevail. 

13.5.3 Arbitration Decisions 

Unless otherwise agreed by the Parties, the 

arbitrator(s) shall render a decision within 

ninety (90) Calendar Days of appointment 

and shall notify the Parties in writing of such 

decision and the reasons therefor. The 

arbitrator(s) shall be authorized only to 

interpret and apply the provisions of the 

LGIA and LGIP and shall have no power to 

modify or change any provision of the LGIA 

and LGIP in any manner. The decision of the 

arbitrator(s) shall be final and binding upon 

the Parties, and judgment on the award may 

be entered in any court having jurisdiction. 

The decision of the arbitrator(s) may be 

appealed solely on the grounds that the 

conduct of the arbitrator(s), or the decision 

itself, violated the standards set forth in the 

Federal Arbitration Act or the Administrative 

Dispute Resolution Act. The final decision of 

the arbitrator must also be filed with FERC 

if it affects jurisdictional rates, terms and 

conditions of service, Interconnection 

Facilities, or Network Upgrades. 

13.5.4 Costs 

Each Party shall be responsible for its own 

costs incurred during the arbitration process 

and for the following costs, if applicable: (1) 

The cost of the arbitrator chosen by the Party 

to sit on the three member panel and one half 

of the cost of the third arbitrator chosen; or 

(2) one half the cost of the single arbitrator 

jointly chosen by the Parties. 

13.5.5 Non-Binding Dispute Resolution 

Procedures 

If a Party has submitted a Notice of Dispute 

pursuant to section 13.5.1, and the Parties are 

unable to resolve the claim or dispute 

through unassisted or assisted negotiations 

within the thirty (30) Calendar Days provided 

in that section, and the Parties cannot reach 

mutual agreement to pursue the section 13.5 

arbitration process, a Party may request that 

Transmission Provider engage in Nonbinding Dispute Resolution pursuant to this 

section by providing written notice to 

Transmission Provider (‘‘Request for Nonbinding Dispute Resolution’’). Conversely, 

either Party may file a Request for Nonbinding Dispute Resolution pursuant to this 

section without first seeking mutual 


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agreement to pursue the section 13.5 

arbitration process. The process in section 

13.5.5 shall serve as an alternative to, and not 

a replacement of, the section 13.5 arbitration 

process. Pursuant to this process, a 

Transmission Provider must within 30 days 

of receipt of the Request for Non-binding 

Dispute Resolution appoint a neutral 

decision-maker that is an independent 

subcontractor that shall not have any current 

or past substantial business or financial 

relationships with either Party. Unless 

otherwise agreed by the Parties, the decisionmaker shall render a decision within sixty 

(60) Calendar Days of appointment and shall 

notify the Parties in writing of such decision 

and reasons therefore. This decision-maker 

shall be authorized only to interpret and 

apply the provisions of the LGIP and LGIA 

and shall have no power to modify or change 

any provision of the LGIP and LGIA in any 

manner. The result reached in this process is 

not binding, but, unless otherwise agreed, the 

Parties may cite the record and decision in 

the non-binding dispute resolution process in 

future dispute resolution processes, 

including in a section 13.5 arbitration, or in 

a Federal Power Act section 206 complaint. 

Each Party shall be responsible for its own 

costs incurred during the process and the 

cost of the decision-maker shall be divided 

equally among each Party to the dispute. 

13.6 Local Furnishing Bonds 

13.6.1 Transmission Providers That Own 

Facilities Financed by Local Furnishing 

Bonds 

This provision is applicable only to a 

Transmission Provider that has financed 

facilities for the local furnishing of electric 

energy with tax-exempt bonds, as described 

in Section 142(f) of the Internal Revenue 

Code (‘‘local furnishing bonds’’). 

Notwithstanding any other provision of this 

LGIA and LGIP, Transmission Provider shall 

not be required to provide Interconnection 

Service to Interconnection Customer 

pursuant to this LGIA and LGIP if the 

provision of such Transmission Service 

would jeopardize the tax-exempt status of 

any local furnishing bond(s) used to finance 

Transmission Provider’s facilities that would 

be used in providing such Interconnection 

Service. 

13.6.2 Alternative Procedures for 

Requesting Interconnection Service 

If Transmission Provider determines that 

the provision of Interconnection Service 

requested by Interconnection Customer 

would jeopardize the tax-exempt status of 

any local furnishing bond(s) used to finance 

its facilities that would be used in providing 

such Interconnection Service, it shall advise 

the Interconnection Customer within thirty 

(30) Calendar Days of receipt of the 

Interconnection Request. 

Interconnection Customer thereafter may 

renew its request for interconnection using 

the process specified in Article 5.2(ii) of the 

Transmission Provider’s Tariff. 

Appendix 1 to LGIP—Interconnection 

Request for a Large Generating Facility 

1. The undersigned Interconnection 

Customer submits this request to 

interconnect its Large Generating Facility 

with Transmission Provider’s Transmission 

System pursuant to a Tariff. 

2. This Interconnection Request is for 

(check one): 

ll A proposed new Large Generating 

Facility. 

ll An increase in the generating capacity 

or a Material Modification of an existing 

Generating Facility. 

3. The type of interconnection service 

requested (check one): 

ll Energy Resource Interconnection 

Service 

ll Network Resource Interconnection 

Service 

4. ll Check here only if Interconnection 

Customer requesting Network Resource 

Interconnection Service also seeks to have its 

Generating Facility studied for Energy 

Resource Interconnection Service 

5. Interconnection Customer provides the 

following information: 

a. Address or location or the proposed new 

Large Generating Facility site (to the extent 

known) or, in the case of an existing 

Generating Facility, the name and specific 

location of the existing Generating Facility; 

b. Maximum summer at ll degrees C and 

winter at ll degrees C megawatt electrical 

output of the proposed new Large Generating 

Facility or the amount of megawatt increase 

in the generating capacity of an existing 

Generating Facility; 

c. General description of the equipment 

configuration; 

d. Commercial Operation Date (Day, 

Month, and Year); 

e. Name, address, telephone number, and 

email address of Interconnection Customer’s 

contact person; 

f. Approximate location of the proposed 

Point of Interconnection (optional); 

g. Interconnection Customer Data (set forth 

in Attachment A) and 

h. Primary frequency response operating 

range for electric storage resources. 

i. Requested capacity (in MW) of 

Interconnection Service (if lower than the 

Generating Facility Capacity). 

6. Applicable deposit amount as specified 

in the LGIP. 

7. Evidence of Site Control as specified in 

the LGIP (check one) 

ll Is attached to this Interconnection 

Request 

ll Will be provided at a later date in 

accordance with this LGIP 

8. This Interconnection Request shall be 

submitted to the representative indicated 

below: [To be completed by Transmission 

Provider] 

9. Representative of Interconnection 

Customer to contact: [To be completed by 

Interconnection Customer] 

10. This Interconnection Request is 

submitted by: 

Name of Interconnection Customer: 

lllllllllllllllllllll

By (signature): llllllllllllll

Name (type or print): lllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

Attachment A to Appendix 1 

Interconnection Request 

Large Generating Facility Data Unit Ratings 

kVA lll °F lll Voltage lll 

Power Factor lll 

Speed (RPM) lll Connection (e.g., 

Wye) lll 

Short Circuit Ratio lll Frequency, 

Hertz lll 

Stator Amperes at Rated kVA lll Field 

Volts lll 

Max Turbine MW lll °F lll 

Primary frequency response operating 

range for electric storage resources: 

Minimum State of Charge: lll lllll

Maximum State of Charge: lll lllll

Combined Turbine-Generator-Exciter Inertia 

Data 

Inertia Constant, H = lll kW sec/kVA 

Moment-of-Inertia, WR2 = lll lb. ft.2

Reactance Data (Per Unit-Rated KVA) 

Direct axis Quadrature 

axis 

Synchronous—saturated .................................................................................................................................................... Xdv lll Xqv lll 

Synchronous—unsaturated ................................................................................................................................................ Xdi lll Xqi lll 

Transient—saturated .......................................................................................................................................................... X′dv lll X′qv lll 

Transient—unsaturated ...................................................................................................................................................... X′di lll X′qi lll 

Subtransient—saturated .................................................................................................................................................... X′′dv lll X′′qv lll 

Subtransient—unsaturated ................................................................................................................................................ X′′di lll X′′qi lll 

Negative Sequence—saturated ......................................................................................................................................... X2v lll 

Negative Sequence—unsaturated ..................................................................................................................................... X2i lll 

Zero Sequence—saturated ................................................................................................................................................ X0v lll 

Zero Sequence—unsaturated ............................................................................................................................................ X0i lll 

Leakage Reactance ........................................................................................................................................................... Xlm lll 


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Field Time Constant Data (SEC) 

Open Circuit ...................................................................................................................................................... T′do lll T′qo lll 

Three-Phase Short Circuit Transient ............................................................................................................... T′d3 lll T′q lll 

Line to Line Short Circuit Transient ............................................................................................................... T′d2 lll 

Line to Neutral Short Circuit Transient .......................................................................................................... T′d1 lll 

Short Circuit Subtransient ................................................................................................................................ T′′d lll T′′q lll 

Open Circuit Subtransient ................................................................................................................................ T′′do lll T′′qo lll 

Armature Time Constant Data (SEC) 

Three Phase Short Circuit—Ta3 lll 

Line to Line Short Circuit—Ta2 lll 

Line to Neutral Short Circuit—Ta1 lll 

Note: If requested information is not 

applicable, indicate by marking ‘‘N/A.’’ 

MW Capability and Plant Configuration 

Large Generating Facility Data 

Armature Winding Resistance Data (Per Unit) 

Positive—R1 lll 

Negative—R2 lll 

Zero—R0 lll 

Rotor Short Time Thermal Capacity I2

2t = 

lll 

Field Current at Rated kVA, Armature 

Voltage and PF = lll amps 

Field Current at Rated kVA and Armature 

Voltage, 0 PF = lll amps 

Three Phase Armature Winding 

Capacitance = lll microfarad 

Field Winding Resistance = lll ohms 

lll °C 

Armature Winding Resistance (Per Phase) 

= lll ohms lll °C 

Curves 

Provide Saturation, Vee, Reactive 

Capability, Capacity Temperature Correction 

curves. Designate normal and emergency 

Hydrogen Pressure operating range for 

multiple curves. 

Generator Step-Up Transformer Data 

Ratings 

Capacity; Self-cooled/Maximum Nameplate 

lll/lll kVA 

Voltage Ratio (Generator Side/System side/ 

Tertiary) 

lll/lll/lll kV 

Winding Connections (Low V/High V/ 

Tertiary V (Delta or Wye)) 

lll/lll/lll 

Fixed Taps Available lll lllllll

Present Tap Setting lll llllllll

Impedance 

Positive; Z1 (on self-cooled kVA rating) 

lll % lll X/R 

Zero; Z0 (on self-cooled kVA rating) lll 

% lll X/R 

Excitation System Data 

Identify appropriate IEEE model block 

diagram of excitation system and power 

system stabilizer (PSS) for computer 

representation in power system stability 

simulations and the corresponding excitation 

system and PSS constants for use in the 

model. 

Governor System Data 

Identify appropriate IEEE model block 

diagram of governor system for computer 

representation in power system stability 

simulations and the corresponding governor 

system constants for use in the model. 

Wind Generators 

Number of generators to be interconnected 

pursuant to this Interconnection Request: 

llllll 

Elevation: lllll llllllllll

llllll 

Single Phase llllllllllllll

llllll Three Phase 

Inverter manufacturer, model name, 

number, and version: 

llllll llllllllllllll

List of adjustable setpoints for the 

protective equipment or software: 

llllll llllllllllllll

Note: A completed General Electric 

Company Power Systems Load Flow (PSLF) 

data sheet or other compatible formats, such 

as IEEE and PTI power flow models, must be 

supplied with the Interconnection Request. If 

other data sheets are more appropriate to the 

proposed device, then they shall be provided 

and discussed at Scoping Meeting. 

Induction Generators 

(*) Field Volts: lllllllllllll

(*) Field Amperes: llllllllllll

(*) Motoring Power (kW): lllllllll

(*) Neutral Grounding Resistor (If Applicable): llllllllllllllllll

(*) I2

2t or K (Heating Time Constant): lll

(*) Rotor Resistance: lllllllllll

(*) Stator Resistance: lllllllllll

(*) Stator Reactance: lllllllllll

(*) Rotor Reactance: lllllllllll

(*) Magnetizing Reactance: llllllll

(*) Short Circuit Reactance: llllllll

(*) Exciting Current: lllllllllll

(*) Temperature Rise: llllllllll

(*) Frame Size: lllllllllllll

(*) Design Letter: llllllllllll

(*) Reactive Power Required In Vars (No 

Load): lllllllllllllllll

(*) Reactive Power Required In Vars (Full 

Load): lllllllllllllllll

(*) Total Rotating Inertia, H: llllll Per 

Unit on KVA Base llllllllllll

Note: Please consult Transmission Provider 

prior to submitting the Interconnection 

Request to determine if the information 

designated by (*) is required. 

Appendix 2 to LGIP—Interconnection 

Feasibility Study Agreement 

This agreement is made and entered into 

this ll day of llllll, 20 ll by and 

between llllll, a llllll 

organized and existing under the laws of the 

State of llllll, (‘‘Interconnection 

Customer,’’) and llllll a llllll 

existing under the laws of the State of 

llllll, (‘‘Transmission Provider ’’). 

Interconnection Customer and Transmission 

Provider each may be referred to as a ‘‘Party,’’ 

or collectively as the ‘‘Parties.’’ 

Recitals 

Whereas, Interconnection Customer is 

proposing to develop a Large Generating 

Facility or generating capacity addition to an 

existing Generating Facility consistent with 

the Interconnection Request submitted by 

Interconnection Customer dated 

llllll; and 

Whereas, Interconnection Customer desires 

to interconnect the Large Generating Facility 

with the Transmission System; and 

Whereas, Interconnection Customer has 

requested Transmission Provider to perform 

an Interconnection Feasibility Study to assess 

the feasibility of interconnecting the 

proposed Large Generating Facility to the 

Transmission System, and of any Affected 

Systems; 

Now, therefore, in consideration of and 

subject to the mutual covenants contained 

herein the Parties agreed as follows: 

1.0 When used in this Agreement, with 

initial capitalization, the terms specified 

shall have the meanings indicated in 

Transmission Provider’s FERC-approved 

LGIP. 

2.0 Interconnection Customer elects and 

Transmission Provider shall cause to be 

performed an Interconnection Feasibility 

Study consistent with Section 6.0 of this 

LGIP in accordance with the Tariff. 

3.0 The scope of the Interconnection 

Feasibility Study shall be subject to the 

assumptions set forth in Attachment A to this 

Agreement. 

4.0 The Interconnection Feasibility Study 

shall be based on the technical information 

provided by Interconnection Customer in the 

Interconnection Request, as may be modified 

as the result of the Scoping Meeting. 

Transmission Provider reserves the right to 

request additional technical information from 

Interconnection Customer as may reasonably 

become necessary consistent with Good 

Utility Practice during the course of the 

Interconnection Feasibility Study and as 

designated in accordance with Section 3.4.4 

of the LGIP. If, after the designation of the 

Point of Interconnection pursuant to Section 

3.4.4 of the LGIP, Interconnection Customer 

modifies its Interconnection Request 

pursuant to Section 4.4, the time to complete 

the Interconnection Feasibility Study may be 

extended. 

5.0 The Interconnection Feasibility Study 

report shall provide the following 

information: 


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Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 26603 

—Preliminary identification of any circuit 

breaker short circuit capability limits 

exceeded as a result of the interconnection; 

—preliminary identification of any thermal 

overload or voltage limit violations 

resulting from the interconnection; and 

—preliminary description and non-bonding 

estimated cost of facilities required to 

interconnect the Large Generating Facility 

to the Transmission System and to address 

the identified short circuit and power flow 

issues. 

6.0 Interconnection Customer shall 

provide a deposit of $10,000 for the 

performance of the Interconnection 

Feasibility Study. 

Upon receipt of the Interconnection 

Feasibility Study Transmission Provider 

shall charge and Interconnection Customer 

shall pay the actual costs of the 

Interconnection Feasibility Study. 

Any difference between the deposit and 

the actual cost of the study shall be paid by 

or refunded to Interconnection Customer, as 

appropriate. 

7.0 Miscellaneous. The Interconnection 

Feasibility Study Agreement shall include 

standard miscellaneous terms including, but 

not limited to, indemnities, representations, 

disclaimers, warranties, governing law, 

amendment, execution, waiver, 

enforceability and assignment, that reflect 

best practices in the electric industry, and 

that are consistent with regional practices, 

Applicable Laws and Regulations, and the 

organizational nature of each Party. All of 

these provisions, to the extent practicable, 

shall be consistent with the provisions of the 

LGIP and the LGIA. 

In witness whereof, the Parties have caused 

this Agreement to be duly executed by their 

duly authorized officers or agents on the day 

and year first above written. 

[Insert name of Transmission Provider or 

Transmission Owner, if applicable] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

[Insert name of Interconnection Customer] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

Attachment A to Appendix 2— 

Interconnection Feasibility Study 

Agreement 

Assumptions Used in Conducting the 

Interconnection Feasibility Study 

The Interconnection Feasibility Study will 

be based upon the information set forth in 

the Interconnection Request and agreed upon 

in the Scoping Meeting held on llllll: 

Designation of Point of Interconnection 

and configuration to be studied. 

Designation of alternative Point(s) of 

Interconnection and configuration. 

[Above assumptions to be completed by 

Interconnection Customer and other 

assumptions to be provided by 

Interconnection Customer and Transmission 

Provider] 

Appendix 3 to LGIP—Interconnection 

System Impact Study Agreement 

This Agreement is made and entered into 

this ll day of llllll, 20ll by and 

between llllll, a llllll 

organized and existing under the laws of the 

State of llllll, (‘‘Interconnection 

Customer,’’) and llllll a llllll 

existing under the laws of the State of 

llllll, (‘‘Transmission Provider ’’). 

Interconnection Customer and Transmission 

Provider each may be referred to as a ‘‘Party,’’ 

or collectively as the ‘‘Parties.’’ 

Recitals 

Whereas, Interconnection Customer is 

proposing to develop a Large Generating 

Facility or generating capacity addition to an 

existing Generating Facility consistent with 

the Interconnection Request submitted by 

Interconnection Customer dated 

llllll; and 

Whereas, Interconnection Customer desires 

to interconnect the Large Generating Facility 

with the Transmission System; 

Whereas, Transmission Provider has 

completed an Interconnection Feasibility 

Study (the ‘‘Feasibility Study’’) and provided 

the results of said study to Interconnection 

Customer (This recital to be omitted if 

Transmission Provider does not require the 

Interconnection Feasibility Study.); and 

Whereas, Interconnection Customer has 

requested Transmission Provider to perform 

an Interconnection System Impact Study to 

assess the impact of interconnecting the 

Large Generating Facility to the Transmission 

System, and of any Affected Systems; 

Now, therefore, in consideration of and 

subject to the mutual covenants contained 

herein the Parties agreed as follows: 

1.0 When used in this Agreement, with 

initial capitalization, the terms specified 

shall have the meanings indicated in 

Transmission Provider’s FERC-approved 

LGIP. 

2.0 Interconnection Customer elects and 

Transmission Provider shall cause to be 

performed an Interconnection System Impact 

Study consistent with Section 7.0 of this 

LGIP in accordance with the Tariff. 

3.0 The scope of the Interconnection 

System Impact Study shall be subject to the 

assumptions set forth in Attachment A to this 

Agreement. 

4.0 The Interconnection System Impact 

Study will be based upon the results of the 

Interconnection Feasibility Study and the 

technical information provided by 

Interconnection Customer in the 

Interconnection Request, subject to any 

modifications in accordance with Section 4.4 

of the LGIP. Transmission Provider reserves 

the right to request additional technical 

information from Interconnection Customer 

as may reasonably become necessary 

consistent with Good Utility Practice during 

the course of the Interconnection Customer 

System Impact Study. If Interconnection 

Customer modifies its designated Point of 

Interconnection, Interconnection Request, or 

the technical information provided therein is 

modified, the time to complete the 

Interconnection System Impact Study may be 

extended. 

5.0 The Interconnection System Impact 

Study report shall provide the following 

information: 

—identification of any circuit breaker short 

circuit capability limits exceeded as a 

result of the interconnection; 

—identification of any thermal overload or 

voltage limit violations resulting from the 

interconnection; 

—identification of any instability or 

inadequately damped response to system 

disturbances resulting from the 

interconnection and 

—description and non-binding, good faith 

estimated cost of facilities required to 

interconnect the Large Generating Facility to 

the Transmission System and to address the 

identified short circuit, instability, and 

power flow issues. 

6.0 Interconnection Customer shall 

provide a deposit of $50,000 for the 

performance of the Interconnection System 

Impact Study. Transmission Provider’s good 

faith estimate for the time of completion of 

the Interconnection System Impact Study is 

[insert date]. 

Upon receipt of the Interconnection 

System Impact Study, Transmission Provider 

shall charge and Interconnection Customer 

shall pay the actual costs of the 

Interconnection System Impact Study. 

Any difference between the deposit and 

the actual cost of the study shall be paid by 

or refunded to Interconnection Customer, as 

appropriate. 

7.0 Miscellaneous. The Interconnection 

System Impact Study Agreement shall 

include standard miscellaneous terms 

including, but not limited to, indemnities, 

representations, disclaimers, warranties, 

governing law, amendment, execution, 

waiver, enforceability and assignment, that 

reflect best practices in the electric industry, 

that are consistent with regional practices, 

Applicable Laws and Regulations and the 

organizational nature of each Party. All of 

these provisions, to the extent practicable, 

shall be consistent with the provisions of the 

LGIP and the LGIA.] 

In witness thereof, the Parties have caused 

this Agreement to be duly executed by their 

duly authorized officers or agents on the day 

and year first above written. 

[Insert name of Transmission Provider or 

Transmission Owner, if applicable] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

[Insert name of Interconnection Customer] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

Attachment A To Appendix 3— 

Interconnection System Impact Study 

Agreement 

Assumptions Used in Conducting the 

Interconnection System Impact Study 

The Interconnection System Impact Study 

will be based upon the results of the 

Interconnection Feasibility Study, subject to 

any modifications in accordance with 


khammond on DSKJM1Z7X2PROD with PROPOSALS4
26604 Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 

Section 4.4 of the LGIP, and the following 

assumptions: 

Designation of Point of Interconnection 

and configuration to be studied. 

Designation of alternative Point(s) of 

Interconnection and configuration. 

[Above assumptions to be completed by 

Interconnection Customer and other 

assumptions to be provided by 

Interconnection Customer and Transmission 

Provider] 

Appendix 4 to LGIP—Interconnection 

Facilities Study Agreement 

THIS AGREEMENT is made and entered 

into this day ll of llllll, 20ll by 

and between llllll, a llllll 

organized and existing under the laws of the 

State of llllll, (‘‘Interconnection 

Customer,’’) and llllll a llllll 

existing under the laws of the State of 

llllll, (‘‘Transmission Provider ’’). 

Interconnection Customer and Transmission 

Provider each may be referred to as a ‘‘Party,’’ 

or collectively as the ‘‘Parties.’’ 

Recitals 

Whereas, Interconnection Customer is 

proposing to develop a Large Generating 

Facility or generating capacity addition to an 

existing Generating Facility consistent with 

the Interconnection Request submitted by 

Interconnection Customer dated 

llllll; and 

Whereas, Interconnection Customer desires 

to interconnect the Large Generating Facility 

with the Transmission System; 

Whereas, Transmission Provider has 

completed an Interconnection System Impact 

Study (the ‘‘System Impact Study’’) and 

provided the results of said study to 

Interconnection Customer; and 

Whereas, Interconnection Customer has 

requested Transmission Provider to perform 

an Interconnection Facilities Study to specify 

and estimate the cost of the equipment, 

engineering, procurement and construction 

work needed to implement the conclusions 

of the Interconnection System Impact Study 

in accordance with Good Utility Practice to 

physically and electrically connect the Large 

Generating Facility to the Transmission 

System. 

Now, therefore, in consideration of and 

subject to the mutual covenants contained 

herein the Parties agreed as follows: 

1.0 When used in this Agreement, with 

initial capitalization, the terms specified 

shall have the meanings indicated in 

Transmission Provider’s FERC-approved 

LGIP. 

2.0 Interconnection Customer elects and 

Transmission Provider shall cause an 

Interconnection Facilities Study consistent 

with Section 8.0 of this LGIP to be performed 

in accordance with the Tariff. 

3.0 The scope of the Interconnection 

Facilities Study shall be subject to the 

assumptions set forth in Attachment A and 

the data provided in Attachment B to this 

Agreement. 

4.0 The Interconnection Facilities Study 

report (i) shall provide a description, 

estimated cost of (consistent with 

Attachment A), schedule for required 

facilities to interconnect the Large Generating 

Facility to the Transmission System and (ii) 

shall address the short circuit, instability, 

and power flow issues identified in the 

Interconnection System Impact Study. 

5.0 Interconnection Customer shall 

provide a deposit of $100,000 for the 

performance of the Interconnection Facilities 

Study. The time for completion of the 

Interconnection Facilities Study is specified 

in Attachment A. 

Transmission Provider shall invoice 

Interconnection Customer on a monthly basis 

for the work to be conducted on the 

Interconnection Facilities Study each month. 

Interconnection Customer shall pay invoiced 

amounts within thirty (30) Calendar Days of 

receipt of invoice. Transmission Provider 

shall continue to hold the amounts on 

deposit until settlement of the final invoice. 

6.0 Miscellaneous. The Interconnection 

Facility Study Agreement shall include 

standard miscellaneous terms including, but 

not limited to, indemnities, representations, 

disclaimers, warranties, governing law, 

amendment, execution, waiver, 

enforceability and assignment, that reflect 

best practices in the electric industry, and 

that are consistent with regional practices, 

Applicable Laws and Regulations, and the 

organizational nature of each Party. All of 

these provisions, to the extent practicable, 

shall be consistent with the provisions of the 

LGIP and the LGIA. 

In witness whereof, the Parties have caused 

this Agreement to be duly executed by their 

duly authorized officers or agents on the day 

and year first above written. 

[Insert name of Transmission Provider or 

Transmission Owner, if applicable] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

[Insert name of Interconnection Customer] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

Attachment A To Appendix 4— 

Interconnection Facilities Study 

Agreement 

Interconnection Customer Schedule Election 

for Conducting the Interconnection Facilities 

Study 

Transmission Provider shall use 

Reasonable Efforts to complete the study and 

issue a draft Interconnection Facilities Study 

report to Interconnection Customer within 

the following number of days after of receipt 

of an executed copy of this Interconnection 

Facilities Study Agreement: 

—Ninety (90) Calendar Days with no more 

than a ±20 percent cost estimate contained 

in the report, or 

—one hundred eighty (180) Calendar Days 

with no more than a ±10 percent cost 

estimate contained in the report. 

Attachment B to Appendix 4— 

Interconnection Facilities Study 

Agreement 

Data Form To Be Provided by 

Interconnection Customer With the 

Interconnection Facilities Study Agreement 

Provide location plan and simplified oneline diagram of the plant and station 

facilities. For staged projects, please indicate 

future generation, transmission circuits, etc. 

One set of metering is required for each 

generation connection to the new ring bus or 

existing Transmission Provider station. 

Number of generation connections: 

On the one line diagram indicate the 

generation capacity attached at each metering 

location. (Maximum load on CT/PT) 

On the one line diagram indicate the 

location of auxiliary power. (Minimum load 

on CT/PT) Amps 

Will an alternate source of auxiliary power 

be available during CT/PT maintenance? 

llYes llNo 

Will a transfer bus on the generation side 

of the metering require that each meter set be 

designed for the total plant generation? 

llYes llNo (Please indicate on one line 

diagram). 

What type of control system or PLC will be 

located at Interconnection Customer’s Large 

Generating Facility? 

lllllllllllllllllllll

What protocol does the control system or 

PLC use? 

lllllllllllllllllllll

Please provide a 7.5-minute quadrangle of 

the site. Sketch the plant, station, 

transmission line, and property line. 

Physical dimensions of the proposed 

interconnection station: 

lllllllllllllllllllll

Bus length from generation to 

interconnection station: 

lllllllllllllllllllll

Line length from interconnection station to 

Transmission Provider’s transmission line. 

lllllllllllllllllllll

Tower number observed in the field. 

(Painted on tower leg) * 

lllllllllllllllllllll

Number of third party easements required 

for transmission lines *: 

lllllllllllllllllllll

* To be completed in coordination with 

Transmission Provider. 

Is the Large Generating Facility in the 

Transmission Provider’s service area? 

llYes llNo 

Local provider: 

lllllllllllllllllllll

Please provide proposed schedule dates: 

Begin Construction: 

Date: llllllllllllllllll

Generator step-up transformer receives back 

feed power 

Generation Testing llllllllllll

Date: llllllllllllllllll

Commercial Operation 

Date: llllllllllllllllll


khammond on DSKJM1Z7X2PROD with PROPOSALS4
Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 26605 

1See, e.g., New England Power Pool Participants 

Committee October 12, 2021 Comments at 4–8 

(detailing past and current transmission planning 

activities). 

2Building for the Future Through Elec. Reg’l 

Transmission Planning & Cost Allocation & 

Generator Interconnection, 179 FERC ¶ 61,028 

(2022) (‘‘NOPR’’); see also Building for the Future 

Through Elec. Reg’l Transmission Planning & Cost 

Allocation & Generator Interconnection, 176 FERC 

¶ 61,024 (2021) (‘‘ANOPR’’). 

3The NOPR uses the phrase ‘‘driven by changes 

in the resource mix and demand’’ 116 times. These 

are code words for ‘‘renewables.’’ See NOPR, 179 

FERC ¶ 61,028 at P 45 (detailing ‘‘[t]hese changes 

in the resource mix and demand,’’ almost all of 

which involve the transition to renewable 

resources). 

4See id. PP 37–41, 48–49. Nearly every other 

preliminary finding related to current transmission 

planning is tied to ‘‘changes in the resource mix 

and demand.’’ 

5See Certification of New Interstate Nat. Gas 

Facilities, 178 FERC ¶ 61,107, order dismissing 

reh’g requests, Certification of New Interstate Nat. 

Continued 

Appendix 5 to LGIP—Optional 

Interconnection Study Agreement 

This Agreement is made and entered into 

this ll day of llllll, 20ll by and 

between llllll, a llllll 

organized and existing under the laws of the 

State of llllll, (‘‘Interconnection 

Customer,’’) and llllll a llllll 

existing under the laws of the State of 

llllll, (‘‘Transmission Provider ’’). 

Interconnection Customer and Transmission 

Provider each may be referred to as a ‘‘Party,’’ 

or collectively as the ‘‘Parties.’’ 

Recitals 

Whereas, Interconnection Customer is 

proposing to develop a Large Generating 

Facility or generating capacity addition to an 

existing Generating Facility consistent with 

the Interconnection Request submitted by 

Interconnection Customer dated 

llllll; 

Whereas, Interconnection Customer is 

proposing to establish an interconnection 

with the Transmission System; and 

Whereas, Interconnection Customer has 

submitted to Transmission Provider an 

Interconnection Request; and 

Whereas, on or after the date when 

Interconnection Customer receives the 

Interconnection System Impact Study results, 

Interconnection Customer has further 

requested that Transmission Provider prepare 

an Optional Interconnection Study; 

Now, therefore, in consideration of and 

subject to the mutual covenants contained 

herein the Parties agree as follows: 

1.0 When used in this Agreement, with 

initial capitalization, the terms specified 

shall have the meanings indicated in 

Transmission Provider’s FERC-approved 

LGIP. 

2.0 Interconnection Customer elects and 

Transmission Provider shall cause an 

Optional Interconnection Study consistent 

with Section 10.0 of this LGIP to be 

performed in accordance with the Tariff. 

3.0 The scope of the Optional 

Interconnection Study shall be subject to the 

assumptions set forth in Attachment A to this 

Agreement. 

4.0 The Optional Interconnection Study 

shall be performed solely for informational 

purposes. 

5.0 The Optional Interconnection Study 

report shall provide a sensitivity analysis 

based on the assumptions specified by 

Interconnection Customer in Attachment A 

to this Agreement. The Optional 

Interconnection Study will identify 

Transmission Provider’s Interconnection 

Facilities and the Network Upgrades, and the 

estimated cost thereof, that may be required 

to provide transmission service or 

interconnection service based upon the 

assumptions specified by Interconnection 

Customer in Attachment A. 

6.0 Interconnection Customer shall 

provide a deposit of $10,000 for the 

performance of the Optional Interconnection 

Study. Transmission Provider’s good faith 

estimate for the time of completion of the 

Optional Interconnection Study is [insert 

date]. 

Upon receipt of the Optional 

Interconnection Study, Transmission 

Provider shall charge and Interconnection 

Customer shall pay the actual costs of the 

Optional Study. 

Any difference between the initial payment 

and the actual cost of the study shall be paid 

by or refunded to Interconnection Customer, 

as appropriate. 

7.0 Miscellaneous. The Optional 

Interconnection Study Agreement shall 

include standard miscellaneous terms 

including, but not limited to, indemnities, 

representations, disclaimers, warranties, 

governing law, amendment, execution, 

waiver, enforceability and assignment, that 

reflect best practices in the electric industry, 

and that are consistent with regional 

practices, Applicable Laws and Regulations, 

and the organizational nature of each Party. 

All of these provisions, to the extent 

practicable, shall be consistent with the 

provisions of the LGIP and the LGIA. 

In witness whereof, the Parties have caused 

this Agreement to be duly executed by their 

duly authorized officers or agents on the day 

and year first above written. 

[Insert name of Transmission Provider or 

Transmission Owner, if applicable] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

[Insert name of Interconnection Customer] 

By: lllllllllllllllllll

Title: llllllllllllllllll

Date: llllllllllllllllll

Appendix 6 to LGIP—Large Generator 

Interconnection Agreement (See LGIA) 

Appendix 7—Interconnection 

Procedures for a Wind Generating Plant 

Appendix 7 sets forth procedures specific 

to a wind generating plant. All other 

requirements of this LGIP continue to apply 

to wind generating plant interconnections. 

A. Special Procedures Applicable to Wind 

Generators 

The wind plant Interconnection Customer, 

in completing the Interconnection Request 

required by section 3.3 of this LGIP, may 

provide to the Transmission Provider a set of 

preliminary electrical design specifications 

depicting the wind plant as a single 

equivalent generator. Upon satisfying these 

and other applicable Interconnection Request 

conditions, the wind plant may enter the 

queue and receive the base case data as 

provided for in this LGIP. 

No later than six months after submitting 

an Interconnection Request completed in this 

manner, the wind plant Interconnection 

Customer must submit completed detailed 

electrical design specifications and other data 

(including collector system layout data) 

needed to allow the Transmission Provider to 

complete the System Impact Study. 

United States of America—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 April 21, 2022) 

DANLY, Commissioner, dissenting: 

1. I welcome long term transmission 

planning reform. I would prefer that Regional 

Transmission Organizations (RTOs) and 

other interested public utilities simply file 

their own proposals under section 205 of the 

Federal Power Act (FPA). They are fully 

capable of proposing rate changes and 

reforms on their own.1

2. This Notice of Proposed Rulemaking 

(NOPR) goes far beyond that. It contemplates 

a Federal Power Act section 206 finding that 

existing transmission planning across the 

nation—in every region, for every utility and 

market—is so unjust and unreasonable that it 

must be replaced with mandatory, pervasive, 

and invasive ‘‘reforms.’’ 2 But let us be clear. 

The NOPR’s primary purpose is to achieve 

narrow environmental policy objectives, not 

to address legitimate requirements under the 

Federal Power Act like ensuring just and 

reasonable rates or reliability. After all, as the 

NOPR itself repeatedly admits, it is ‘‘driven 

by changes in resource mix and demand,’’ 3

notwithstanding its references to genuine 

problems with existing transmission 

planning.4

3. The majority seeks to establish policies 

designed to encourage the massive 

transmission build-out that will doubtless be 

required to transition to an aspirational 

renewable future. To do so, they need to 

socialize the costs of this transmission across 

as broad a population of ratepayers as 

possible. Thus, they seek to use the FPA, a 

statute that sounds in rate regulation and 

reliability, as a tool to achieve a particular 

(and inapposite) policy goal. In this regard, 

it is much like the majority’s recent foray into 

transforming our pipeline certification 

process into a comprehensive environmental 

review.5 Accordingly, I must dissent. 


khammond on DSKJM1Z7X2PROD with PROPOSALS4
26606 Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 

Gas Facilities, 179 FERC ¶ 61,012 (2022); see also 

Certification of New Interstate Nat. Gas Facilities, 

178 FERC ¶ 61,197 (2022). 

6NOPR, 179 FERC ¶ 61,028 at PP 104, 106. 

7Arizona Public Service Company October 12, 

2021 Comments at 4. 

8NOPR, 179 FERC ¶ 61,028 at P 123. 

9 Id. P 124 (emphasis added). 

10 Id. P 274. 

11 Implementation of Dynamic Line Ratings, 178 

FERC ¶ 61,110 (2022). 

12NOPR, 179 FERC ¶ 61,028 at PP 91, 127–134. 

13 Id. P 131 & n.247 (citing National Renewable 

Energy Laboratory’s Renewable Energy Potential 

model and Distributed Generation Market Demand 

model). 

14 Id. P 255. 

15 Id. PP 7, 400–415. 

16 Id. PP 414–415. 

17 Id. P 310. 18See State Renewable Portfolio Standards & 

Goals, National Conference of State Legislatures 

(Aug. 13, 2021), https://www.ncsl.org/research/ 

energy/renewable-portfolio-standards.aspx. 19See id. 20Utah Public Service Commission October 8, 

2021 Comments at 2 (citing ANOPR, 176 FERC 

¶ 61,024 at P 40). 

21 Id. at 2–3. 

4. I normally would not oppose a NOPR. 

What is wrong with asking questions and 

seeking a record to consider reforms? But this 

NOPR is a boondoggle. It seeks to change 

virtually all aspects of transmission planning, 

including in non-RTO regions and it does so 

for the specific, though unstated, purpose of 

suborning the transmission planning process 

so it can be wielded as a tool to support the 

development of a specific set of favored 

generation resources. How does it do this? 

The NOPR proposes to require regions to 

factor in any state or even ‘‘local’’ (!) public 

policy (read, renewable) goals, no matter how 

far-fetched.6 If San Francisco, for example, 

passes an ordinance that all its energy must 

be solar no matter the cost, CAISO and 

perhaps all western regional planning now 

must take that into account in their 

transmission plans. And what if the local 

policy is unreasonable? Or what if a state has 

far more aggressive goals than another state? 

No matter: All must plan for the dreams of 

others. 

5. The Federal Power Act requires just and 

reasonable rates. That prohibits the 

Commission from charging ratepayers for 

unneeded transmission projects to 

accommodate someone else’s view of what 

types of generation might be preferable. And 

we are not talking about economic or 

reliability projects. The transmission at issue 

here is that required to accommodate state 

and local laws establishing the composition 

of their generation fleets. Choosing their own 

generation mix is undoubtedly their right, 

since such choices are unambiguously 

reserved to the states under the FPA, but the 

FPA does not require the Commission to 

accommodate these policies under either of 

its core statutory obligations: To ensure just 

and reasonable rates and to ensure reliability. 

In fact, it is quite the opposite, the NOPR 

risks further undue discrimination. 

Nevertheless, the NOPR starts from the 

premise that such projects must be 

considered in regional planning. 

6. Even if no transmission projects are ever 

selected under the new regional planning 

regime, the process imposed by the NOPR 

itself will substantially increase customer 

costs. As Arizona’s largest utility commented 

in the record, ‘‘[w]hile [Arizona Public 

Service Company] acknowledges the 

Commission’s desire to construct 

transmission for a quicker transition to a 

clean energy mix, unbound[ed] study work 

would lengthen timelines, thereby increasing 

the associated costs, for both the 

transmission planning process and the 

generator interconnection process.’’ 7

7. The NOPR not only is too expansive, it 

also is too specific. It proposes scores of 

detailed mandates. One such mandate, for 

example, is that four is the minimum number 

of planning scenarios a public utility must 

study, and that if one of the scenarios is a 

‘‘base case,’’ that one must be ‘‘most likely.’’ 8

‘‘[A]t least one of the four distinct’’ scenarios 

‘‘must account for uncertain operational 

outcomes . . . during high-impact, lowfrequency events’’ but we do ‘‘allow’’ utilities 

‘‘to determine which . . . high-impact, lowfrequency event should be modeled.’’ 9 Woe 

unto the utility that conducts long term 

planning by considering a fewer number of 

scenarios, but you do get to pick your favorite 

high-impact, low-frequency event. 

8. Entire sections of the NOPR read like a 

think tank’s wish list rather than a rigorous 

analysis of whether such Nice-to-Have ideas 

are required for just and reasonable, nondiscriminatory ratemaking. For some reason, 

the NOPR proposes that dynamic line ratings 

and advanced power flow control devices 

must be the default when studying any new 

transmission or generation solution ‘‘in all 

aspects of the regional transmission planning 

processes, including the existing regional 

transmission planning processes for nearterm regional transmission needs.’’ 10 Never 

mind that we already have a Notice of 

Inquiry on dynamic line ratings.11 And I 

thought this proceeding was about long-term 

planning? For some other reason, the NOPR 

has a section on ‘‘Specificity of Data 

Inputs’’ 12 which defines the ‘‘best available 

data’’ everyone in the industry must use in 

their planning, particularly endorsing ‘‘the 

most recent data on renewable energy 

potential and distributed energy resources 

developed by national labs.’’ 13 The NOPR 

also considers a mandate to establish a 

‘‘periodic forum’’ to study best practices and 

additional reforms.14 Why would this need to 

be mandated? Must the Commission control 

everything? Is no one in the industry capable 

of such foresight absent our intervention? 

And, by the way, the NOPR also proposes (in 

the name of ‘‘transparency’’) to require new 

levels of ‘‘enhancements’’ and oversight for 

local transmission planning, by requiring 

utilities to incorporate detailed tariff 

amendments to describe their local planning 

processes.15 It also obligates them to 

consider, among other things, requirements 

for how utilities should be ‘‘right-sizing’’ 

transmission facilities, and whether we 

should mandate information requirements on 

‘‘estimated in-kind replacements of . . . 

existing transmission.’’ 16 Does this not seem 

like overly prescriptive regulatory meddling? 

9. And yet—notwithstanding its bulk and 

granularity—the NOPR fails to clarify the 

single most critical question confronting 

individual states and consumers: Will 

unwilling states’ ratepayers be required to 

pay for their neighboring state’s new 

transmission project which is being built 

solely for the purpose of achieving that 

neighboring state’s (or locality’s) public 

policy goals? The NOPR leaves open what 

happens if states cannot voluntarily agree on 

such issues,17 but many will seek to have the 

RTO allocate costs as it sees fit, including to 

unwilling states. I oppose forcing the 

ratepayers in states with different public 

policy goals to pay for another state’s plans. 

10. According to a 2018 summary by the 

National Conference of State Legislatures, 24 

states either did not have any renewable 

portfolio standard or it had expired or was 

set to expire: Alabama, Alaska, Arkansas, 

Florida, Georgia, Idaho, Iowa (expired), 

Kansas (expired), Kentucky, Louisiana, 

Michigan (expired in 2021), Mississippi, 

Missouri (expired in 2021), Montana 

(expired), Nebraska, North Carolina (expired 

in 2021), North Dakota (expired), Oklahoma 

(expired), Pennsylvania (expired in 2021), 

South Dakota (expired), Tennessee, West 

Virginia, Wisconsin (expired), and 

Wyoming.18 Renewable standards in an 

additional 3 states were voluntary: Indiana, 

South Carolina, and Utah.19 That 27 states 

lack mandatory renewable portfolio 

standards rather suggests that the country is 

divided on this issue. 

11. Not surprisingly, states are among the 

primary opponents of the reforms 

contemplated in the ANOPR, many of which 

have survived through to the issuance of 

today’s NOPR. The Utah Public Service 

Commission correctly commented ‘‘that 

FERC seeks to reshape transmission planning 

and cost allocation for the purpose of 

expanding the transmission system ‘in areas 

with high degrees of renewable resources’ 

that require ‘extensive’ and ‘more expensive’ 

new transmission facilities.’’ 20 The Utah 

Public Service Commission explained that: 

[I]ncreased development and integration of 

renewable generation is a highly charged 

political question and a matter of significant 

political interest. Different states’ legislatures 

have made different policy choices. Some 

states, like California, have enacted very 

ambitious laws that require revolutionary 

changes to their generation mixes. As the 

[ANOPR] makes clear, these changes require 

significant investment in, among other 

things, new transmission infrastructure to 

wheel renewable generation. 

* * * * * 

The [Utah Public Service Commission] is 

deeply concerned the [ANOPR] advertises an 

interest in rewriting the rules governing 

transmission planning and cost allocation to 

better facilitate policy choices, not of 

Congress, but of particular state legislatures. 

More specifically, the [Utah Public Service 

Commission] is opposed to any rule change 

that would allow such preferences to impose 

costs on ratepayers in other states.21

12. Different policy goals are a critical 

reason for state opposition to a federal 

transmission planning regime, but certainly 

not the only one. The Louisiana Public 

Service Commission explained: 


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22Louisiana Public Service Commission October 

12, 2021 Comments at 2–3. 

23See, e.g., Joint Fed.-State Task Force on Elec. 

Transmission, 175 FERC ¶ 61,224 (2021) 

(establishing task force); see Joint Fed.-State Task 

Force on Elec. Transmission, FERC (last updated 

Apr. 4, 2022), https://www.ferc.gov/TFSOET. 

24Sponsors of the Southeastern Regional 

Transmission Planning Process October 12, 2021 

Comments at 2. 

25See id. at 11. 

26See id. at 12–14 (detailing renewable 

integration in the southeast on a state-by-state 

basis). 

27See, e.g., NOPR, 179 FERC ¶ 61,028 at P 3 (‘‘the 

reforms proposed in this NOPR would require 

public utility transmission providers’’ to amend 

their tariffs) (emphasis added). 

28New England Power Pool Participants 

Committee October 12, 2021 Comments at 8. 

29Chamber of Commerce of the United States of 

America October 12, 2021 Comments at 1. 

30Large Public Power Council October 12, 2021 

Comments at 5 (emphasis added). 

31New England Power Pool Participants 

Committee October 12, 2021 Comments at 7. 

the Commission proposes to change 

transmission planning and cost allocation to 

support a new fleet of renewable generating 

resources in preference to other types of 

generation. But it is not within the 

Commission’s FPA authority, or within the 

ambit of sound transmission planning, to 

dictate the choice of generating resources and 

then determine what planning and cost 

allocation metrics will lead to the appearance 

of an economic transmission build-out to 

support those resources. This approach 

interferes with the jurisdiction and authority 

of the states, fails to recognize regional 

differences, and could stifle innovation and 

the development of the most reliable and 

beneficial solutions at the least delivered 

energy and capacity cost. 

Many of the ANOPR’s proposals would not 

achieve just and reasonable rates, and, in 

fact, could lead in the opposite direction. 

They would dramatically increase costs 

imposed on consumers while potentially 

jeopardizing the reliability of the grid. 

Renewable resources are inherently 

intermittent and not dispatchable. They do 

not and will not have the same reliability 

benefits as thermal generation without 

significant technological investment and/or 

duplicative back-up power costs. Consumer 

costs should not increase without a 

corresponding benefit, and certainly not in 

the face of diminished reliability, one of the 

bedrock principles of electric rate 

regulation.22

13. I also attended the meetings of the joint 

federal-state task force on electric 

transmission in which numerous state 

commissioners voiced their concern that 

federal transmission planning regimes would 

be imposed upon the states, that the 

Commission would insist on uniformity 

throughout the country, and most 

importantly, that the Commission might 

require their state’s ratepayers to shoulder 

the costs of another state’s transmission 

projects.23 It should go without saying that 

the Commission would be wise to proceed 

with caution before acting in the face of state 

opposition. 

14. The NOPR raises another serious issue: 

I do not know how most of these proposals 

are supposed to work in non-RTO regions. 

Nor, apparently, does anyone else. This may 

explain the repeated entreaties for the 

Commission to allow regional variation in 

transmission planning. For example: 

the [Sponsors of the Southeastern Regional 

Transmission Planning Process (SERTP 

Sponsors)] are concerned that a one-size-fitsall adoption of some of the items 

contemplated in the ANOPR could prove 

counter-productive or unworkable in the 

SERTP’s expansive, twelve-state, non-RTO 

footprint. The SERTP Sponsors respectfully 

submit that the Commission’s rules 

concerning regional transmission planning 

should continue to accommodate varying 

approaches to transmission and system 

planning in recognition of the inherent 

variability of existing market structures, state 

policies and requirements, locally available 

resources, and customer needs that prevail 

throughout the country.24

15. It likewise is doubtful that many of the 

problems highlighted in the NOPR apply to 

the entire country or even extend beyond 

certain RTOs. In the southeast, at least, where 

there is no RTO, public utilities added 3,158 

miles of new transmission and 6,989 miles of 

uprates between 2015–2020, representing 

12% of all transmission in the region.25 This 

non-RTO region provided detailed record 

evidence that strongly suggests it is managing 

transmission expansion and renewable 

integration as well as or better than any 

RTO.26 Somehow this evidence evaded 

discussion in the NOPR and the Commission, 

regardless of the record evidence, seems 

intent on subjecting all public utilities, even 

those outside of the RTOs, to the same 

planning requirements.27

16. Even RTOs are calling for the 

Commission to recognize regional differences 

and not to impose uniform federal mandates. 

The New England Power Pool, for example, 

tells us in its ANOPR comments that ‘‘[t]he 

Commission should allow ISO–NE, NEPOOL, 

the [transmission owners in New England] 

and the New England States to continue to 

have the flexibility to develop solutions in 

planning, cost allocation and generator 

interconnection that work best for New 

England . . . .’’ 28

17. I recognize that there are at least some 

stakeholders, particularly in RTOs, that want 

guidance or direction from the Commission 

to address the current or potential lack of 

stakeholder consensus for transmission 

planning reforms. But replacing the 

stakeholder process with FERC-driven 

mandates only pleases the subset of 

stakeholders who agree with the mandates. It 

is another way to overrule voices in 

opposition. 

18. The numerous comments in response 

to the ANOPR requesting the continued 

recognition of regional differences 

underscore one of my primary concerns. I 

simply disagree that the record before us 

supports the scope and profundity of change 

the Commission seeks to impose. Other broad 

Commission rulemakings have had sufficient 

record support to satisfy our statutory 

obligations. Here, I am doubtful. I agree with 

the comments of the U.S. Chamber of 

Commerce which stated that: 

the Commission should seriously consider 

the gravity of this undertaking and its 

potential significant impacts on both the 

reliability and the cost of electricity for 

businesses and consumers across the 

country. Many of the policies and procedures 

subject to revaluation in this docket have 

served their intended purposes. They should 

not be abruptly jettisoned without a thorough 

evaluation of the costs and benefits resulting 

from any significant transmission planning 

and interconnection policy changes.29

19. In the same vein, the Large Public 

Power Council ‘‘asks the Commission to be 

careful not to disrupt planning and cost 

allocation principles within and outside 

ISOs/RTO structures that are currently 

working, and pursuant to which transmission 

is being planned and developed.’’ 30 Again, 

there is no mention of this argument or the 

supporting evidence in the NOPR. 

20. The NOPR solicits further comment, 

but it also plainly anticipates rule changes for 

which my own review of the record indicates 

only partial, or lukewarm, or minimal 

support. The most common comment I have 

seen in the record, and at the task force 

meetings, as I have already highlighted 

above, is some variation of ‘‘regional 

planning is a good idea, and reform is 

needed, but please do not tell us what to do.’’ 

Well, here are 450 pages of the Commission 

proposing to tell you what to do. 

21. I freely acknowledge that the NOPR 

includes several potentially reasonable ideas 

for reform. But that is not the test under 

section 206 of the FPA. We are not the Good 

Ideas Commission. We must have substantial 

record evidence that the existing rate is 

unjust and unreasonable. We must find that 

the current planning processes are so 

unacceptable that the existing system 

essentially must be scrapped. We must also 

have record evidence that the replacement 

rate—the final rule to follow the NOPR—is 

just and reasonable. We owe it to the 

jurisdictional entities and the ratepayers to 

assure ourselves that each of the prescriptive 

requirements we seek to impose are actually 

necessary to ensure a just and reasonable, 

non-discriminatory replacement rate. I 

certainly do not see the required evidentiary 

support in the record we have compiled to 

date and I am skeptical that I will ever see 

it. 

22. Every single party with an interest 

should file in this docket. And many parties 

will. The sheer scope of the NOPR means 

that there is likely to be at least some support 

in the record for just about anything. I must 

therefore underscore that it is critical for 

parties filing comments in response to the 

NOPR to be direct and clear. This can be as 

simple as styling comments as ‘‘Comments in 

Opposition’’ when the filing party opposes 

any significant part of the NOPR. For 

example, if you are one of the numerous 

parties that filed comments in the ANOPR 

proceeding requesting that ‘‘[i]n any final 

rule that comes out of this rulemaking 

proceeding the Commission should allow for 

regional variations and flexibility in 

compliance for RTO/ISO regions,’’ 31 or for 


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32See NOPR, 179 FERC ¶ 61,028 at PP 183, 355. 

33See, e.g., Sierra Club v. Costle, 657 F.2d 298, 

352 (D.C. Cir. 1981). 

34See Modernizing Wholesale Elec. Mkt. Design, 

179 FERC ¶ 61,029 at P 1 (2022). 

1 16 U.S.C. 824(b)(1). 

2 Id. § 824(a). 

3 Id. § 824(b)(1). 

4Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public 

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

154 (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 (DC Cir. 2014) (‘‘[T]he regional transmission 

planning process is not the vehicle by which 

integrated resource planning is conducted; that may 

be a separate obligation imposed on many public 

utility transmission providers and under the 

purview of the states.’’) (emphases added); see also 

id. PP 107, 156. 

5 16 U.S.C. 824e(a). 

6 Id. § 824o. 

non-RTO regions, then I strongly suggest that 

you file ‘‘Comments in Opposition’’ to the 

NOPR. The NOPR appears to anticipate only 

limited regional flexibility.32

23. I further specifically request itemized 

lists from each commenting party indicating 

whether it supports, opposes, or abstains as 

to each of the NOPR’s preliminary findings 

and proposed reforms. The Commission’s 

ultimate findings cannot rest merely on a 

tally of votes, but the scope of this 

proceeding would make such basic 

summaries of the comments immensely 

helpful and will aid the Commission in its 

review of the (already) voluminous record. 

24. To the extent possible, every part of a 

comment should directly respond to a 

particular preliminary finding or proposal in 

the NOPR. The ANOPR comments have been 

filed and reviewed. The time for generic 

comments, ‘‘principles’’ of planning, the 

voicing of general support and the like is 

over and such comments will be nearly 

without value in the face of page after page 

of detailed, specific preliminary findings and 

proposed requirements. Do you support the 

finding or not? Do you support the proposal 

or not? 

25. And in voicing your support or 

opposition, I also remind commenting parties 

to submit hard data whenever possible, 

including in affidavits, to help the 

Commission meet—or not—both of the 

required legal showings for this section 206 

proposal (that existing rates are unjust and 

unreasonable, and that the proposed 

replacement rate is just and reasonable). I am 

fully aware that parties have limited 

resources to comment on the Commission’s 

generic proceedings. And while the scope of 

this NOPR will inevitably make this an 

expensive and burdensome endeavor for 

commenters, I urge you not to rest solely on 

your ANOPR comments. Support or 

opposition to the specific proposals in the 

NOPR is necessary. It will be worth the effort. 

After all, the only thing at stake in this 

proceeding is nearly everything connected 

with transmission planning. 

26. Parties should remember that this is not 

the final rule. The Commission can issue a 

final rule that contains any provision based 

on substantial evidence and that is a ‘‘logical 

outgrowth’’ 33 of the provisions in today’s 

proposed rule. That gives wide berth for any 

number of ultimate outcomes. In other 

words, this rule, when finalized, could be 

substantially different. Given what is at stake, 

be certain to inform the Commission of your 

positions on every element of the NOPR that 

could possibly be of concern to you. 

27. In this regard, I strongly object to our 

75- and 30-day comment and reply periods. 

Commenting parties presumably do not have 

hundreds of hours to wade through 450 pages 

of detailed proposals and to marshal 

evidence and legal argument for or against 

every potential change. I am not sure how the 

same Commission that just set up an Office 

of Public Participation thinks anyone can 

reasonably comment on every detail in this 

tome in 6 months, let alone 75 days. In 

another proceeding today, we provide RTOs 

with 6 months to file reports on potential 

‘‘modernizing’’ reforms to electricity markets, 

yet here, where no less than the entirety of 

transmission planning is at stake, we 

suddenly are in a rush.34

28. Do not forget that we are also actively 

considering interconnection queue reforms, 

albeit separately, which might be an even 

greater priority. If we are going to propose 

comprehensive transmission planning 

changes in a rulemaking, regional planning 

and transmission interconnection queue 

reform should not be considered in silos. 

29. While I think this NOPR is a mistake, 

I am happy to be convinced that particular 

reforms are justified by sound legal argument 

and solid record evidence. Where reform is 

needed to ensure just and reasonable rates 

and reliable service, and the reform itself is 

just and reasonable, I can be persuaded that 

it is worthy of support. I nevertheless 

reiterate my strong preference that we allow 

public utilities to file their own transmission 

planning solutions under FPA section 205. 

The Commission does not need to issue rules 

to change everything. Sometimes it is better 

to build incrementally to improve the current 

system, rather than to scrap everything and 

start from scratch. In my view, if an RTO or 

public utility wants to ‘‘enhance’’ its regional 

planning, it can figure out how to do so. And 

if the Commission really believes that we 

cannot rely on public utilities to seek more 

efficient transmission planning of their own 

volition, my second option would be to issue 

section 206 orders requiring the RTOs to 

show cause why their existing transmission 

planning processes are just and reasonable. 

Whether you agree or disagree with these 

alternative procedural vehicles for change, 

please say so in your comments. 

30. I conclude with a note of caution. A 

transmission planning revolution opposed by 

half of the country risks becoming a 

transmission planning civil war. The 

Commission should not cram ‘‘reforms’’ 

down the throats of opponents on issues of 

such deep division, such as whether we can 

force utilities in unwilling states to consider 

the transmission needs of other states’ policy 

aspirations. The result will be protracted 

proceedings, litigation, and risk. Who is 

going to fund a transmission project in such 

an environment, in the face of the perpetual 

risk that it might have its costs ‘‘reallocated’’? 

For these reasons, I respectfully dissent. 

lllllllllllllllllllll

James P. Danly, 

lllllllllllllllllllll

Commissioner. 

United States of America 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 April 21, 2022) 

CHRISTIE, Commissioner, concurring: 

1. The broad purpose of this Commission’s 

oversight of transmission planning under the 

Federal Power Act (FPA) is to provide 

consumers with reliable power at just and 

reasonable rates. I am voting for this Notice 

of Proposed Rulemaking (NOPR) because I 

believe it contains some very good proposals 

that could protect consumers from paying 

unjust and unreasonable rates for 

transmission service while also supporting 

the delivery of reliable power to those 

consumers. I also believe it comports with 

our legal authority under the FPA. 

2. First, the legal framework: While the 

FPA gives this Commission authority over 

‘‘the transmission of electric energy in 

interstate commerce,’’ 1 the Commission has 

no authority to encroach on matters regulated 

by the states.2 The planning, approval and 

siting of the generation resources necessary 

to meet the needs of customers in a state are 

under the regulatory authority of the states, 

not the Commission.3 States can prefer, 

mandate or subsidize specific types of 

generation resources, but the Commission 

cannot use its authority over transmission to 

pressure, steer or require regional planning 

entities to act as the Commission’s agents and 

do indirectly what the Commission cannot 

do directly. The Commission is not a national 

integrated resource planner. Order No. 1000, 

to its credit, recognized this clear delineation 

between federal and state authority.4

3. Further, under the FPA our authority 

over transmission planning and cost 

allocation must ensure that wholesale 

transmission rates are not unjust and 

unreasonable.5 We also have the authority to 

promote the reliability of the bulk power 

grid.6 Those are consumer protection 

functions, not a license to promote the policy 

goals of any presidential administration or of 

any corporate or special-interest group that 

have not been enacted into law in the FPA 

or any other federal statute. 

4. With that legal framework in mind, I am 

voting in favor of issuing this NOPR at this 

time and in this form because, on the whole, 

I find the current draft is consistent with our 

authority under the FPA and contains some 

important and constructive proposals that 

will serve the consumer protection goals of 

just and reasonable rates and reliability. 

5. For example, and as described more 

fully below, this NOPR will formally put the 

states—for the first time—at the center of 

regional transmission planning and cost 

allocation decision-making for policy-driven 

projects in all regional transmission entities, 


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7States have long played an informal advisory 

and advocacy role through organizations such as 

the Organization of PJM States, Inc. (my alma 

mater) and the Organization of MISO States. In 

Southwest Power Pool, Inc. (SPP) and ISO New 

England Inc. states have played what could be 

perhaps described as a more formal role in the 

decision-making processes of the regional entity, 

through the SPP Regional State Committee and the 

New England States Committee on Electricity, 

respectively. In single-state RTOs/ISOs such as New 

York Independent System Operator, Inc. (NYISO) 

and California Independent System Operator 

Corporation, state policies and policy-makers 

already heavily influence transmission planning 

and cost allocation. See, e.g., N.Y. Indep. Sys. 

Operator, Inc., 178 FERC ¶ 61,179 (2022) (Christie, 

Comm’r, concurring) (‘‘The specific [transmission] 

projects at issue in this proceeding are designed to 

implement the public policies of the State of New 

York, which are ultimately the responsibility of 

New York’s elected legislators. . . . NYISO is a 

single-state ISO that is attempting to act in 

accordance with the public policies of the state.’’). 

The states, as sovereign entities, must choose to 

embrace the heightened role offered by this NOPR; 

no state can be compelled to do so, as the NOPR 

makes clear. Building for the Future Through 

Electric Regional Transmission Planning and Cost 

Allocation and Generator Interconnection, 179 

FERC ¶ 61,028, at P 308 (2022) (NOPR). 

8Building for the Future Through Electric 

Regional Transmission Planning and Cost 

Allocation and Generator Interconnection, 176 

FERC ¶ 61,024 (2021) (Christie, Comm’r, 

concurring, at P 5). 

9For example, I agree with Commissioner Danly’s 

dissent that many of the specific long-term planning 

directives proposed in the NOPR may be far too 

prescriptive and may need to be revised in any final 

rule to permit more regional variation and 

flexibility. 

10NOPR, 179 FERC ¶ 61,028 at PP 3, 89, 314. 

11 I recognize that, with regard to projects to 

relieve congestion costs, in some circumstances 

there may be cheaper solutions available through 

new builds of generation. 

12NOPR, 179 FERC ¶ 61,028 at P 4 & n.6; see also 

id. n.507. 

13Order No. 1000 described these types of 

projects as those that address ‘‘transmission needs 

driven by Public Policy Requirements.’’ 

14NOPR, 179 FERC ¶ 61,028 at PP 302–303, 305. 

15 Id. PP 305, 307. 

16See, e.g., id. PP 302, 312. 

17 Id. 

18 I am aware that states qua states do not join 

RTOs/ISOs. Rather, they use their regulatory power 

to allow or require their regulated transmissionowning utilities to join. 

19See, e.g., Google, A Policy Roadmap for 24/7 

Carbon-Free Energy (Apr. 14, 2022), https://

cloud.google.com/blog/topics/sustainability/apolicy-roadmap-for-achieving-247-carbon-freeenergy; see also BlackRock, Inc., 179 FERC ¶ 61,049 

(2022) (Christie, Comm’r, concurring). 

if the states choose.7 As another valuable 

example, also described below, the NOPR 

will shift the risk of financing policy-driven 

projects from consumers back to developers, 

where it should be. 

6. Let me also emphasize that this is a 

NOPR—the ‘‘P’’ stands for ‘‘Proposed’’—it is 

not a final rule. This is only another step in 

a long process. I look forward to reviewing 

the comments reacting to it, which I suspect 

will come in significant quantities. My vote 

on any final rule will, of course, be based on 

the text of that final rule. I will not support 

any final rule that exceeds our FPA authority 

and/or threatens to cause unjust and 

unreasonable rates to consumers. 

7. When we issued the ANOPR last 

summer,8 I said: 

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. 

Fortunately, this NOPR contains some very 

good proposals and leaves out the worst of 

the ‘‘not ready for prime time’’ ideas of the 

ANOPR. While it still contains some features 

I would not choose,9 on balance I am 

comfortable in voting for it in this form and 

putting it out for additional comment. Here 

are some of the best features of this NOPR: 

8. First, it leaves unchanged the planning 

criteria and cost allocation frameworks for 

Reliability and Economic projects.10

Reliability and Economic projects are the 

meat and potatoes of regional transmission 

planning. These categories of projects are, by 

definition, integral to the primary duty of 

utilities to serve retail customers (load). 

Reliability projects are essential to keep the 

lights on. Economic projects are constructed 

to reduce quantifiable and definable 

congestion costs. When these projects are 

needed, they should be expeditiously built.11

The NOPR wisely does not disturb existing 

criteria for timely planning, constructing and 

paying for these two categories of projects. 

9. Second, the NOPR proposes to create a 

separate category of projects, which we can 

label ‘‘Long-Term Regional Transmission 

Facilities,’’ 12 or ‘‘LTRT projects.’’ This new 

category replaces Order No. 1000’s ‘‘public 

policy projects.’’ 13 As with these public 

policy projects, the new category of LTRT 

projects are mostly driven, in whole or in 

part, directly or indirectly, by public policies, 

such as projects that would accommodate a 

state’s legislated preferences for certain 

resources, or projects that could 

accommodate generation growth and 

retirements resulting from states’ 

implementation of their own integrated 

resource plans (IRP), or corporate goals 

recognized in state utility regulation. 

10. For this new category of LTRT projects, 

the NOPR proposes to require a planning 

process extending out 20 years, based on the 

premise that a 20-year projection of the 

expected generation mix, costs of generation, 

and/or load has validity. Based on my 

experience as a state regulator with IRPs and 

computer models purporting to predict the 

future two or more decades down the road, 

I regard 20-year projections of this sort as, at 

best, occasionally interesting, but they 

certainly provide no basis whatsoever for 

saddling consumers with the costs of a 

billion-dollar transmission line. However, 

while this NOPR does propose to require a 

20-year planning process for LTRT projects, 

it does not propose to require that any 

individual LTRT project or group of projects 

must be approved for inclusion in any 

regional transmission expansion plan. 

Indeed, there are no mandated LTRT projects 

in this NOPR, nor any planning-cycle quotas 

that regional entities must meet for including 

these types of projects in regional plans. 

11. Even more importantly though, for 

these LTRT projects, the NOPR proposes to 

require the regional planning entities to 

consult with and seek the agreement of the 

relevant states to both the selection criteria 

for these projects and to the regional cost 

allocation arrangements. State approval is 

especially important in a multi-state region, 

where different states have different policies. 

The NOPR proposes to provide the maximum 

opportunity for creativity and flexibility to 

the states and regional entities in developing 

the process for designing and approving 

regional selection criteria and cost allocation 

arrangements. States can agree to an ex ante 

formula for regional cost allocation of these 

types of projects—such as, for example, the 

‘‘highway-byway’’ formula approved by the 

SPP Regional State Committee—or states can 

agree to a process for a project-by-project 

agreement on cost allocation among one or 

several states—such as, for example, the State 

Agreement Approach in PJM—or states may 

choose some combination of both.14 States in 

a multi-state RTO or ISO can even agree to 

defer the decision on cost allocation to the 

governing board of the RTO/ISO.15 The result 

is, while we are proposing to require regional 

planning entities to study and evaluate a 

broad, forward-looking array of 

information—including information 

addressing states’ individual energy policies 

and goals—any projects identified through 

this new process will not be built, or more 

importantly, paid for by consumers, until the 

states representing such consumers have 

agreed that such projects are indeed needed 

and wanted by those same consumers. 

12. And let me emphasize two points: 

First, as stated above, the Commission cannot 

impose a preference for certain types of 

generation nor require regional entities to 

plan transmission designed to prefer or 

facilitate one type of generation over another. 

Second, regardless of any ultimate cost 

allocation arrangement agreed to in a regional 

entity, no individual state’s consumers can 

be forced to bear the costs of another state’s 

policy-driven project or element of a project 

against its consent.16 That would be 

inconsistent with the cost-allocation 

principles of Order No. 1000, which this 

NOPR explicitly proposes to preserve.17

13. States did not join RTOs 18 to pay for 

other states’ public policies or to pay for the 

public policy goals of huge multinational 

corporations or asset managers.19 States 

joined to provide their retail consumers with 

the promised benefits of lower transmission 

costs and strengthened reliability through 

regional planning of core Reliability projects. 

Some may say that state regulators should 

have no more special right to consent to 

planning criteria and cost allocation for these 

projects than other stakeholders in the RTO/ 

ISO. But states are not just ‘‘stakeholders.’’ 

State regulators have the duty to act in the 

public interest and states alone are sovereign 

authorities with inherent police powers to 

regulate utilities through their designated 

state officers. The FPA itself explicitly 

recognizes state authority. So it is perfectly 

fitting for state regulators to have the 


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26610 Federal Register / Vol. 87, No. 86 / Wednesday, May 4, 2022 / Proposed Rules 

20NOPR, 179 FERC ¶ 61,028 at P 333 & n.530. 

21See e.g., Nat’l Wildlife Refuge Ass’n v. Rural 

Utils. Serv., Nos. 21–cv–096-wmc & 21–cv–306, 

2021 WL 5050073 (W.D. Wis. Nov. 1, 2021) 

(enjoining on environmental grounds construction 

of a segment of a transmission project intended to 

bring wind-generated power from generators in 

Iowa to Wisconsin); see also Clark Mindock, Wis. 

Judge Blocks $500M Power Line From Wildlife 

Refuge, LAW360 (Mar. 2, 2022), https://

www.law360.com/articles/1469697 (‘‘The CHC 

Project is a proposed 102-mile high-voltage 

transmission line in the Midwest that was proposed 

as a way of connecting parts of Milwaukee and 

Chicago to cheap wind power by connecting 

Dubuque, Iowa, to southwestern Wisconsin.’’). 

22NOPR, 179 FERC ¶ 61,028 at PP 383–415. 

23See, e.g., Ohio Consumers’ Counsel Comments 

at 13 (explaining that the Ohio Power Siting Board 

(OPSB) does not review local projects ‘‘for need, 

prudence, or cost efficiency’’); Ohio Consumers’ 

Counsel Reply Comments at 8 (‘‘the OPSB rejected 

[Ohio Consumers’ Counsel’s] recommendation that 

the OPSB report to the General Assembly that the 

state legislature should pass new statutory authority 

for OPSB that would require the agency to regulate 

the siting of, need for and cost-effectiveness of any 

proposed new transmission facilities in Ohio rated 

at 69 kV and above.’’). 

1Transmission 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). 

2 16 U.S.C. 824e. 

3For instance, after an 85% cost decline over the 

past decade, solar photovoltaic systems are among 

the most cost-competitive energy resources in the 

market. See Deloitte, 2022 Renewable Energy 

Outlook, https://www2.deloitte.com/us/en/pages/ 

energy-and-resources/articles/renewable-energyoutlook.html. 

4Queued Up: Characteristics of Power Plants 

Seeking Transmission Interconnection As of the 

End of 2020, Lawrence Berkeley National 

Laboratory, at 22 (May 2021). 

5Queued Up: Characteristics of Power Plants 

Seeking Transmission Interconnection As of the 

End of 2021, Lawrence Berkeley National 

Laboratory, at 3 (April 2022). 

6As outlined in the November 2021 FERC– 

NERC–Regional Entity Staff Report on Winter Storm 

Uri, interregional transfers played a critical role in 

helping MISO and SPP compensate for generation 

outages during the event. The February 2021 Cold 

Weather Outages in Texas and the South Central 

United States, FERC, NERC and Regional Entity 

Staff Report, at 98 (November 2021). 

7See National Association of Regulatory Utility 

Commissioners (NARUC) Comments at 17 

(‘‘Because certain clean energy resources are diffuse 

by nature, meaning the resources exist at disparate 

locations and cannot simply be placed near existing 

load centers, new transmission facilities may need 

to be developed to gather and transport energy from 

generation rich areas to load.’’); Harvard Electricity 

Law Initiative Comments at 17 (‘‘Transmission is 

needed to connect these location-constrained 

resources and to ensure that the system remains 

reliable with a larger share of intermittent 

generation.’’). 

important roles proposed in this NOPR, 

without preempting the regional planning 

entities from seeking additional input 

through their existing stakeholder processes. 

14. The bottom line for me is this: I believe 

that elevating the role in planning and cost 

allocation of state regulators—who are, as a 

group, deeply concerned about the monthly 

bills paid by consumers, of which 

transmission is a rapidly growing 

component—will make it more likely, not 

less, that necessary transmission can get built 

while ensuring that rates resulting from these 

types of policy-driven projects will not be 

unjust and unreasonable, which they clearly 

have the potential to be. 

15. There is a third feature of this NOPR 

I also find very important. For LTRT projects 

the NOPR proposes to end the Commission’s 

long practice of awarding, as an incentive, 

cost recovery for Construction Work in 

Process (CWIP); instead it will propose to 

require the booking of these pre-service costs 

as Allowance for Funds Used During 

Construction (AFUDC).20 CWIP is the award 

of cost recovery of construction costs during 

the pre-construction and construction phases 

to the developer. CWIP is, of course, passed 

through as a cost to consumers, making 

consumers effectively an involuntary lender 

to the developer. By contrast, AFUDC is 

booked during the pre-service phases, but 

cannot be recovered from customers until the 

project is completed and actually serving 

customers, i.e., ‘‘used and useful.’’ The NOPR 

proposal is simply in keeping with 

traditional good utility ratemaking 

principles. Booking these costs as AFUDC 

also recognizes the reality that just because 

an LTRT project is selected for a regional 

plan, it still has to obtain all state siting, 

certificate of public convenience and 

necessity and other, including 

environmental, approvals, and survive what 

may be the subsequent litigation, before it is 

actually built.21 Consumers should be 

protected from paying CWIP costs during this 

potentially long period before a project 

actually enters service, if it ever does. This 

NOPR proposal represents a major step 

forward in consumer protection and is a big 

reason I am voting for it. 

16. Finally, let me note again that this is 

a NOPR—a continuing work in progress with 

more work ahead. For example, the section 

on planning of local projects 22 seeks to 

address a concern expressed by many 

commenters, that local projects may not be 

getting sufficiently vetted by regional 

planning entities. In response, the NOPR 

essentially proposes PJM’s procedures for 

vetting and transparency of local projects, but 

I welcome additional comment from other 

regional entities as to whether there are more 

conducive measures for such vetting that 

may fit their own regions better. Most 

importantly, on the broader issue of whether 

local projects are being properly scrutinized, 

as a former state regulator who sat on scores 

of local-project cases, I would point out that 

no local project is going to be built unless a 

state agency approves a certificate or its 

equivalent. While the commenters note that 

procedures differ greatly from state to state, 

and some state utility commissions have 

more authority than others,23 there is no 

question that states have within their 

inherent police powers the authority to 

regulate utilities and that includes the power 

to vet local projects both as to need and cost 

before approving them, just as states have the 

siting authority. If states are not using these 

powers to vet fully such local projects, they 

should review their own state laws and 

procedures. And if states believe they need 

more information from the RTOs/ISOs to 

make more informed decisions in their 

vetting processes, please comment on what 

additional information would be helpful for 

the RTOs and ISOs to provide. States should 

be a full partner in the process for vetting and 

approving local projects and I invite 

comment on how to strengthen state 

oversight of these projects to get the best deal 

for the consumer. 

For these reasons cited above, I concur in 

the issuance of the NOPR. 

lllllllllllllllllllll

Mark C. Christie, 

Commissioner. 

United States of America 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 April 21, 2022) 

PHILLIPS, Commissioner, concurring: 

1. I concur in today’s Notice of Proposed 

Rulemaking (NOPR) to emphasize the 

importance of our action today and to call 

attention to the work that remains. I believe 

today’s NOPR represents a critical first step 

toward ensuring a 21st century electric grid 

that is capable of reliably and affordably 

accommodating new generation. 

2. Most commenters urge the Commission 

to reexamine the transmission planning and 

cost allocation policies adopted in Order No. 

1000 over a decade ago.1 While Order No. 

1000 was well intentioned, commentors 

argue that it fell short of its goal to spur 

competitive transmission buildout. Under 

section 206 of the Federal Power Act,2 the 

Commission must ensure that transmission 

rates are just and reasonable. If there are 

deficiencies in the Commission’s existing 

regional transmission planning and cost 

allocation requirements, we must endeavor to 

remedy those deficiencies. For this reason, I 

support the NOPR’s proposal to revisit our 

existing policies. 

3. This NOPR acknowledges the facts on 

the ground. It is an inescapable fact that our 

resource mix is changing, which is a key 

factor leading to a greater need for 

transmission. Due in large part to economies 

of scale, the cost of renewable energy has 

fallen rapidly over the last decade while the 

demand for those resources has increased.3

As of the end of 2020, there were over 800 

GW of wind, solar, and energy storage 

capacity seeking interconnection in the 

United States.4 That figure has now risen to 

1,300 gigawatts of wind, solar and storage 

capacity proposed for interconnection as of 

the end of 2021.5 At the same time as the 

resource mix is changing, severe weather 

events and wildfires are becoming more 

frequent and extreme.6 These are just a few 

of the factors contributing to a greater need 

for expansion of our nation’s grid.7

4. The record here appears to show that 

transmission expansion is increasingly 

occurring in a piecemeal and inefficient 

fashion outside of the regional transmission 


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8See Building for the Future Through Electric 

Regional Transmission Planning and Cost 

Allocation and Generator Interconnection, 179 

FERC ¶ 61,028, at P 38 (2022) (NOPR) (discussing 

the dramatic increase in cost, size, and scope of 

interconnection-related network upgrades). 

9See Americans for a Clean Energy Grid Reply 

Comments, Appendix A (listing 174 commenters). 

10See NOPR, 179 FERC ¶ 61,028 at P 183. 

11 Id. P 242. 

12See, e.g., Advanced Energy Economy Reply 

Comments at 17–23; American Electric Power 

Service Corporation Comments at 36–38; American 

Public Power Association Comments at 27; Edison 

Electric Institute Reply Comments at 27–30; 

NextEra Energy, Inc. Comments at 12. 

13See Queued Up . . . But in Need of 

Transmission Unleashing the Benefits of Clean 

Power with Grid Infrastructure, U.S. Department of 

Energy, at 2 (April 2022). 

14See, e.g., California Public Utilities 

Commission Comments at 70 (noting that California 

Independent System Operator Corporation is 

undertaking a stakeholder process focused on 

increasing efficiency of the interconnection study 

process); PJM Interconnection, L.L.C. Comments at 

47–49. 

15See, e.g., NARUC Comments at 8 (‘‘The 

planning process should share system planning 

information on an interregional level whenever 

appropriate.’’); id. at 19 (describing how during 

Winter Storm Uri, ‘‘usually a net exporter of energy, 

SPP relied significantly on imported energy to serve 

load during the winter event’’ and that ‘‘effective 

planning should strive to quantify benefits 

associated with enhancing interregional import and 

export capabilities, given the likelihood of future 

extreme weather events and related energy 

shortages. Further analysis and process 

improvements in interregional transmission 

development and imports and exports capability 

will be necessary, not only to accommodate 

demand for a clean energy transition, but also for 

reliability and defined resiliency benefits.’’); PJM 

Interconnection, L.L.C. Comments at 72–73 (stating 

that greater interregional transfer capability has a 

significant reliability benefit as demonstrated by the 

February 2021 Cold Snap and the 2014 Polar 

Vortex, and the Commission should approach the 

issue of strengthening interregional ties as a broad 

reliability-based benefit); New York Independent 

System Operator, Inc. Comments at 55 

(‘‘Interconnections with neighboring systems are 

important tools to support grid reliability, 

resiliency, and market efficiency by providing 

opportunities for the exchange of capacity and 

energy.’’). 

planning process, which may not be costeffective for consumers in the long run.8

While commenters’ views vary on how best 

to address this problem, nearly all 

commenters endorse some form of proactive 

planning for the future resource mix and 

demand.9 I believe the NOPR proposal to 

require long-term scenario planning, 

including accounting for extreme weather 

events, is necessary to maintain the 

reliability of the grid and to ensure that 

transmission costs are just and reasonable. I 

also note that while this NOPR proposes to 

require the evaluation of benefits of longterm regional transmission facilities over a 

20-year time horizon, it does not propose to 

prescribe any particular definition of 

‘‘benefits’’ or ‘‘beneficiaries,’’ nor require use 

of any specific benefits.10 Instead, we 

continue to acknowledge the benefits of 

regional flexibility. Nor does it propose to 

require that transmission providers select any 

particular transmission projects, instead 

proposing to provide transmission providers 

the flexibility to propose the selection criteria 

that they, in consultation with their 

stakeholders and states, believe will ensure 

that more efficient or cost-effective long-term 

regional transmission facilities ultimately are 

selected.11 And I support the proposal to 

require transmission providers to consult 

with and incorporate states’ views in project 

selection and cost allocation. I invite 

comment on the value of such state 

involvement for increasing the likelihood 

that those facilities are sited and ultimately 

developed with fewer costly delays. 

5. I also strongly support the NOPR 

proposal for greater consideration of dynamic 

line ratings and advanced power flow control 

devices in regional transmission planning 

processes. Grid-enhancing technologies 

(GETs) can optimize our existing 

transmission infrastructure and provide costeffective solutions for consumers. For 

example, by allowing the measurement of 

transmission capacity in real-time, dynamic 

line ratings can provide net benefits to 

customers by allowing increased power flow 

and reducing congestion costs, as well as by 

detecting when power flows should be 

reduced to avoid unnecessary wear on 

transmission equipment. The role that these 

and other GETs could play in delaying or 

eliminating the need for new transmission 

facilities cannot be ignored. I urge the 

Commission to consider further reforms to 

incentivize the adoption and deployment of 

GETs. 

6. Many commenters raise concerns about 

delays and significant backlogs in 

interconnection queues across the country.12

Currently, less than a quarter of generator 

interconnection applications actually result 

in an interconnection.13 Interconnection 

applicants submitting speculative 

interconnection requests can linger in the 

queue, only to withdraw at late stages, often 

necessitating the study of non-viable projects 

as well as restudies due to withdrawals. 

These often result in delays and cost risks for 

commercially viable projects that are 

otherwise ready to interconnect. Although 

the reforms we propose in this NOPR may 

help mitigate these issues in the long term, 

they are not enough to alleviate existing 

backlogs in the near term. While I recognize 

and commend the ongoing efforts in some 

regions to address the large volume of 

interconnection requests,14 I encourage my 

colleagues to consider whether it is necessary 

to require certain best practices, such as firstready, first-served cluster study approaches, 

to process interconnection requests more 

efficiently. 

7. Similarly, many commenters have 

highlighted the importance of adopting 

interregional coordination and planning 

reforms, particularly for reliability.15 Today’s 

NOPR does not, at this time, propose changes 

to the existing interregional transmission 

coordination and cost allocation 

requirements of Order No. 1000. As we 

continue to examine those issues, I urge the 

Commission to act expeditiously to propose 

interregional reliability planning reforms. 

Looking beyond regional boundaries is 

important so that cost-efficient regional and 

interregional projects can be considered and 

studied together. We should consider 

whether neighboring regions should adopt 

common planning assumptions and methods 

that allow for region-specific inputs. 

Additionally, I believe we must consider 

whether to adopt a requirement for a 

minimum amount of interregional transfer 

capacity to protect against generation 

shortfalls, especially during extreme weather 

events. 

8. Finally, I note that this NOPR is merely 

a proposal and I am looking forward to 

reviewing the comments in response. In 

addition, I emphasize that the reforms in this 

NOPR are not intended to be one-size-fits-all, 

nor would I support such an approach. 

Recognizing the unique needs and 

characteristics of individual markets and 

regions, I am particularly interested in 

comments on whether the reforms proposed 

in this NOPR allow for a sufficient level of 

regional flexibility. 

For these reasons, I respectfully concur. 

Willie L. Phillips, 

Commissioner. 

[FR Doc. 2022–08973 Filed 5–3–22; 8:45 am] 

BILLING CODE 6717–01–P 


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