[Federal Register Volume 87, Number 86 (Wednesday, May 4, 2022)]
[Proposed Rules]
[Pages 26504-26611]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-08973]



[[Page 26503]]

Vol. 87

Wednesday,

No. 86

May 4, 2022

Part IV





Department of Energy





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 Federal Energy Regulatory Commission





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18 CFR Part 35





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

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

[[Page 26504]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM21-17-000]


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

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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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 forward-looking 
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-in-progress 
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.
    [cir] Mail via U.S. Postal Service Only: Addressed to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street NE, Washington, DC 20426.
    [cir] 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, 
[email protected]
Noah Lichtenstein (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696, 
[email protected]
Lina Naik (Legal Information), Office of the General Counsel, 888 First 
Street NE, Washington, DC 20426, (202) 502-8882, [email protected]

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            28
   Planning and Cost Allocation to Identify and Plan for
   Transmission Needs Driven by Changes in the Resource Mix
   and Demand...............................................
  B. Unjust and Unreasonable and Unduly Discriminatory and            34
   Preferential Commission-Jurisdictional Rates.............
      1. The Transmission Investment Landscape Today........          36
      2. Deficiencies in the Commission's Existing Regional           47
       Transmission Planning and Cost Allocation
       Requirements.........................................
IV. Regional Transmission Planning..........................          56
  A. Overview of Existing Regional Transmission Planning              57
   Processes................................................
      1. Reliability Needs..................................          58
      2. Economic Needs.....................................          59
      3. Transmission Needs Driven by Public Policy                   60
       Requirements.........................................
  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           79
               In Long-Term Regional Transmission Planning..
                  (a) Comments..............................          80
                  (b) Proposed Reform.......................          84
                  (1) Long-Term Scenarios Requirements......          91
                  (i) Transmission Planning Horizon and               92
                   Frequency................................
                  (01) Comments.............................          95

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                  (02) Proposed Requirement.................          97
                  (ii) Factors..............................         101
                  (01) Comments.............................         103
                  (02) Proposed Requirement.................         104
                  (iii) Number and Range of Long-Term                113
                   Scenarios................................
                  (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              154
               Planning and Generator Interconnection
               Processes....................................
                  (a) ANOPR.................................         155
                  (b) Comments..............................         157
                  (c) Need for Reform.......................         161
                  (d) Proposed Reform.......................         166
              iii. Evaluation of the Benefits of Regional            175
               Transmission Facilities......................
                  (a) Evaluations of Long-Term Regional              176
                   Transmission Benefits....................
                  (1) Comments..............................         178
                  (2) Proposed Reform.......................         183
                  (3) Description of Long-Term Regional              189
                   Transmission Benefits....................
                  (b) Evaluation of Transmission Benefits            226
                   Over Longer Time Horizon.................
                  (1) Comments..............................         226
                  (2) Proposed Reform.......................         227
                  (c) Evaluation of the Benefits of                  231
                   Portfolios of Transmission Facilities....
                  (1) Comments..............................         232
                  (2) Proposed Reform.......................         233
              iv. Selection of Regional Transmission                 236
               Facilities...................................
                  (a) Comments..............................         238
                  (b) Proposed Reform.......................         241
          c. Implementation of Long-Term Regional                    253
           Transmission Planning............................
      2. Consideration of Dynamic Line Ratings and Advanced          256
       Power Flow Control Devices in Long-Term Regional
       Transmission Planning................................
          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          302
       Regional Transmission Facilities.....................
          a. Agreement of Relevant State Entities...........         304
          b. State Agreement Process........................         311
      2. Time Period in Long-Term Regional Transmission              319
       Planning Cost Allocation Processes for State-
       Negotiated Alternate Cost Allocation Method..........
      3. Identification of Benefits Considered in Cost               325
       Allocation for Long-Term Regional Transmission
       Facilities...........................................
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                 335
 Commission-Jurisdictional Tariffs and Agreements...........
  A. Background.............................................         337
      1. Order No. 1000's Nonincumbent Transmission                  337
       Developer Reforms and Federal Right of First Refusal
       Elimination Mandate..................................
      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             358
       Certain Jointly-Owned Transmission Facilities........
          a. Background.....................................         359
          b. Comments.......................................         360
          c. Proposed Reform................................         365
VIII. Enhanced Transparency of Local Transmission Planning           383
 Inputs In the Regional Transmission Planning Process and
 Identifying Potential Opportunities to Right-Size
 Replacement Transmission Facilities........................
  A. Background.............................................         383
  B. ANOPR..................................................         387

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  C. Comments...............................................         390
  D. Need for Reform........................................         398
  E. Proposed Reform........................................         400
IX. Interregional Transmission Coordination and Cost                 416
 Allocation.................................................
  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.
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    \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.
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    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.
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    \2\ Promoting 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).
    \3\ Preventing 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).
    \4\ Transmission 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).
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    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 forward-looking basis to meet 
transmission needs driven by changes in the resource mix and demand.\5\ 
As part of this long-term 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 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 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.
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    \5\ A 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).
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    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.
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    \6\ This NOPR refers to such facilities as ``Long-Term Regional 
Transmission Facilities''.
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    5. We also propose to not permit public utility transmission 
providers to take advantage of the construction-work-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

[[Page 26507]]

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 interconnection-related 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.
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    \7\ Building 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).
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    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\
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    \8\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
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    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\
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    \9\ Order 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.
    \12\ Public Policy Requirements are requirements established by 
local, state or federal laws or regulations (i.e., enacted statutes 
passed by the legislature and signed by the executive and 
regulations promulgated by a relevant jurisdiction, whether within a 
state or at the federal level). 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.
    \13\ Order No. 1000, 136 FERC ] 61,051 at P 3.
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    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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    \14\ Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ] 61,132 at 
PP 3, 4-6.
    \15\ Order No. 1000, 136 FERC ] 61,051 at P 12.

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[[Page 26508]]

    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\
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    \16\ The 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.
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    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\ Commission-
approved 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\
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    \17\ A 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.
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    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.
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    \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.
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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 Commission-
jurisdictional 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 Commission-jurisdictional 
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 
Commission-jurisdictional rates remain just and reasonable and not 
unduly discriminatory or preferential and that reliability is 
maintained.
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    \24\ ANOPR, 176 FERC ] 61,024 at P 3.
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    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.
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    \25\ Building 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).
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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 transmission-related 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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    \26\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC 
] 61,224, at PP 1, 6 (2021).
    \27\ Id. P 2.
    \28\ An 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 meetings, are available in the Commission's eLibrary in 
Docket No. AD21-15-000.

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[[Page 26509]]

    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\
---------------------------------------------------------------------------

    \29\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching 
agenda).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \30\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching 
agenda).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \31\ See Appendix A for a list of commenters and the abbreviated 
names of commenters that are used in this NOPR.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \32\ See supra PP 12-14.
---------------------------------------------------------------------------

    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 cost-effective 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.
---------------------------------------------------------------------------

    \33\ S.C. Pub. Serv. Auth., 762 F.3d at 56-59.
---------------------------------------------------------------------------

    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

[[Page 26510]]

transmission planning and cost allocation processes.
    27. In light of those concerns, we propose reforms to require 
public utility transmission providers to conduct long-term 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 Commission-jurisdictional 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 cost-effective 
transmission facilities to meet transmission needs.
---------------------------------------------------------------------------

    \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 inter-
regional transmission projects, is key to continued access to 
reliable, resilient, lower-cost, and clean electricity for all'').
    \35\ See, 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%20Reliability%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.
    \36\ U.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).
    \37\ MISO'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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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-proven-practices-that-increase-value-and-reduce-costs-7.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 . . . .'')).
    \39\ See, e.g., PJM Interconnection, L.L.C., PJM Value 
Proposition (2019), https://www.pjm.com/about-pjm/~/media/about-pjm/
pjm-value-proposition.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/miso-strategy-and-value-proposition/miso-value-proposition/ (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.).
    \40\ U.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'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \41\ See, 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-model-bringing-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).
    \42\ MTEP17 Review at 4.
---------------------------------------------------------------------------

    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

[[Page 26511]]

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\
---------------------------------------------------------------------------

    \43\ Midcontinent 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 time-frame.'' Id.
    \44\ MISO 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 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.
    \45\ See, e.g., MTEP17 Review at 16.
    \46\ Id. at 13.
    \47\ MISO Comments at 9.
---------------------------------------------------------------------------

    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 large-scale 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\
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    \48\ Order No. 890, 118 FERC ] 61,119 at P 57.
    \49\ Order No. 1000, 136 FERC ] 61,051 at P 486.
    \50\ Id. PP 498-501.
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    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 cost-benefit 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

[[Page 26512]]

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 cost-effective 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 cost-effective regional transmission facilities.
---------------------------------------------------------------------------

    \51\ The 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.
---------------------------------------------------------------------------

    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 interconnection-related 
network upgrades and noted a similar trend in other MISO sub-
regions.\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\
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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-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf (ICF Sept. 2021 Report) (attached to ACORE Comments as 
Exhibit 5).
    \53\ Americans 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-Generator-Interconnection-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/MISO2020InterconnectionQueueOutlook445829.pdf 
(MISO 2020 Queue Outlook)).
    \54\ ICF Sept. 2021 Report at 2.
---------------------------------------------------------------------------

    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 
ever-growing 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.
---------------------------------------------------------------------------

    \55\ ACEG Jan. 2021 Interconnection Report at 14; NextEra 
Comments at 16 (citing MISO 2020 Queue Outlook at fig. 7).
    \56\ E.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 interconnection-related 
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 interconnection-related 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).
    \57\ ACEG 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).
    \58\ See 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).
    \59\ See 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).
---------------------------------------------------------------------------

    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

[[Page 26513]]

of cost allocation since implementation of Order No. 1000.\62\
---------------------------------------------------------------------------

    \60\ Brattle-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-and-Challenges.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/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf (Brattle Apr. 2019 Competition Report).
    \61\ See, 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).
    \62\ LS 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/transmission-investment-metrics.pdf.
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    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\
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    \63\ See 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.
    \64\ Brattle-Grid Strategies Oct. 2021 Report at 2-3.
    \65\ LS Power October 12 Comments, Ex. 9, at 7.
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    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 cost-
effective 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\
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    \66\ See Order No. 1000-A, 139 FERC ] 61,132 at P 5.
    \67\ See id.
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    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 cost-effective 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 Commission-
jurisdictional rates that are unjust and unreasonable and unduly 
discriminatory and preferential.
---------------------------------------------------------------------------

    \68\ See supra PP 28-32.
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    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 non-discriminatory 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.
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    \69\ Order 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.
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    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

[[Page 26514]]

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.
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    \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 
total approximately 48.4 GW. NERC, 2021 Long-Term Reliability 
Assessment, at 30, 35 (Dec. 2021).
    \72\ See 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).
    \73\ See 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).
    \74\ See 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).
    \75\ See 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).
    \76\ For 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).
    \77\ For 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.
    \78\ Moreover, 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.'').
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    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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    \79\ See, 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).
    \81\ See, 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'').
    \82\ See, 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 cost-inefficient 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).
    \83\ See, 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).
    \84\ See, 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'').
    \85\ See, 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'').
    \86\ MISO 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).
    \87\ See, 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 cost-causers and 
beneficiaries which create free rider situations; and failure to 
consider congestion costs and other economic impacts in processes 
used to 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).

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[[Page 26515]]

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 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 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 long-term 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\
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    \88\ For 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, Sec.  IV.2 (8.0.0), Sec.  IV.2.a)
    \89\ For 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'').
    \90\ Policy Integrity Comments at 29.
    \91\ PJM'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.'').
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    49. While it is reasonable for regional transmission planning and 
cost allocation processes to include near-term 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 long-lead 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\
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    \92\ U.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.'').
    \93\ U.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 
[Aacute]lvaro Garc[iacute]a-Cerzo et al., Robust Transmission 
Network Expansion Planning Considering Non-Convex Operational 
Constraints, 98 Energy Econ. (June 2021)).
---------------------------------------------------------------------------

    50. The second deficiency is that existing requirements fail to 
ensure that public utility transmission providers adequately account on 
a forward-looking 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

[[Page 26516]]

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\
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    \94\ See 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).
    \95\ See 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 high-value zones).
---------------------------------------------------------------------------

    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, Commission-jurisdictional 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.
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    \96\ NERC 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).
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    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\
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    \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).
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    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.
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    \98\ See infra P-235- .
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    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 Commission-jurisdictional 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

[[Page 26517]]

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 cost-effectively 
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.
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    \99\ ANOPR, 176 FERC ] 61,024 at P 13.
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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\
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    \100\ 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.
    \101\ Long-term planning for reliability by RTO/ISO varies as 
follows: CAISO at least 10 years (CAISO, CASIO eTariff, Sec.  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), Sec.  
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), Sec.  I.C.8.a)); NYISO years 
4 through 10 (NYISO, NYISO Tariffs, NYISO OATT, Sec.  31.1, attach. 
Y (New York Comprehensive System Planning Process) (26.0.0)); PJM 10 
years (PJM, Intra-PJM Tariffs, OA Schedule 6, Sec.  1.4 (Contents of 
the Regional Transmission Expansion Plan) (2.1.0), Sec.  1.4.b)); 
and, SPP 10 and 20 years (Southwest Power Pool, Inc., OATT, attach. 
Y, Sec.  III (The Integrated Transmission Planning Assessment) 
(8.0.0), Sec.  IV (Other Planning Studies) (8.0.0)).
    \102\ For 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.
    \103\ The 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.
    \104\ ANOPR, 176 FERC ] 61,024 at P 14.
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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 cost-effectively 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.
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    \105\ Order No. 1000, 136 FERC ] 61,051 at PP 3, 81, 147.
    \106\ Id. P 148.
    \107\ Id. PP 147-148.
    \108\ Order No. 890, 118 FERC ] 61,119 at P 549.
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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

[[Page 26518]]

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.
---------------------------------------------------------------------------

    \109\ Order No. 1000, 136 FERC ] 61,051 at PP 203, 222; Order 
No. 1000-A, 139 FERC ] 61,132 at P 208.
    \110\ Order 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.
    \112\ Order No. 1000-A, 139 FERC ] 61,132 at P 322.
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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\
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    \113\ E.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).
    \114\ For 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.
---------------------------------------------------------------------------

    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\
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    \116\ CAISO Comments at 3-5; MISO Comments at 2-4.
    \117\ ISO-NE Comments at 2, 13-16.
    \118\ NYISO Comments at 2-4.
---------------------------------------------------------------------------

    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\
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    \119\ PJM Market Monitor Comments at 2-3.
    \120\ Potomac Economics Comments at 4.
    \121\ SPP Market Monitor Comments at 4.
---------------------------------------------------------------------------

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 forward-looking 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

[[Page 26519]]

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.
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    \122\ Supra 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.
    \123\ See infra P 94.
    \124\ See supra P 36.
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    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.
---------------------------------------------------------------------------

    \125\ Order No. 1000, 136 FERC ] 61,051 at PP 624-625.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \126\ ANOPR, 176 FERC ] 61,024 at P 85.
    \127\ See 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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \128\ For 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 re-
assessment providing the basis for identification and evaluation of 
transmission facilities for potential selection in the regional 
transmission plan for purposes of cost allocation.
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    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

[[Page 26520]]

allocation that more efficiently or cost-effectively address these 
transmission needs in collaboration with states and other stakeholders. 
We discuss each of these requirements in greater detail below.
---------------------------------------------------------------------------

    \129\ We 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.
---------------------------------------------------------------------------

    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.
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    \130\ See Order No. 1000, 136 FERC ] 61,051 at P 11.
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    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.
---------------------------------------------------------------------------

    \131\ See 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.
    \132\ See id. P 2.
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    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 Long-Term 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;

[[Page 26521]]

(5) comparability; and (6) dispute resolution.\133\
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    \133\ See id. PP 146, 151.
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    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 Long-Term 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 Commission-identified 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 under-forecast 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\
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    \134\ ANOPR, 176 FERC ] 61,024 at P 31.
    \135\ Id.
    \136\ Id. P 47.
    \137\ Id. P 46.
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(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\
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    \138\ E.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.
    \139\ CAISO 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.
    \140\ See SERTP Comments at 8, 14-17; SERTP Reply Comments at 
11.
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    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 non-binding.\143\ Some 
public utility transmission providers equate scenario planning to their 
existing integrated resource plans.\144\
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    \141\ E.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.
    \142\ E.g., National Grid Comments at 4-9; Exelon Comments at 
12-16.
    \143\ E.g., Southern Comments at 36-37; Arizona Public Service 
Comments at 2-4; Xcel Comments at 20.
    \144\ E.g., Berkshire Comments at 12-13.
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    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\
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    \145\ NARUC Comments at 6, 10-11.
    \146\ E.g., Arizona Commission Comments at 2; Oregon Commission 
Comments at 8-9; Massachusetts Attorney General Comments at 5-15.
    \147\ E.g., Mississippi Commission Comments at 3; Nebraska 
Commission Comments at 3-4; Michigan Commission Comments at 7.
    \148\ PJM 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).
    \149\ SPP Market Monitor Comments at 3.
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    83. Several consumer and trade organizations support scenario 
planning to assess uncertainty about future

[[Page 26522]]

transmission needs.\150\ Some commenters call for a national uniform 
framework for scenario planning.\151\
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    \150\ E.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.
    \151\ See, e.g., NARUC Comments at 17; PIOs Comments at 103; 
Policy Integrity Comments 29-40; U.S. DOE Comments at 33.
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(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 Long-Term 
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 Long-Term 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 Long-Term 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 Long-Term 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.
---------------------------------------------------------------------------

    \152\ Supra 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.
---------------------------------------------------------------------------

    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 cost-
effectively 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.
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    \153\ Supra Need for Reform: Deficiencies in the Commission's 
Existing Regional Transmission Planning and Cost Allocation 
Requirements.
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    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,

[[Page 26523]]

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 Commission-
identified 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 Long-Term Scenarios. For example, a transmission planning 
horizon of 20 years means that the public utility transmission provider 
develops Long-Term 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 cost-
effective 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 
Long-Term Regional Transmission Planning should not remain static over 
time. Instead, they should be periodically re-evaluated 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 Long-Term 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 longer-term 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 high-level 
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.
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    \154\ CAISO Comments at 44-46.
    \155\ NYISO 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.
    \156\ SPP Comments at 3; SPP, OATT, attach. O, Sec.  IV.2 
(4.0.0), Sec.  IV.2.a.
    \157\ MISO Comments at 36.
    \158\ PJM Comments at 41.
    \159\ E.g., Southeastern Regional Transmission Planning, 2021 
Regional Transmission Planning Analyses, at 2 (Nov. 17, 2021), 
https://www.southeasternrtp.com/docs/general/2021/2021-SERTP-Regional-Transmission-Planning-Analyses-Summary-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.
    \160\ See 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.
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(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

[[Page 26524]]

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 shorter-term 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\
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    \162\ E.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.
    \163\ For 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.
    \164\ November 2021 Technical Conference Transcript (Tr.) at 
129-137.
    \165\ Id. at 129-137.
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    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\
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    \166\ For 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.
    \167\ AEP Comments at 10-11.
    \168\ November 2021 Technical Conference Tr. at 138-140.
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(02) Proposed Requirement
    97. We propose to require that public utility transmission 
providers develop Long-Term Scenarios as part of Long-Term 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--Long-Term Regional 
Transmission Planning should be able to identify more efficient or 
cost-effective regional transmission facilities to address these needs.
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    \169\ The 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.
    \170\ As indicated above in this NOPR, NERC defines the long-
term transmission planning horizon as covering year six through year 
10 and beyond.
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    99. We preliminarily find that a three-year 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.
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    \171\ For 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.
---------------------------------------------------------------------------

    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

[[Page 26525]]

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 long-term 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\
---------------------------------------------------------------------------

    \172\ MISO Comments at 41-43.
---------------------------------------------------------------------------

    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\
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    \173\ ANOPR, 176 FERC ] 61,024 at P 46.
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(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

[[Page 26526]]

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\
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    \174\ E.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.
    \175\ E.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.
    \176\ E.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.
    \177\ E.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.
    \178\ E.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.
    \179\ E.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.
    \180\ E.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.
    \182\ City of New York Comments at 6-7.
    \183\ Exelon Comments at 12, 15-16.
    \184\ ACPA and ESA Comments at 46.
    \185\ Southern Comments at 3-5; Berkshire Comments at 12-13.
    \186\ Industrial Customers Comments at 20-33.
    \187\ Potomac Economics Comments at 4.
    \188\ PJM 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).
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(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 Long-Term 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\
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    \189\ For 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.
    \190\ For example, five of the six New England states are 
statutorily required to reduce economy-wide 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.
    \191\ For example, North Carolina's vertically-integrated 
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.
    \192\ For 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)).
    \193\ For 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.
    \194\ For 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.
    \195\ For 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.
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    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 Long-Term 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 Long-Term 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

[[Page 26527]]

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 Same-Time 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 
Long-Term 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.
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    \196\ See 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.'').
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    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.
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    \197\ Order No. 1000, 136 FERC ] 61,051 at PP 206-207; Order No. 
1000-A, 139 FERC ] 61,132 at P 335.
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    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 Long-Term 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\
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    \198\ MISO Comments at 8, 80.
    \199\ MISO, MISO Futures Report, at 4 (Dec. 2021).
    \200\ CAISO Comments at 45.
    \201\ SPP, 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).
    \202\ NYISO Comments at 28-29.
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    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 cost-effective 
transmission facilities in regional transmission plans.\203\
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    \203\ ANOPR, 176 FERC ] 61,024 at P 48.
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    117. The ANOPR also sought comment on how the regional

[[Page 26528]]

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\
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    \204\ Id.
    \205\ Stochastic models are frameworks for addressing 
optimization problems that involve uncertainty.
    \206\ ANOPR, 176 FERC ] 61,024 at P 49.
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(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-as-usual, 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\
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    \207\ U.S. DOE Comments at 12-15.
    \208\ ACPA and ESA Comments at 46.
    \209\ Oregon Commission Comments at 8-9.
    \210\ Eversource Comments at 9.
    \211\ Nebraska Commission Comments at 3-4.
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    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-as-usual 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\
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    \212\ ACPA and ESA Comments at 46.
    \213\ AEP Comments at 11-12.
    \214\ NextEra Comments at 71-71, 75-77.
    \215\ Nature Conservancy Comments at 3.
    \216\ Avangrid Comments at 12-14.
    \217\ LS Power Oct. 12 Comments at 33-36.
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    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 wide-ranging stakeholder opinions about 
the future.\224\
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    \218\ E.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'').
    \219\ AES Ohio Comments at 2-3; PIOs Comments at 79; California 
Commission Comments at 66; VEIR Comments at 15-16.
    \220\ PG&E Comments at 3.
    \221\ U.S. DOE Comments at 20.
    \222\ EEI 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).
    \223\ PJM Comments at 64-66; MISO Comments at 46-47; CAISO 
Comments at 48.
    \224\ Minnesota Commission Comments at 4.
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(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 
Long-Term 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

[[Page 26529]]

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 high-impact, 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.
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    \225\ We 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.
    \226\ The 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.
    \227\ The 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.
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    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, 
low-frequency events. We propose to allow public utility transmission 
providers to determine which high-impact, low-frequency 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-
than-expected 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\
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    \228\ For 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?'').
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    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.
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    \229\ See, 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.
---------------------------------------------------------------------------

    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

[[Page 26530]]

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 cost-effective 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\
---------------------------------------------------------------------------

    \230\ ANOPR, 176 FERC ] 61,024 at P 48.
    \231\ Id. P 50.
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \232\ As 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.
    \233\ PJM Comments, attach. K at 4.
    \234\ ACEG Comments, attach. C at 10; AEE Reply Comments at 4; 
PIOs Reply Comments at 43-44.
    \235\ Rail Electrification Comments at 13.
    \236\ Union of Concerned Scientists Comments at 31.
    \237\ U.S. DOE Comments at 12-13.
    \238\ Id. at attach. B.
    \239\ NARUC Comments at 42.
    \240\ RMI Comments at 3.
    \241\ NERC Comments at 10.
    \242\ Entergy Comments at 17.
    \243\ Certain TDUs Comment at 11.
    \244\ PJM Market Monitor Comments at 6.
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \245\ Timely data inputs are based on the most current 
information.
    \246\ See supra note 226.
    \247\ See, 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.
---------------------------------------------------------------------------

    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 Long-Term 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

[[Page 26531]]

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \249\ ANOPR, 176 FERC ] 61,024 at P 57.
    \250\ Id. PP 55-56.
---------------------------------------------------------------------------

(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 buy-in 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\
---------------------------------------------------------------------------

    \251\ CAISO Comments at 49-54.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \252\ NYISO Comments at 31-33.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \254\ PJM Comments at 12-13.
    \255\ Id. at 41-42.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \256\ MISO Comments at 53-56.
    \257\ Id. at 56-58.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \258\ U.S. DOI Comments at 1-3.
    \259\ U.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'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \260\ Consumer Organizations Comments at 21.
    \261\ East Kentucky Comments at 8-9.
    \262\ APPA Comments at 17.
    \263\ OMS Comments at 8-9; NESCOE Comments at 46-47.
    \264\ WIRES Comments at 41-42.
    \265\ Xcel Comments at 5-10.
---------------------------------------------------------------------------

    143. Ohio Commission states that the Commission lacks jurisdiction 
to require the creation of new zones.\266\ Michigan

[[Page 26532]]

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\
---------------------------------------------------------------------------

    \266\ Ohio Commission Comments at 6-10.
    \267\ Michigan Commission Comments at 12-14.
    \268\ NRECA Comments at 21-23
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \269\ LPPC Comments at 14-15.
    \270\ SoCal Edison Comments at 10.
    \271\ Shell Comments at 8-9.
    \272\ Orsted Comments at 8.
    \273\ Union of Concerned Scientists Comments at 32-37.
---------------------------------------------------------------------------

(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 cost-effective 
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.
---------------------------------------------------------------------------

    \274\ We note that, while we refer to multiple ``zones,'' 
subsequent to stakeholder feedback, the final list may contain only 
one designated geographic zone.
---------------------------------------------------------------------------

    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

[[Page 26533]]

(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 credit-worthy 
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 
multi-state 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 multi-state 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 Long-Term 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\
---------------------------------------------------------------------------

    \275\ ANOPR, 176 FERC ] 61,024 at P 23.
    \276\ ANOPR, 176 FERC ] 61,024 at P 23. Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \277\ ANOPR, 176 FERC ] 61,024 atId. P 65.
    \278\ ANOPR, 176 FERC ] 61,024 atId. P 66.
    \279\ ANOPR, 176 FERC ] 61,024 at P 66. Id.
---------------------------------------------------------------------------

(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

[[Page 26534]]

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\
---------------------------------------------------------------------------

    \280\ CAISO Comments at 71-72.
    \281\ PJM Comments at 17-18.
    \282\ ISO-NE Comments at 25-26.
    \283\ NYISO Comments at 41; SPP Comments at 9-11.
    \284\ MISO Comments at 75-76.
---------------------------------------------------------------------------

    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 interconnection-related network upgrade should be incorporated into 
its regional transmission plan for purposes of cost allocation 
according to a defined cost allocation method.\287\
---------------------------------------------------------------------------

    \285\ See, 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.
    \286\ Anbaric Comments at 23; Public System Comments at 6-7, 19.
    \287\ Duke Comments at 8-9.
---------------------------------------------------------------------------

    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 interconnection-
related network upgrades and could also help unburden constrained and 
backlogged interconnection queues that are creating barriers to 
entry.\290\
---------------------------------------------------------------------------

    \288\ Enel Comments at 3.
    \289\ Enel 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.
    \290\ AEE Comments at 52-53.
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    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 co-optimization, of the two processes.\293\
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    \291\ Southern 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.
    \293\ EEI Comments at 37; Exelon Comments at 33-34; Policy 
Integrity Comments at 27-28; Indicated PJM TOs Comments at 27.
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(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.
---------------------------------------------------------------------------

    \294\ ANOPR, 176 FERC ] 61,024 at P 23.
---------------------------------------------------------------------------

    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 interconnection-related 
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

[[Page 26535]]

years, the deciding factor has become the interconnection customer's 
``sticker shock'' at its cost responsibility for interconnection-
related network upgrades.\298\
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    \295\ Supra section_Supra Need for Reform: Unjust 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).
    \296\ ACEG Jan. 2021 Interconnection Report at 17.
    \297\ Id. (naming the high cost of interconnection-related 
network upgrades as the fundamental problem that interconnection 
queue reform has failed to address thus far).
    \298\ See ACORE Comments at 12.
---------------------------------------------------------------------------

    163. When interconnection customers withdraw from the 
interconnection queue, the identified interconnection-related 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 interconnection-
related 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.
---------------------------------------------------------------------------

    \299\ ICF Sept. 2021 Report at 25-26.
---------------------------------------------------------------------------

    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.
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    \300\ See, 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.
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(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 
interconnection-related 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

[[Page 26536]]

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 
interconnection-related 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 interconnection-related 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.
---------------------------------------------------------------------------

    \301\ We propose that when an interconnection-related 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.
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    170. We propose that the initial five-year 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 interconnection-related 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 interconnection-related 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 interconnection-related 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 interconnection-related 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

[[Page 26537]]

$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\
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    \302\ Section 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 of $200 million or more.'' CAISO, Tariff, sectionSec.  24.4.6.5 
(LGIP Network Upgrades) (1.0.0).
    \303\ TheAn 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 System-Wide 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-V3a-FINAL.pdf.
---------------------------------------------------------------------------

    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 cost-effective 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 cost-effective 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 Long-Term 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 in-service 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 cost-effective solution to a regional transmission 
need.
---------------------------------------------------------------------------

    \304\ Order No. 1000, 136 FERC ] 61,051 at P 624.
    \305\ Id. PP 624-625.
    \306\ Id. P 622.
---------------------------------------------------------------------------

    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

[[Page 26538]]

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\
---------------------------------------------------------------------------

    \307\ ANOPR, 176 FERC ] 61,024 at P 53.
    \308\ Id. P 70.
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(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 multi-value, 
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\
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    \309\ ACORE 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).
    \310\ City 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.
    \311\ See, 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.
    \312\ PIOs Comments at 30; see also Orsted Comments at 6.
    \313\ See, 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'').
---------------------------------------------------------------------------

    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\
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    \314\ Ameren Comments at 9-11.
    \315\ Consumer Organizations Comments at 18-19; District of 
Columbia's Office of the People's Counsel Comments at 26-27.
    \316\ Consumer Organizations Comments at 18; LPPC Comments at 
20-23.
    \317\ District of Columbia's Office of the People's Counsel 
Comments at 3-4.
    \318\ APPA Comments at 15-16.
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    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\
---------------------------------------------------------------------------

    \319\ MISO 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).
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    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\
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    \321\ NYISO 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).
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    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

[[Page 26539]]

accounting for how the congestion dollars are or are not returned to 
load through the financial transmission rights (or their 
equivalent).\323\
---------------------------------------------------------------------------

    \322\ PJM Market Monitor Comments at 10.
    \323\ Id. at 11.
---------------------------------------------------------------------------

(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 Long-Term 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.
---------------------------------------------------------------------------

    \324\ See Order No. 1000, 136 FERC ] 61,051 at PP 624-625.
    \325\ See id. P 624.
---------------------------------------------------------------------------

    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 Long-Term 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 Long-Term 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          Reduced costs of avoided or
 transmission facilities and aging        delayed transmission
 transmission infrastructure              investment otherwise required
 replacement.                             to address reliability needs
                                          or replace aging transmission
                                          facilities.
Reduced loss of load probability [OR     Reduced frequency of loss of
 next benefit].                           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      While holding loss of load
 prior benefit].                          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 higher-
                                          cost 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   Reduced production costs during
 outages.                                 transmission outages that
                                          significantly increase
                                          transmission congestion.
Mitigation of extreme events and system  Reduced production costs during
 contingencies.                           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           Reduced production costs during
 uncertainty.                             higher than normal load
                                          conditions or significant
                                          shifts in regional weather
                                          patterns.
Capacity cost benefits from reduced      Reduced energy losses during
 peak energy losses.                      peak load reduces generation
                                          capacity investment needed to
                                          meet the peak load and
                                          transmission losses.
Deferred generation capacity             Reduced costs of needed
 investments.                             generation capacity
                                          investments through expanded
                                          import capability into
                                          resource-constrained areas.

[[Page 26540]]

 
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\
---------------------------------------------------------------------------

    \326\ Order No. 1000, 136 FERC ] 61,051 at P 81.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \327\ See, e.g., S.C. Elec. & Gas Co., 143 FERC ] 61,058, at P 
232 (2013).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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

[[Page 26541]]

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\
---------------------------------------------------------------------------

    \329\ SPP Benefit Metrics Manual, SPP Engineering, at 15 (Nov. 
6, 2020).
    \330\ The Brattle Group, Benefit-Cost Analysis of Proposed New 
York AC Transmission Upgrades, The Brattle Group, at 114 (Sept. 15, 
2015).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \331\ SPP, Benefits for the 2013 Regional Cost Allocation 
Review, at 25 (Sept. 13, 2012).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \332\ MISO, Proposed Multi Value Project Portfolio: Business 
Case Workshop, at 36-38 (Sept. 19 & 29, 2011).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \333\ When this calculation is adjusted to account for purchases 
and sales outside the region, we propose to define this as adjusted 
production cost savings.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \334\ See MISO, FERC Electric Tariff, Attach. FF, Benefit 
Metrics Sec.  (I)(A)(1) (33.0.0).
    \335\ See 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, Sec.  31.5 (27.0.0), Sec.  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.
---------------------------------------------------------------------------

    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 lower-cost 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

[[Page 26542]]

allocates the costs of the regional transmission facilities on that 
basis.\336\
---------------------------------------------------------------------------

    \336\ Pub. Serv. Co. of Colo., 142 FERC ] 61,206, at P 314 
(2013).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \337\ PROMOD is a generator and portfolio modeling system. 
https://www.hitachienergy.com/us/en/offering/product-and-system/energy-planning-trading/market-analysis/promod.
    \338\ ATC 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).
    \339\ SPP, Regional Cost Allocation Review (RCAR II), at 5 (July 
11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \340\ Brattle-Grid Strategies Oct. 2021 Report at 79.
    \341\ SPP, 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \342\ Opinion 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 Devers-Palo Verde No. 2 Transmission Line 
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007).
    \343\ ATC, Planning Analysis of the Paddock-Rockdale Project, 
Docket No. 137-CE-149, app. C, Ex. 1, at 4, 50-53 (Wisc. Pub. Serv. 
Comm'n Apr. 5, 2007).
    \344\ M. Goggin, Grid Strategies, LLC, Transmission Makes the 
Power System Resilient to Extreme Weather (July 2020).
---------------------------------------------------------------------------

    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

[[Page 26543]]

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.
---------------------------------------------------------------------------

    \345\ ERCOT, 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \346\ ITC Holdings Co., Joint Application, Docket No. EC12-145-
000, at Ex. ITC-600, 77-78 (Test. of Pfeifenberger) (filed Sept. 24, 
2012).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \347\ Id.
---------------------------------------------------------------------------

    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 resource-
constrained 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\
---------------------------------------------------------------------------

    \348\ Id. at 58-59.
---------------------------------------------------------------------------

    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, low-cost 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 lower-cost, new generation 
in Arizona.\349\
---------------------------------------------------------------------------

    \349\ Opinion 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 Devers-Palo Verde No. 2 Transmission Line 
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007).
---------------------------------------------------------------------------

    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

[[Page 26544]]

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\
---------------------------------------------------------------------------

    \350\ TC 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).
    \351\ Brattle-Grid Strategies Oct. 2021 Report at 46-47.
---------------------------------------------------------------------------

    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 Commission-jurisdictional 
rates.
---------------------------------------------------------------------------

    \352\ F.A. Wolak, Managing Unilateral Market Power in 
Electricity, Policy Research Working Paper; No. 3691. World Bank, 
Washington, DC, at 8 (2005).
---------------------------------------------------------------------------

    220. More specifically, to the extent that certain portions of a 
transmission planning region remain import-constrained, 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 
Paddock-Rockdale 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.
---------------------------------------------------------------------------

    \353\ Opinion 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 Devers-Palo 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).
    \354\ The 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 
Paddock-Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at 
44 & n.11 (Wisc. Pub. Serv. Comm'n Apr. 5, 2007).
---------------------------------------------------------------------------

    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 mark-ups. 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 price-cost markup for hours when the Residual 
Supplier Index is below 1.2 provides the benefits from increased 
competition.
---------------------------------------------------------------------------

    \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).
    \356\ This 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.
---------------------------------------------------------------------------

    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.

[[Page 26545]]

    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.
---------------------------------------------------------------------------

    \358\ See, 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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \359\ Brattle-Grid Strategies Oct. 2021 Report at 50.
    \360\ Id.
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \361\ See, 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).
    \362\ ACPA and ESA Comments at 44-45; see also PIOs Comments at 
121-122.
    \363\ Entergy 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.
---------------------------------------------------------------------------

(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 in-service 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\
---------------------------------------------------------------------------

    \365\ See 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/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf; SPP Engineering, 2021 SPP Transmission 
Expansion Plan Report (Jan. 11, 2021), https://spp.org/documents/56611/2021%20step%20report.pdf.
---------------------------------------------------------------------------

    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 in-service 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--

[[Page 26546]]

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.
---------------------------------------------------------------------------

    \366\ ACPA and ESA Comments at 44-45; see also WIRES Comments at 
7-8 (recommending accounting for benefits of transmission facilities 
over their useful lives).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \367\ ANOPR, 176 FERC ] 61,024 at PP 53, 89, 91.
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \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).
    \369\ U.S. DOE Comments at 40-41.
    \370\ PIOs Comments at 50-51.
    \371\ ACEG Reply Comments at 5, 8; ITC Comments at 6, 11, 28.
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

    \372\ U.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).
    \373\ MISO, Multi Value Project Portfolio Results and Analyses 
at 1-6 (2012), https://cdn.misoenergy.org/2011%20MVP%20Portfolio%20Analysis%20Full%20Report117059.pdf.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \374\ See, 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).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \375\ Order No. 1000, 136 FERC ] 61,051 at PP 328-331; Order No. 
1000-A, 139 FERC ] 61,132 at P 452.
    \376\ Order No. 1000, 136 FERC ] 61,051 at P 331.
    \377\ See Order No. 1000-A, 139 FERC ] 61,132 at P 455.
---------------------------------------------------------------------------

    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

[[Page 26547]]

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\
---------------------------------------------------------------------------

    \378\ ANOPR, 176 FERC ] 61,024 at P 53.
    \379\ See id. PP 89, 91.
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \380\ AEP 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).
    \381\ See 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.'').
    \382\ PJM 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'').
    \383\ MISO Comments at 32; National Grid Comments at 14-15; 
American Municipal Power Comments at 15.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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 vertically-integrated utilities already use a 
portfolio approach).
    \385\ U.S. DOE Comments at 40-41.
---------------------------------------------------------------------------

    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 benefit-cost 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\
---------------------------------------------------------------------------

    \386\ ITC Comments at 11; ACEG Comments at 5-6; Policy Integrity 
Comments at 44-46; AEP Comments at 16.
    \387\ NARUC 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).
    \388\ National 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.
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

    \389\ Order No. 1000, 136 FERC ] 61,051 at P 328.
---------------------------------------------------------------------------

    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 
cost-effectiveness of various regional transmission facilities, whether 
by reference, for example, to a benefit-cost ratio or by aggregate net 
benefits.\390\
---------------------------------------------------------------------------

    \390\ We 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.
---------------------------------------------------------------------------

    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

[[Page 26548]]

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 Long-Term 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.
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    \391\ Supra 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).
    \392\ See, e.g., NASUCA Comments at 3-5; November 2021 Technical 
Conference Tr. at 29 (testimony of Dr. Patton).
---------------------------------------------------------------------------

    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.
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    \393\ For 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.
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    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\
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    \394\ We 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.
    \395\ Order 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).
---------------------------------------------------------------------------

    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

[[Page 26549]]

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 net-beneficial 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\
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    \397\ Brattle-Grid Strategies Oct. 2021 Report at 59-60.
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    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\
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    \398\ As 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.
    \399\ For 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.
    \400\ We 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.
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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

[[Page 26550]]

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\
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    \401\ For 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).
    \402\ ANOPR, 176 FERC ] 61,024 at P 48.
    \403\ Id. P 158.
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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\
---------------------------------------------------------------------------

    \404\ See, 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).
    \405\ NARUC Comments at 9.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \406\ Duke Comments at 13; EEI Comments at 7; MISO TOs Comments 
at 46-47.
    \407\ AEP Comments at 15.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \408\ A 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).
    \409\ PJM Market Monitor Comments at 13.
    \410\ Potomac Economics Comments at 4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \411\ CAISO Comments at 113-114.
    \412\ MISO Comments at 45-46.
    \413\ PJM Comments at 59-60.
    \414\ Id. at 60.
    \415\ SPP Comments at 12.
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    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\
---------------------------------------------------------------------------

    \416\ MISO Comments at 28; PJM Comments at 62-63.
    \417\ PJM Comments at 60-63.
    \418\ MISO Comments at 45-46.
---------------------------------------------------------------------------

    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

[[Page 26551]]

regional transmission planning process where they are cost-
effective.\421\
---------------------------------------------------------------------------

    \419\ Certain TDUs Comments at 22.
    \420\ CTC Global Comments at 6.
    \421\ PIOs Comments at 97.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \422\ TAPS Comments at 2.
    \423\ Id. at 22.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \424\ PJM Comments at 63.
    \425\ WATT Coalition Comments at 4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \426\ EDF Comments at 16-18.
    \427\ WATT Coalition Comments at 5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \428\ Id.
    \429\ Arizona Commission Reply Comments at 12.
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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 cost-effectively. 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\
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    \430\ Order 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.
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    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

[[Page 26552]]

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.
---------------------------------------------------------------------------

    \436\ Grid-Enhancing Technologies, Notice of Workshop, Docket 
No. AD19-19-000 (issued Sept. 9, 2019).
    \437\ Advanced 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://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf.
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    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 cost-effective 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 cost-effective. 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.
---------------------------------------------------------------------------

    \438\ Order No. 1000, 136 FERC ] 61,051 at P 328; Order No. 
1000-A, 139 FERC ] 61,132 at P 267.
---------------------------------------------------------------------------

    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\
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    \439\ For 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.
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    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 cost-effective transmission facility 
selected in the regional transmission plan for purposes of cost 
allocation.\440\
---------------------------------------------------------------------------

    \440\ Cf. 18 CFR 35.25(g)(13)(i) (requiring each RTO/ISO to 
maintain systems and procedures to accept and utilize dynamic line 
ratings data).
---------------------------------------------------------------------------

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

[[Page 26553]]

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\
---------------------------------------------------------------------------

    \441\ 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \442\ Order No. 890, 118 FERC ] 61,119 at PP 557-558.
    \443\ Id. P 559.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \444\ Order 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \449\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 637, 646, 
657, 668, 685.
    \450\ Id. P 624.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \451\ Order No. 1000-A, 139 FERC ] 61,132 at P 680.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \452\ MISO, 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.
---------------------------------------------------------------------------

     Economic: increased market efficiency (congestion and fuel 
savings and operating reserves), deferred generation investment (system 
planning

[[Page 26554]]

reserve margins and transmission line losses), and other capital 
benefits (wind turbine investment and future transmission investment); 
\453\
---------------------------------------------------------------------------

    \453\ MISO, Multi-Value Project Portfolio, Detailed Business 
Case at 27.
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     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\
---------------------------------------------------------------------------

    \454\ Id. at 17-19.
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     Policy: reliably enables the delivery of energy in support 
of policy mandates.\455\
---------------------------------------------------------------------------

    \455\ Id. at 21.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \456\ ANOPR, 176 FERC ] 61,024 at P 84.
    \457\ Id. PP 83-89.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \458\ ANOPR, 176 FERC ] 61,024 atId. P 176.
    \459\ ANOPR, 176 FERC ] 61,024 at P 176Id. (citing SPP, 
Governing Documents Tariff, Bylaws, Section 7.2 (Regional State 
Committee) (1.0.0)).
    \460\ ANOPR, 176 FERC ] 61,024 atId. P 177.
---------------------------------------------------------------------------

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 non-RTO/ISO 
regions.\470\ ACPA and ESA state that a Commission approach to cost 
allocation could include cost contributions from states and 
interconnection customers.\471\
---------------------------------------------------------------------------

    \461\ Members 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).
    \462\ NARUC 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).
    \463\ NARUC Comments at 25-26.
    \464\ NESCOE Comments at 21-25.
    \465\ Id. at 49.
    \466\ NESCOE CommentsId. at 47-48; MISO Comments at 8, 21.
    \467\ Arizona 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).
    \468\ New Jersey Commission Comments at 12-15.
    \469\ Mississippi Commission Comments at 14.
    \470\ Northwest and Intermountain Comments at 28-30.
    \471\ ACPA and ESA Comments at 75.
---------------------------------------------------------------------------

    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

[[Page 26555]]

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\
---------------------------------------------------------------------------

    \472\ District of Columbia's Office of the People's Counsel 
Comments at 4-5.
    \473\ Id. at 5.
    \474\ Arizona Commission Comments at 7; Maryland Energy 
AdministrationAdmin Comments at 2.
    \475\ Maryland Energy AdministrationAdmin Comments at 3.
    \476\ Exelon Comments at 31-32.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \477\ ACORE 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.
    \478\ PIOs Comments at 30; see also Orsted Comments at 6.
    \479\ U.S. DOE Comments at 23.
    \480\ Certain TDUs Comments at 5-6.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \481\ NYISO Reply Comments at 10-11.
    \482\ SPP Comments at 14.
    \483\ CAISO Comments at 85-88; MISO Comments at 85.
    \484\ PJM Comments at 8.
    \485\ CAISO Comments at 85; MISO Comments at 85; NYISO Comments 
at 35-36.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \486\ Minnesota 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.
    \487\ See, 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.
    \488\ See NESCOE Comments at 50.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \489\ Under 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).
    \490\ Exelon Comments at 30-31.
    \491\ Michigan Commission Comments at 20.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \492\ See, 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).
    \493\ AEP Comments at 15.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \494\ See, e.g., ACEG Comments at 6-7; Consumers Council 
Comments at 16-17; WIRES Comments at 18-19; PSEG Comments at 5.
    \495\ APPA Comments at 15-16.

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[[Page 26556]]

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 cost-effective 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\
---------------------------------------------------------------------------

    \496\ Order No. 1000, 136 FERC ] 61,051 at P 496 (discussing 
findings in Order No. 890).
    \497\ Id.
    \498\ See, e.g., Long Island Power Auth. v. FERC, 27 F.4th 705, 
709 (D.C. Cir. 2022) (addressing a ``long-running 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).
    \499\ See, 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).
---------------------------------------------------------------------------

    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 longer-term 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 state-prioritized 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 FERC-jurisdictional 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\
---------------------------------------------------------------------------

    \500\ See 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).
    \501\ State Voluntary Agreements to Plan and Pay for 
Transmission Facilities, 175 FERC ] 61,225 (2021).
    \502\ Id. PP 2, 6.
    \503\ See Joint Fed.-State Task Force on Elec. Transmission, 175 
FERC ] 61,224 at PP 1-2 (establishing the Task Force).
    \504\ Id. P 6.
    \505\ See 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).
---------------------------------------------------------------------------

    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

[[Page 26557]]

needs for which we are proposing to require public utility transmission 
providers to plan in this NOPR.
---------------------------------------------------------------------------

    \506\ E.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).
---------------------------------------------------------------------------

E. Proposed Reform

1. State Involvement in Cost Allocation for Long-Term Regional 
Transmission Facilities \507\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 Long-Term 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\
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    \508\ We 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 Long-Term Regional Transmission Facility would be 
entitled to use the Long-Term Regional Transmission Cost Allocation 
Method if it is the applicable method.
    \509\ We 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.
    \510\ For 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.
    \511\ 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.
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    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 Long-Term 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\
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    \512\ For 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.
    \513\ As discussed infra in Proposed Compliance Procedures, we 
propose to establish an extended compliance period to accommodate 
meaningful engagement with states with respect to this Long-Term 
Regional Transmission Planning cost allocation reform.
---------------------------------------------------------------------------

    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

[[Page 26558]]

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.
---------------------------------------------------------------------------

    \514\ Under this proposed requirement, the Long-Term 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.
---------------------------------------------------------------------------

    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 Long-Term 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 Long-Term Regional Transmission Cost Allocation 
Method.\515\
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    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \516\ As 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.
---------------------------------------------------------------------------

    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 Long-Term 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 Long-
Term Regional Transmission Facilities an opportunity to do so. Where 
relevant state entities in a multi-state

[[Page 26559]]

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.
---------------------------------------------------------------------------

    \517\ The 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.
---------------------------------------------------------------------------

    315. We recognize that, if states agree to a State Agreement 
Process instead of a Long-Term Regional Transmission Cost Allocation 
Method, certain Long-Term 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.
---------------------------------------------------------------------------

    \518\ Id. P 499; Order No. 1000-A, 139 FERC ] 61,132 at P 52.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \519\ Order 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.
---------------------------------------------------------------------------

    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 Long-Term 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.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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 state-
negotiated 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.

[[Page 26560]]

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 state-proposed 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 
state-negotiated 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\
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    \521\ Public Law 109-58, 1241, 119 Stat. 594 (2005).
    \522\ Promoting 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).
---------------------------------------------------------------------------

    329. In Order No. 679, the Commission adopted several incentive-
based 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

[[Page 26561]]

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\
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    \523\ Id. P 9.
    \524\ The 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).
    \525\ Order No. 679, 116 FERC ] 61,057 at n.70.
    \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)).
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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 over-
investment 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.
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    \528\ See, e.g., NextEra Energy Transmission Sw., LLC, 178 FERC 
] 61,082 (2022) (Christie, Comm'r, concurring).
    \529\ Order No. 679, 116 FERC ] 61,057 at P 115.
---------------------------------------------------------------------------

    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 Long-Term 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\
---------------------------------------------------------------------------

    \530\ We 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.
---------------------------------------------------------------------------

    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 Commission-jurisdictional rates and limit opportunities 
for undue discrimination by public utility transmission providers.
---------------------------------------------------------------------------

    \531\ See 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.
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    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\
---------------------------------------------------------------------------

    \532\ Order No. 1000, 136 FERC ] 61,051 at P 225.
---------------------------------------------------------------------------

    338. Among its nonincumbent transmission developer reforms, Order 
No. 1000 requires that each public

[[Page 26562]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \534\ Order 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.
    \535\ Order 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.
    \536\ Order No. 1000, 136 FERC ] 61,051 at PP 226, 319.
    \537\ See, 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).
---------------------------------------------------------------------------

    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 Commission-jurisdictional 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\
---------------------------------------------------------------------------

    \538\ Order 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \541\ Order 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.
    \542\ See 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.
---------------------------------------------------------------------------

    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

[[Page 26563]]

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.
---------------------------------------------------------------------------

    \544\ See 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.
    \545\ See supra note 537 and associated text.
    \546\ See, 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 incumbent 
transmission providers should be able to maintain an existing 
federal right of first refusal for certain types of new transmission 
projects'').
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \547\ See FERC, Staff Report, 2017 Transmission Metrics, at 8 
(Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-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).
    \548\ See 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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \549\ See 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).
    \550\ See 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'').
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \551\ ANOPR, 176 FERC ] 61,024 at P 37.
    \552\ Id.
    \553\ Id.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \554\ E.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'').
---------------------------------------------------------------------------

    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

[[Page 26564]]

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\
---------------------------------------------------------------------------

    \555\ Competition 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.
    \556\ LS 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)).
    \557\ NARUC 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'').
    \558\ PIOs Reply Comments at 13.
    \559\ PJM 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.
    \560\ Chairman of the Kentucky Commission Kent A. Chandler Reply 
Comments at 3-4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \561\ See 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'').
    \562\ EEI 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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \565\ See supra note 550 and associated text.
    \566\ See, 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/wp-content/uploads/2021/05/18939_offshore_transmission_in_new_england_-the_benefits_of_a_better-planned_grid_brattle.pdf (Brattle Offshore 
Transmission Study).
    \567\ See, 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-project-statistics.ashx.
    \568\ See, e.g., Brattle Apr. 2019 Competition Report at 19 fig. 
6.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \569\ See Order No. 1000, 136 FERC ] 61,051 at PP 2-3, 46.
    \570\ See, e.g., id. (Moeller, Comm'r, dissenting in part).
---------------------------------------------------------------------------

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,

[[Page 26565]]

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\
---------------------------------------------------------------------------

    \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.'').
    \572\ See Order No. 1000, 136 FERC ] 61,051 at PP 5, 7, 226.
---------------------------------------------------------------------------

    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 cost-effective 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.
---------------------------------------------------------------------------

    \573\ See supra notes 538 to 541 and associated text.
---------------------------------------------------------------------------

    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 Commission-
jurisdictional 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

[[Page 26566]]

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\
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    \574\ The 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.
    \575\ The 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.
    \576\ The 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.
    \577\ The 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.
    \578\ See, 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).
---------------------------------------------------------------------------

    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\
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    \579\ See 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, Sec.  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'').
---------------------------------------------------------------------------

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 joint-ownership 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.
---------------------------------------------------------------------------

    \581\ See supra P 337.
    \582\ See infra PP 365, 371.
---------------------------------------------------------------------------

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\
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    \583\ Order No. 1000, 136 FERC ] 61,051 at P 776.
    \584\ Id. (citing Order No. 890, 118 FERC ] 61,119 at P 593).
    \585\ See, e.g., CAISO, CASIO eTariff, Sec.  24.5.2 (Project 
Sponsor Application and Information Requirements) (6.0.0), Sec.  
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), Sec.  VIII.D.4.2. (Joint-Developer 
Proposal); PJM, Intra-PJM Tariffs, OA Schedule 6, Sec.  1.5 
(Procedure for the Development of the Regional Transmission 
Expansion Plan) (28.0.0), Sec.  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.'').
---------------------------------------------------------------------------

b. Comments
    360. Although the Commission did not specifically ask about 
jointly-owned

[[Page 26567]]

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-Pe[ntilde]asquitos projects.\587\
---------------------------------------------------------------------------

    \586\ See ANOPR, 176 FERC ] 61,024 at P 37.
    \587\ SDG&E Comments at 4-5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \588\ TAPS Comments at 8 (citing TAPS 2021 White Paper (June 25, 
2021), https://www.tapsgroup.org/wp-content/uploads/2021/09/TAPS-Inclusive-Joint-Ownership-White-Paper.pdf (TAPS 2021 White Paper)).
    \589\ Id. at 9-11.
    \590\ Id. at 8-9 & nn.9-11.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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)).
    \592\ TAPS Comments at 13-15, 52-53.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \593\ Id. at 13-15.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \594\ Id. at 12, 14-15, 52-53.
---------------------------------------------------------------------------

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 municipally-owned 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.
---------------------------------------------------------------------------

    \595\ See supra P 337.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \596\ See FERC, Staff Report, 2017 Transmission Metrics, at 8 
(Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf (describing the two general 
types of competitive transmission development processes).
---------------------------------------------------------------------------

    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 jointly-owned regional transmission facility

[[Page 26568]]

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 Commission-jurisdictional 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 already-selected 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 
joint-ownership 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\
---------------------------------------------------------------------------

    \597\ See, 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).
---------------------------------------------------------------------------

    372. We believe that a conditional federal right of first refusal 
for jointly-owned 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 load-serving entities and potentially those that are 
public power entities, may increase collaboration within the regional 
transmission planning process consistent with Order No. 679.\599\
---------------------------------------------------------------------------

    \598\ See Order No. 1000, 136 FERC ] 61,051 at P 776; see also 
Order No. 890, 118 FERC ] 61,119 at PP 593-594.
    \599\ See Promoting Transmission Inv. through Pricing Reform, 
Order No. 679, 71 FR 43294 (July 31, 2006), 116 FERC ] 61,057, at PP 
354, 355 (2006).
---------------------------------------------------------------------------

    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

[[Page 26569]]

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-Pe[ntilde]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 
Commission-jurisdictional rates.
---------------------------------------------------------------------------

    \600\ See SDG&E Comments at 4-5; see also California State Water 
Project Reply Comments at 12 n.44 (discussing the Sycamore-
Pe[ntilde]asquitos Project (citations omitted)); Citizens Sycamore-
Penasquitos 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).
---------------------------------------------------------------------------

    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 near-term 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 cost-effective 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\
---------------------------------------------------------------------------

    \601\ See supra notes 538 to 541 and associated text.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \602\ See 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'').
---------------------------------------------------------------------------

    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 Commission-jurisdictional rates and limits opportunities for 
undue discrimination by public utility transmission providers.
---------------------------------------------------------------------------

    \603\ See supra notes 538 to 543 and associated text.
---------------------------------------------------------------------------

    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 joint-ownership 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\
---------------------------------------------------------------------------

    \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.
    \605\ See TAPS Comments at 14-15.
---------------------------------------------------------------------------

    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

[[Page 26570]]

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\
---------------------------------------------------------------------------

    \606\ For 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), Sec.  VIII.D.4.2. (Joint-Developer Proposal); id. Sec.  
VIII.D.5.1.1. (Identification of RFP Respondents).
    \607\ For example, we note that SDG&E's Sycamore-
Pe[ntilde]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-Pe[ntilde]asquitos Project. See Citizens Sycamore-
Penasquitos Transmission LLC, 164 FERC ] 61,149 at P 7.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \608\ Supra P 17.
    \609\ Order No. 1000-A, 139 FERC ] 61,132 at P 190.
---------------------------------------------------------------------------

    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 cost-effectively 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

[[Page 26571]]

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\
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    \610\ For 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).
    \611\ See 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.
    \612\ See, 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.'').
    \613\ See PJM Interconnection, L.L.C., 172 FERC ] 61,136 at 21.
    \614\ Supra Table 1--Long-Term Regional Transmission Benefits.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \615\ Order 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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \617\ ANOPR, 176 FERC ] 61,024 at P 171.
---------------------------------------------------------------------------

    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\
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    \618\ ANOPR, 176 FERC ] 61,024 at P 37.
---------------------------------------------------------------------------

    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 well-publicized 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.
---------------------------------------------------------------------------

    \619\ Id. P 162.
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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\
---------------------------------------------------------------------------

    \620\ ACORE 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \621\ E.g., District of Columbia's Office of the People's 
Counsel Comments at 11-12; EDF Comments at 12.
    \622\ California Commission Comments at 17-18.
    \623\ NARUC Comments at 15, 48-29.
    \624\ New Jersey Commission Comments at 12-13.
---------------------------------------------------------------------------

    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\
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    \625\ ACEG Jan. 2021 Planning Report at 18-24.
    \626\ Eversource Comments at 10.
    \627\ LS Power Oct. 12 Comments at 43-44.
    \628\ PIOs Comments at 50 (citing Brattle-Grid Strategies Oct. 
2021 Report at 3).
---------------------------------------------------------------------------

    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

[[Page 26572]]

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\
---------------------------------------------------------------------------

    \629\ ACEG 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.
    \630\ California Commission Comments at 39-43; Competition 
Coalition Comments at 16; LS Power Oct. 12 Comments at 49-53.
    \631\ See e.g., Union of Concerned Scientists Comments at 24-31; 
see also Environmental Advocates Comments at 22; Northwest and 
Intermountain Comments at 49.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \632\ PJM Market Monitor Comments at 9.
    \633\ American 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.
---------------------------------------------------------------------------

    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 non-RTO/ISO regions.\634\
---------------------------------------------------------------------------

    \634\ AEP 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.
---------------------------------------------------------------------------

    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\
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    \635\ CAISO Comments at 55-56.
    \636\ MISO TOs Comments at 21-22.
    \637\ PJM TOs Comments at 13-14.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \638\ Alabama 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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \639\ See 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'').
    \640\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
    \641\ Id. P 454.
    \642\ See, e.g., Monongahela Power Co., 156 FERC ] 61,134 
(2016).
    \643\ NARUC 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'').
    \644\ See supra P 40; note 63.
---------------------------------------------------------------------------

    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 cost-effectively address regional transmission needs, 
and, more generally, that public utility transmission providers 
developing

[[Page 26573]]

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 ``right-sizing'' 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 in-kind 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 in-kind replacement transmission 
facilities and may result in the development of duplicative or 
unnecessary transmission facilities that increase costs to consumers 
and render Commission-jurisdictional rates unjust and unreasonable.
---------------------------------------------------------------------------

    \645\ For 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-of-the-pjm-transmission-system.pdf.https://www.pjm.com/-/media/library/reports-notices/special-reports/2019/the-benefits-of-the-pjm-transmission-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.
    \646\ S. 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.
---------------------------------------------------------------------------

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 
Commission-jurisdictional 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\
---------------------------------------------------------------------------

    \647\ Order No. 890, 118 FERC ] 61,119 at P 471.
---------------------------------------------------------------------------

    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

[[Page 26574]]

identified in Long-Term Regional Transmission Planning. By ``right-
sizing'' 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. Right-sizing 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\
---------------------------------------------------------------------------

    \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-transmission-corridors-to-accelerate-low-cost-decarbonization.pdf.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \649\ We 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.
---------------------------------------------------------------------------

    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 in-kind replacement estimates can be right-sized 
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 
right-sizing 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 right-sized 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\
---------------------------------------------------------------------------

    \650\ We note that benefits associated with right-sizing 
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.
---------------------------------------------------------------------------

    407. The process under this proposed reform would entail the 
following steps. First, sufficiently early in each Long-Term Regional 
Transmission Planning cycle, each public utility transmission provider 
would submit its in-kind replacement estimates for use in Long-Term 
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 cost-effective solution to a 
transmission need identified through Long-Term Regional Transmission 
Planning, then the right-sized replacement transmission facility may be 
selected in the regional transmission plan for purposes of cost 
allocation.\651\
---------------------------------------------------------------------------

    \651\ See supra Regional Transmission Planning: Proposed 
Reforms, Selection of Regional Transmission Facilities.
---------------------------------------------------------------------------

    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 right-
sizing, 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.
---------------------------------------------------------------------------

    \652\ Similarly, nothing in this proposed rule would alter 
existing law concerning subsequent proceedings involving an in-kind 
asset replacement, e.g., state-law siting proceedings.

---------------------------------------------------------------------------

[[Page 26575]]

    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.
---------------------------------------------------------------------------

    \653\ See, e.g., PJM, Intra-PJM Tariffs, OATT, attach. M-3, OATT 
Attachment M-3 (1.0.0), Sec.  (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'').
---------------------------------------------------------------------------

    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 right-sizing 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 Long-
Term 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 Long-Term 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 right-
sized.
    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.
---------------------------------------------------------------------------

    \654\ Order No. 1000, 136 FERC ] 61,051 at P 262; Order No. 
1000-A, 139 FERC ] 61,132 at PP 366, 379, 425, 428.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \655\ See supra P 412.
---------------------------------------------------------------------------

    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 cost-effective 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

[[Page 26576]]

replacement transmission facilities so as to reduce after-the-fact 
disputes regarding transmission system needs or cost allocation.
---------------------------------------------------------------------------

    \656\ See supra Regional Transmission Planning: Proposed 
Reforms, Selection of Regional Transmission Facilities.
---------------------------------------------------------------------------

    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 
right-sizing 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \659\ Id. P 436.
    \660\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \661\ Id. P 437; Order No. 1000-A, 139 FERC ] 61,132 at PP 506, 
510.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \662\ Order No. 1000, 136 FERC ] 61,051 at P 400; Order No. 
1000-A, 139 FERC ] 61,132 at P 509.
    \663\ Order No. 1000, 136 FERC ] 61,051 at PP 443, 635.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \664\ Id. P 578.
    \665\ Id. P 603.
---------------------------------------------------------------------------

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 state-
regional 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

[[Page 26577]]

whether the Commission should establish interregional reliability 
planning criteria.\668\
---------------------------------------------------------------------------

    \666\ ANOPR, 176 FERC ] 61,024 at PP 57, 62-64.
    \667\ Id. P 64.
    \668\ Id. PP 62-63.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \669\ See, 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.
    \670\ See, 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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \671\ Order No. 1000, 136 FERC ] 61,051 at P 369.
    \672\ Id. P 368.
    \673\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \674\ As 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \675\ See 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).
---------------------------------------------------------------------------

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

[[Page 26578]]

this NOPR and are included in any final rule in this proceeding.\676\
---------------------------------------------------------------------------

    \676\ See Appendix B for the proposed pro forma Attachment K 
consistent with this NOPR.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \677\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \678\ 44 U.S.C. 3507(d).
    \679\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    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 Commission-jurisdictional 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 ([email protected]) 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 Commission-jurisdictional 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\
---------------------------------------------------------------------------

    \680\ The 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.
    \681\ The 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.
---------------------------------------------------------------------------

    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:
---------------------------------------------------------------------------

    \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.

[[Page 26579]]



                            Proposed Changes in NOPR in Docket No. RM21-17-000 \683\
----------------------------------------------------------------------------------------------------------------
                                                                                               Total estimated
                                                         Total annual      Average burden       burden hours &
       Area of modification          Annual number of      estimated    hours  & cost \684\    total estimated
                                       respondents         number of        per response       cost (column C x
                                                           responses                              column D)
A                                  B..................               C  D..................  E
----------------------------------------------------------------------------------------------------------------
                                   FERC-917, Electric Transmission Facilities
                                           (OMB Control No. 1902-0233)
----------------------------------------------------------------------------------------------------------------
Participate in Long-Term Regional  125 (TSPs and TOs).             125  Year 1: 150 hours;   Year 1: 18,750
 Transmission Planning, which                                            $11,275.             hours; $1,409,363.
 includes developing Long-Term                                          Subsequent Years:    Subsequent Years:
 Scenarios, evaluating the                                               50 hours per year;   6,250 hours per
 benefits of regional                                                    $3,758 per year.     year; $469,788 per
 transmission facilities, and                                                                 year.
 establishing criteria in
 consultation with states to
 select transmission facilities
 in the regional transmission
 plan for purposes of cost
 allocation.
Revise the regional transmission   125 (TSPs and TOs).             125  Year 1: 20 hours;    Year 1: 2,500
 planning process to enhance                                             $1,208.              hours; $151,038.
 transparency of local                                                  Subsequent Years:    Subsequent Years:
 transmission planning and                                               50 hours per year;   6,250 hours per
 identifying potential                                                   $3,758 per year.     year; $469,788 per
 opportunities to right-size                                                                  year.
 replacement transmission
 facilities.
Seek agreement from the states to  125 (TSPs and TOs).             125  Year 1: 150 hours;   Year 1: 18,750
 establish a Long-Term Regional                                          $11,275.             hours; $1,409,363.
 Transmission Cost Allocation                                           Subsequent Years:    Subsequent Years:
 Method and/or a State Agreement                                         50 hours per year;   6,250 hours per
 Process.                                                                $3,758 per year.     year; $469,788 per
                                                                                              year.
Consider in the regional           125 (TSPs and TOs).             125  Year 1: 50 hours;    Year 1: 6,250
 transmission planning processes                                         $3,758.              hours; $469,750.
 regional transmission facilities                                       Subsequent Years: 0  Subsequent Years: 0
 that address certain                                                    hours per year; $0   hours per year; $0
 interconnection-related needs.                                          per year.            per year.
Revise interregional transmission  125 (TSPs and TOs).             125  Year 1: 50 hours;    Year 1: 6,250
 coordination procedures to                                              $3,758.              hours; $469,750.
 reflect Long-Term Regional                                             Subsequent Years:    Subsequent Years:
 Transmission Planning.                                                  25 hours per year;   3,125 hours per
                                                                         $1,715 per year.     year; $214,375 per
                                                                                              year.
----------------------------------------------------------------------------------------------------------------
                              FERC-516, Electric Rate Schedules and Tariff Filings
                                           (OMB Control No. 1902-0096)
----------------------------------------------------------------------------------------------------------------
Revise LGIP to indicate the        125 (TSPs and TOs).             125  Year 1: 30 hours;    Year 1: 3,750
 consideration in the regional                                           $2,058.              hours; $257,288.
 transmission planning processes                                        Subsequent Years: 0  Subsequent Years: 0
 of regional transmission                                                hours per year; $0   hours per year; $0
 facilities that address certain                                         per year.            per year.
 interconnection-related needs.
----------------------------------------------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
    \684\ The 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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \685\ Reguls. 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).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \687\ 5 U.S.C. 601-612.
    \688\ 13 CFR 121.201.
    \689\ The 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.
---------------------------------------------------------------------------

    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.

[[Page 26580]]

    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.
---------------------------------------------------------------------------

    \690\ U.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.
---------------------------------------------------------------------------

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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].
    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.

[[Page 26581]]

 
BP...........................  BP America Inc.
Bridgelink...................  Bridgelink Investments, LLC.
Business Council for           Business Council for Sustainable Energy.
 Sustainable Energy.
CAISO........................  California Independent System Operator
                                Corporation.
California Commission........  California Public Utilities Commission.
California Municipal           California Municipal Utilities
 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          Electricity Consumers Resource Council.
 Resource Council.
CTC Global...................  CTC Global Corporation.
District of Columbia's Office  Office of the People's Counsel for the
 of the People's Counsel.       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         Massachusetts Attorney General Maura
 General.                       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.

[[Page 26582]]

 
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      North Carolina Utilities Commission
 Staff.                         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         Transmission Dependent Utility Systems.
 Utilities.
Union of Concerned Scientists  Union of Concerned Scientists.
US Chamber of Commerce.......  US Chamber of Commerce.
U.S. DOE.....................  United States Department of Energy.

[[Page 26583]]

 
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 Commission-jurisdictional 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, 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. 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 cost-
effectively 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 Long-Term 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

[[Page 26584]]

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 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          Reduced costs of avoided or
 transmission facilities and aging        delayed transmission
 transmission infrastructure              investment otherwise required
 replacement.                             to address reliability needs
                                          or replace aging transmission
                                          facilities.
Reduced loss of load probability [OR     Reduced frequency of loss of
 next benefit].                           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      While holding loss of load
 prior benefit].                          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 higher-
                                          cost 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   Reduced production costs during
 outages.                                 transmission outages that
                                          significantly increase
                                          transmission congestion.
Mitigation of extreme events and system  Reduced production costs during
 contingencies.                           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           Reduced production costs during
 uncertainty.                             higher than normal load
                                          conditions or significant
                                          shifts in regional weather
                                          patterns.
Capacity cost benefits from reduced      Reduced energy losses during
 peak energy losses.                      peak load reduces generation
                                          capacity investment needed to
                                          meet the peak load and
                                          transmission losses.
Deferred generation capacity             Reduced costs of needed
 investments.                             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

[[Page 26585]]

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 Right-Size 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 cost-effectively 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].

[[Page 26586]]

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 cost-effectively 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 cost-effective transmission solutions to transmission 
needs identified through Long-Term 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

[[Page 26587]]

    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 Re-Studies 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

[[Page 26588]]

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

[[Page 26589]]

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 non-interruptible 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

[[Page 26590]]

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 password-protected 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

[[Page 26591]]

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 steady-state 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.

[[Page 26592]]

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.

[[Page 26593]]

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 Long-Term 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.

[[Page 26594]]

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

[[Page 26595]]

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 re-studied.

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

[[Page 26596]]

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

[[Page 26597]]

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

[[Page 26598]]

form of Transmission Provider's FERC-approved 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

[[Page 26599]]

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 
non-confidential 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,

[[Page 26600]]

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 Non-binding 
Dispute Resolution pursuant to this section by providing written 
notice to Transmission Provider (``Request for Non-binding Dispute 
Resolution''). Conversely, either Party may file a Request for Non-
binding Dispute Resolution pursuant to this section without first 
seeking mutual

[[Page 26601]]

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 decision-maker 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):

__ A proposed new Large Generating Facility.
__ An increase in the generating capacity or a Material Modification 
of an existing Generating Facility.

    3. The type of interconnection service requested (check one):

__ Energy Resource Interconnection Service
__ Network Resource Interconnection Service

    4. __ 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 __ degrees C and winter at __ 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)

__ Is attached to this Interconnection Request
__ 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:
-----------------------------------------------------------------------
By (signature):--------------------------------------------------------
Name (type or print):--------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

Attachment A to Appendix 1 Interconnection Request

Large Generating Facility Data Unit Ratings

kVA ___ [deg]F ___ Voltage ___
Power Factor ___
Speed (RPM) ___ Connection (e.g., Wye) ___
Short Circuit Ratio ___ Frequency, Hertz ___
Stator Amperes at Rated kVA ___ Field Volts ___
Max Turbine MW ___ [deg]F ___

    Primary frequency response operating range for electric storage 
resources:

Minimum State of Charge: ___-------------------------------------------
Maximum State of Charge: ___-------------------------------------------

Combined Turbine-Generator-Exciter Inertia Data

Inertia Constant, H = ___ kW sec/kVA
Moment-of-Inertia, WR\2\ = ___ lb. ft.\2\

Reactance Data (Per Unit-Rated KVA)

------------------------------------------------------------------------
                                      Direct axis      Quadrature  axis
------------------------------------------------------------------------
Synchronous--saturated..........  Xdv ___             Xqv ___
Synchronous--unsaturated........  Xdi ___             Xqi ___
Transient--saturated............  X'dv ___            X'qv ___
Transient--unsaturated..........  X'di ___            X'qi ___
Subtransient--saturated.........  X''dv ___           X''qv ___
Subtransient--unsaturated.......  X''di ___           X''qi ___
Negative Sequence--saturated....  X2v ___
Negative Sequence--unsaturated..  X2i ___
Zero Sequence--saturated........  X0v ___
Zero Sequence--unsaturated......  X0i ___
Leakage Reactance...............  Xlm ___
------------------------------------------------------------------------


[[Page 26602]]

Field Time Constant Data (SEC)

 
 
 
Open Circuit................  T'do ___              T'qo ___
Three-Phase Short Circuit     T'd3 ___              T'q ___
 Transient.
Line to Line Short Circuit    T'd2 ___
 Transient.
Line to Neutral Short         T'd1 ___
 Circuit Transient.
Short Circuit Subtransient..  T''d ___              T''q ___
Open Circuit Subtransient...  T''do ___             T''qo ___
 

Armature Time Constant Data (SEC)

    Three Phase Short Circuit--Ta3 ___
    Line to Line Short Circuit--Ta2 ___
    Line to Neutral Short Circuit--Ta1 ___

    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 ___
    Negative--R2 ___
    Zero--R0 ___
    Rotor Short Time Thermal Capacity I2\2\t = ___
    Field Current at Rated kVA, Armature Voltage and PF = ___ amps
    Field Current at Rated kVA and Armature Voltage, 0 PF = ___ amps
    Three Phase Armature Winding Capacitance = ___ microfarad
    Field Winding Resistance = ___ ohms ___ [deg]C
    Armature Winding Resistance (Per Phase) = ___ ohms ___ [deg]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
___/___ kVA
Voltage Ratio (Generator Side/System side/Tertiary)
___/___/___ kV
Winding Connections (Low V/High V/Tertiary V (Delta or Wye))
___/___/___
Fixed Taps Available ___-----------------------------------------------
Present Tap Setting ___------------------------------------------------

Impedance

    Positive; Z1 (on self-cooled kVA rating) ___ % ___ X/
R
    Zero; Z0 (on self-cooled kVA rating) ___ % ___ 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: ______
Elevation: _____-------------------------------------------------------
______
Single Phase-----------------------------------------------------------
______ Three Phase
    Inverter manufacturer, model name, number, and version:
______-----------------------------------------------------------------
    List of adjustable setpoints for the protective equipment or 
software:
 ______----------------------------------------------------------------

    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:-------------------------------------------------------
(*) Field Amperes:-----------------------------------------------------
(*) Motoring Power (kW):-----------------------------------------------
(*) Neutral Grounding Resistor (If Applicable):------------------------
(*) I2\2\t or K (Heating Time Constant):--------------------
(*) Rotor Resistance:--------------------------------------------------
(*) Stator Resistance:-------------------------------------------------
(*) Stator Reactance:--------------------------------------------------
(*) Rotor Reactance:---------------------------------------------------
(*) Magnetizing Reactance:---------------------------------------------
(*) Short Circuit Reactance:-------------------------------------------
(*) Exciting Current:--------------------------------------------------
(*) Temperature Rise:--------------------------------------------------
(*) Frame Size:--------------------------------------------------------
(*) Design Letter:-----------------------------------------------------
(*) Reactive Power Required In Vars (No Load):-------------------------
(*) Reactive Power Required In Vars (Full Load):-----------------------
(*) Total Rotating Inertia, H: ______ Per Unit on KVA Base-------------

    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 __ day of ______, 
20 __ by and between ______, a ______ organized and existing under 
the laws of the State of ______, (``Interconnection Customer,'') and 
______ a ______ existing under the laws of the State of ______, 
(``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 ______; 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:


[[Page 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:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

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 ______:
    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 __ day of ______, 
20__ by and between ______, a ______ organized and existing under 
the laws of the State of ______, (``Interconnection Customer,'') and 
______ a ______ existing under the laws of the State of ______, 
(``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 ______; 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:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

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

[[Page 26604]]

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 __ of ______, 
20__ by and between ______, a ______ organized and existing under 
the laws of the State of ______, (``Interconnection Customer,'') and 
______ a ______ existing under the laws of the State of ______, 
(``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 ______; 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:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

[Insert name of Interconnection Customer]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

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 one-line 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? __Yes __No
    Will a transfer bus on the generation side of the metering 
require that each meter set be designed for the total plant 
generation? __Yes __No (Please indicate on one line diagram).
    What type of control system or PLC will be located at 
Interconnection Customer's Large Generating Facility?
-----------------------------------------------------------------------

    What protocol does the control system or PLC use?
-----------------------------------------------------------------------

    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:
-----------------------------------------------------------------------

    Bus length from generation to interconnection station:
-----------------------------------------------------------------------

    Line length from interconnection station to Transmission 
Provider's transmission line.
-----------------------------------------------------------------------

    Tower number observed in the field. (Painted on tower leg) *
-----------------------------------------------------------------------

    Number of third party easements required for transmission lines 
*:
-----------------------------------------------------------------------

    * To be completed in coordination with Transmission Provider.
    Is the Large Generating Facility in the Transmission Provider's 
service area? __Yes __No
    Local provider:
-----------------------------------------------------------------------

    Please provide proposed schedule dates:
Begin Construction:
Date:------------------------------------------------------------------
Generator step-up transformer receives back feed power
Generation Testing-----------------------------------------------------
Date:------------------------------------------------------------------
Commercial Operation
Date:------------------------------------------------------------------

[[Page 26605]]

Appendix 5 to LGIP--Optional Interconnection Study Agreement

    This Agreement is made and entered into this __ day of ______, 
20__ by and between ______, a ______ organized and existing under 
the laws of the State of ______, (``Interconnection Customer,'') and 
______ a ______ existing under the laws of the State of ______, 
(``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 ______;
    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:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

[Insert name of Interconnection Customer]

By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \1\ See, e.g., New England Power Pool Participants Committee 
October 12, 2021 Comments at 4-8 (detailing past and current 
transmission planning activities).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \2\ Building 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'').
    \3\ The 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).
    \4\ See 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.''
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \5\ See Certification of New Interstate Nat. Gas Facilities, 178 
FERC ] 61,107, order dismissing reh'g requests, Certification of New 
Interstate Nat. Gas Facilities, 179 FERC ] 61,012 (2022); see also 
Certification of New Interstate Nat. Gas Facilities, 178 FERC ] 
61,197 (2022).

---------------------------------------------------------------------------

[[Page 26606]]

    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.
---------------------------------------------------------------------------

    \6\ NOPR, 179 FERC ] 61,028 at PP 104, 106.
---------------------------------------------------------------------------

    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\ Arizona Public Service Company October 12, 2021 Comments at 
4.
---------------------------------------------------------------------------

    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, low-frequency 
events'' but we do ``allow'' utilities ``to determine which . . . 
high-impact, low-frequency 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\ NOPR, 179 FERC ] 61,028 at P 123.
    \9\ Id. P 124 (emphasis added).
---------------------------------------------------------------------------

    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, non-discriminatory 
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 near-term 
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?
---------------------------------------------------------------------------

    \10\ Id. P 274.
    \11\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110 
(2022).
    \12\ NOPR, 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \17\ Id. P 310.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \18\ See State Renewable Portfolio Standards & Goals, National 
Conference of State Legislatures (Aug. 13, 2021), https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
    \19\ See id.
---------------------------------------------------------------------------

    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:
---------------------------------------------------------------------------

    \20\ Utah Public Service Commission October 8, 2021 Comments at 
2 (citing ANOPR, 176 FERC ] 61,024 at P 40).

[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\
---------------------------------------------------------------------------

    \21\ Id. at 2-3.

    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:


[[Page 26607]]


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\
---------------------------------------------------------------------------

    \22\ Louisiana Public Service Commission October 12, 2021 
Comments at 2-3.

    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.
---------------------------------------------------------------------------

    \23\ See, 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.
---------------------------------------------------------------------------

    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-fits-all 
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\
---------------------------------------------------------------------------

    \24\ Sponsors of the Southeastern Regional Transmission Planning 
Process October 12, 2021 Comments at 2.

    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\
---------------------------------------------------------------------------

    \25\ See id. at 11.
    \26\ See id. at 12-14 (detailing renewable integration in the 
southeast on a state-by-state basis).
    \27\ See, 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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \28\ New England Power Pool Participants Committee October 12, 
2021 Comments at 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \29\ Chamber of Commerce of the United States of America October 
12, 2021 Comments at 1.

    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.
---------------------------------------------------------------------------

    \30\ Large Public Power Council October 12, 2021 Comments at 5 
(emphasis added).
---------------------------------------------------------------------------

    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

[[Page 26608]]

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\
---------------------------------------------------------------------------

    \31\ New England Power Pool Participants Committee October 12, 
2021 Comments at 7.
    \32\ See NOPR, 179 FERC ] 61,028 at PP 183, 355.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \33\ See, e.g., Sierra Club v. Costle, 657 F.2d 298, 352 (D.C. 
Cir. 1981).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \34\ See Modernizing Wholesale Elec. Mkt. Design, 179 FERC ] 
61,029 at P 1 (2022).
---------------------------------------------------------------------------

    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.

-----------------------------------------------------------------------
James P. Danly,
-----------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824(b)(1).
    \2\ Id. Sec.  824(a).
    \3\ Id. Sec.  824(b)(1).
    \4\ Transmission 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \5\ 16 U.S.C. 824e(a).
    \6\ Id. Sec.  824o.
---------------------------------------------------------------------------

    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,

[[Page 26609]]

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.
---------------------------------------------------------------------------

    \7\ States 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).
---------------------------------------------------------------------------

    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:
---------------------------------------------------------------------------

    \8\ Building 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).

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:
---------------------------------------------------------------------------

    \9\ For 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \10\ NOPR, 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \12\ NOPR, 179 FERC ] 61,028 at P 4 & n.6; see also id. n.507.
    \13\ Order No. 1000 described these types of projects as those 
that address ``transmission needs driven by Public Policy 
Requirements.''
---------------------------------------------------------------------------

    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.
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    \14\ NOPR, 179 FERC ] 61,028 at PP 302-303, 305.
    \15\ Id. PP 305, 307.
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    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\
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    \16\ See, e.g., id. PP 302, 312.
    \17\ Id.
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    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

[[Page 26610]]

important roles proposed in this NOPR, without preempting the 
regional planning entities from seeking additional input through 
their existing stakeholder processes.
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    \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 transmission-owning utilities to join.
    \19\ See, e.g., Google, A Policy Roadmap for 24/7 Carbon-Free 
Energy (Apr. 14, 2022), https://cloud.google.com/blog/topics/sustainability/a-policy-roadmap-for-achieving-247-carbon-free-energy; see also BlackRock, Inc., 179 FERC ] 61,049 (2022) 
(Christie, Comm'r, concurring).
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    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.
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    \20\ NOPR, 179 FERC ] 61,028 at P 333 & n.530.
    \21\ See 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.'').
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    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.
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    \22\ NOPR, 179 FERC ] 61,028 at PP 383-415.
    \23\ See, 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.'').
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    For these reasons cited above, I concur in the issuance of the 
NOPR.

-----------------------------------------------------------------------
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.
---------------------------------------------------------------------------

    \1\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ] 
61,051 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 61,132, 
order on reh'g and clarification, Order No. 1000-B, 141 FERC ] 
61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 
F.3d 41 (D.C. Cir. 2014).
    \2\ 16 U.S.C. 824e.
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    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\
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    \3\ For 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-energy-outlook.html.
    \4\ Queued Up: Characteristics of Power Plants Seeking 
Transmission Interconnection As of the End of 2020, Lawrence 
Berkeley National Laboratory, at 22 (May 2021).
    \5\ Queued Up: Characteristics of Power Plants Seeking 
Transmission Interconnection As of the End of 2021, Lawrence 
Berkeley National Laboratory, at 3 (April 2022).
    \6\ As 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).
    \7\ See 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.'').
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    4. The record here appears to show that transmission expansion 
is increasingly occurring in a piecemeal and inefficient fashion 
outside of the regional transmission

[[Page 26611]]

planning process, which may not be cost-effective 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 long-term 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.
---------------------------------------------------------------------------

    \8\ See 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).
    \9\ See Americans for a Clean Energy Grid Reply Comments, 
Appendix A (listing 174 commenters).
    \10\ See NOPR, 179 FERC ] 61,028 at P 183.
    \11\ Id. P 242.
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    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 cost-effective 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 first-ready, first-served cluster study approaches, to 
process interconnection requests more efficiently.
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    \12\ See, 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.
    \13\ See 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).
    \14\ See, 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.
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    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.
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    \15\ See, 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.'').
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    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


