Proposed Rule2022-08973
Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection
Primary source
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Published
May 4, 2022
Issuing agencies
Energy DepartmentFederal Energy Regulatory Commission
Abstract
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.
Full Text
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<title>Federal Register, Volume 87 Issue 86 (Wednesday, May 4, 2022)</title>
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[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 [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[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 <a href="https://www.ferc.gov">https://www.ferc.gov</a>, is
preferred.
<bullet> Electronic Filing: Documents must be filed in acceptable
native applications and print-to-PDF, but not in scanned or picture
format.
<bullet> 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,
<a href="/cdn-cgi/l/email-protection#fc989d8a9598d29e938e989992bc9a998e9fd29b938a"><span class="__cf_email__" data-cfemail="81e5e0f7e8e5afe3eef3e5e4efc1e7e4f3e2afe6eef7">[email protected]</span></a>
Noah Lichtenstein (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696,
<a href="/cdn-cgi/l/email-protection#a6c8c9c7ce88cacfc5ced2c3c8d5d2c3cfc8e6c0c3d4c588c1c9d0"><span class="__cf_email__" data-cfemail="4b25242a2365272228233f2e25383f2e22250b2d2e3928652c243d">[email protected]</span></a>
Lina Naik (Legal Information), Office of the General Counsel, 888 First
Street NE, Washington, DC 20426, (202) 502-8882, <a href="/cdn-cgi/l/email-protection#08646166692666696163486e6d7a6b266f677e"><span class="__cf_email__" data-cfemail="e985808788c787888082a98f8c9b8ac78e869f">[email protected]</span></a>
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
[[Page 26505]]
(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
[[Page 26506]]
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: <a href="https://www.ferc.gov/TFSOET">https://www.ferc.gov/TFSOET</a>. 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\
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\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\
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\30\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching
agenda).
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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.
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\31\ See Appendix A for a list of commenters and the abbreviated
names of commenters that are used in this NOPR.
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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.
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\33\ S.C. Pub. Serv. Auth., 762 F.3d at 56-59.
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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.
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\34\ 16 U.S.C. 824, 824d, 824e; see also U.S. DOE Comments at 2
(stating that ``strengthening and expanding existing transmission
infrastructure, particularly the development of regional and 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), <a href="https://www.nerc.com/news/Headlines%20DL/NERC%20Reliability%20Hearing%20Testimony%203-11-21%20-%20Final.pdf">https://www.nerc.com/news/Headlines%20DL/NERC%20Reliability%20Hearing%20Testimony%203-11-21%20-%20Final.pdf</a>
(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), <a href="https://gridprogress.files.wordpress.com/2021/10/transmission-planning-for-the-21st-century-proven-practices-that-increase-value-and-reduce-costs-7.pdf">https://gridprogress.files.wordpress.com/2021/10/transmission-planning-for-the-21st-century-proven-practices-that-increase-value-and-reduce-costs-7.pdf</a> (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), <a href="https://www.misoenergy.org/about/miso-strategy-and-value-proposition/miso-value-proposition/">https://www.misoenergy.org/about/miso-strategy-and-value-proposition/miso-value-proposition/</a> (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), <a href="https://www.spp.org/value-of-transmission/">https://www.spp.org/value-of-transmission/</a> (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), <a href="https://cleanenergygrid.org/texas-national-model-bringing-clean-energy-grid/">https://cleanenergygrid.org/texas-national-model-bringing-clean-energy-grid/</a>
) (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.
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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\
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\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.
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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.
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\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.
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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), <a href="https://acore.org/wp-content/uploads/2021/09/Just-Reasonable-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf">https://acore.org/wp-content/uploads/2021/09/Just-Reasonable-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf</a> (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),
<a href="https://acore.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.14.21.pdf">https://acore.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.14.21.pdf</a> (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), <a href="https://cdn.misoenergy.org/MISO2020InterconnectionQueueOutlook445829.pdf">https://cdn.misoenergy.org/MISO2020InterconnectionQueueOutlook445829.pdf</a>
(MISO 2020 Queue Outlook)).
\54\ ICF Sept. 2021 Report at 2.
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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.
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\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).
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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\
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\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), <a href="https://www.brattle.com/wp-content/uploads/2021/10/Transmission-Investment-Needs-and-Challenges.pdf">https://www.brattle.com/wp-content/uploads/2021/10/Transmission-Investment-Needs-and-Challenges.pdf</a>); 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),
<a href="https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf">https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf</a> (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),
<a href="https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf">https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf</a>.
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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), <a href="https://www.eba-net.org/assets/1/6/5_-_%5BPeskoe%5D%5B1-66%5D.pdf">https://www.eba-net.org/assets/1/6/5_-_%5BPeskoe%5D%5B1-66%5D.pdf</a>.
\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.
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\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), <a href="https://www.iso-ne.com/static-assets/documents/2021/09/a07_tc_2021_09_28_attk_ext_trans_presentation.pdf">https://www.iso-ne.com/static-assets/documents/2021/09/a07_tc_2021_09_28_attk_ext_trans_presentation.pdf</a>; 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)).
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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).
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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), <a href="https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf">https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf</a>.
\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), <a href="https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf">https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf</a>.
\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.
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\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.
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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.
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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.
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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.
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\125\ Order No. 1000, 136 FERC ] 61,051 at PP 624-625.
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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.
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\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).
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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.
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\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.
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\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.
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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.
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\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.
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\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),
<a href="https://www.southeasternrtp.com/docs/general/2021/2021-SERTP-Regional-Transmission-Planning-Analyses-Summary-Final.pdf">https://www.southeasternrtp.com/docs/general/2021/2021-SERTP-Regional-Transmission-Planning-Analyses-Summary-Final.pdf</a>;
WestConnect Regional Transmission Planning, 2020-21 Planning Cycle
Final Regional Study Plan, at 7 (Mar. 18, 2020), <a href="https://doc.westconnect.com/Documents.aspx?NID=18668&dl=1">https://doc.westconnect.com/Documents.aspx?NID=18668&dl=1</a>; NorthernGrid,
Regional Transmission Plan for the 2020-2021 NorthernGrid Planning
Cycle, at 5 (Dec. 8, 2021), <a href="https://www.northerngrid.net/private-media/documents/2020-2021_Regional_Transmission_Plan.pdf">https://www.northerngrid.net/private-media/documents/2020-2021_Regional_Transmission_Plan.pdf</a>.
\160\ See NERC, Glossary of Terms Used in NERC Reliability
Standards (June 28, 2021), <a href="https://www.nerc.com/files/glossary_of_terms.pdf">https://www.nerc.com/files/glossary_of_terms.pdf</a> (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), <a href="https://emp.lbl.gov/generation-storage-and-hybrid-capacity">https://emp.lbl.gov/generation-storage-and-hybrid-capacity</a>.
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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\
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\172\ MISO Comments at 41-43.
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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 utili
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