transmission facility); see also Minnesota Commerce Comments at 3
(arguing the risk of status quo is worse than the risk of over-
building).
    \392\ See, e.g., NASUCA Comments at 3-5; November 2021 Technical
Conference Tr. at 29 (testimony of Dr. Patton).
---------------------------------------------------------------------------

    246. Public utility transmission providers would bear the burden on
compliance of demonstrating that their proposed selection criteria
satisfy the Order Nos. 890 and 1000 transmission planning principles in
the context of Long-Term Regional Transmission Planning, even if public
utility transmission providers propose to use selection criteria that
they also use in their existing regional transmission planning
process.\393\ Likewise, public utility transmission providers would
bear the burden on compliance of demonstrating that their proposed
selection criteria seek to maximize benefits to consumers over time
without over-building transmission facilities. Moreover, we propose to
require that public utility transmission providers demonstrate on
compliance that they developed their proposed selection criteria in
consultation with the relevant state entities in their transmission
planning region's footprint.
---------------------------------------------------------------------------

    \393\ For example, if public utility transmission providers in a
transmission planning region propose to use existing selection
criteria, they should explain on compliance how those criteria also
are just and reasonable with respect to the selection of regional
transmission facilities identified to address transmission needs
driven by changes in the resource mix and demand.
---------------------------------------------------------------------------

    247. We propose that, consistent with Order No. 1000, the developer
of a transmission facility selected in the regional transmission plan
for purposes of cost allocation through Long-Term Regional Transmission
Planning to address transmission needs driven by changes in the
resource mix and demand would be eligible to use the applicable cost
allocation method for the Long-Term Regional Transmission
Facility.\394\ We also propose that the existing transmission developer
requirements would apply, including that the developer of the selected
regional transmission facility must submit a development schedule that
indicates the required steps, such as the granting of state approvals
necessary to develop and construct the transmission facility such that
it meets the transmission needs of the transmission planning
region.\395\ To the extent the relevant state entities in a
transmission planning region agree to a State Agreement Process, as
described in the Regional Transmission Cost Allocation section below,
the development schedule should also include relevant steps related to
that process.\396\
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    \394\ We note that the applicable cost allocation method for a
Long-Term Regional Transmission Facility may not be ex ante, as
discussed in the Regional Transmission Cost Allocation section
below.
    \395\ Order No. 1000-A, 139 FERC ] 61,132 at P 442. The
Commission also stated that, as part of the ongoing monitoring of
the progress of a transmission facility once it is selected, the
public utility transmission providers in a transmission planning
region must establish a date by which state approvals to construct
must have been achieved that is tied to when construction must begin
to timely meet the need that the facility is selected to address. If
such critical steps have not been achieved by that date, then the
public utility transmission providers in a transmission planning
region may ``remove the transmission facility from the selected
category and proceed with reevaluating the regional transmission
plan to seek an alternative solution.'' Id.
    \396\ Infra P 302 (describing cost allocation requirements for
Long-Term Regional Transmission Planning).
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    248. Given the longer-term nature of transmission needs driven by
changes in the resource mix and demand, we note that the required
development schedule may make it unnecessary for the developer of a
transmission facility selected in the regional transmission plan for
purposes of cost allocation to take actions or incur expenses in the
near-term if the transmission facility will not need to be in service
in the near-term. We also note that, with respect to a transmission
facility selected in the regional transmission plan for purposes of
cost allocation to meet transmission needs driven by changes in the
resource mix and demand, public utility transmission providers may make
its selection status subject to the outcomes of subsequent Long-Term
Regional Transmission Planning cycles, such that a previously selected
transmission facility is no longer needed. Public utility transmission
providers should include in their selection criteria how they will
address the selection status of a previously selected transmission
facility based on the outcomes of subsequent Long-Term Regional
Transmission Planning cycles.
    249. Consistent with our approach to benefits analysis, we clarify
that public utility transmission providers would have the flexibility
to propose to use a portfolio approach in selecting regional
transmission facilities in the regional transmission plan for purposes
of cost allocation that address transmission needs driven by changes in
the resource mix and demand. Public utility transmission providers that
propose such an approach would have to include in their OATTs
provisions describing whether the selection criteria would apply to one
proposed regional transmission facility or to a portfolio of regional
transmission facilities; and whether the portfolio approach would be
used for Long-Term Regional Transmission Planning universally to
address transmission needs driven by changes in the resource mix and

demand or would be used only in certain specified instances.
    250. We preliminarily find that the development and analysis of
Long-Term Scenarios cannot remedy the deficiencies in the Commission's
existing regional transmission planning requirements without the
inclusion of transparent and not unduly discriminatory selection
criteria that are used to evaluate transmission facilities (or
portfolios of transmission facilities) for potential selection in the
regional transmission plan for purposes of cost allocation. Absent such
criteria, public utility transmission providers' Commission-
jurisdictional rates may be unjust and unreasonable and unduly
discriminatory and preferential.
    251. As noted above, we recognize the inherent uncertainty involved
in predicting future transmission needs, including those driven by
changes in the resource mix and demand, and many commenters express
concern that imperfect information may lead to selecting transmission
facilities in the regional transmission plan for purposes of cost
allocation that become stranded assets. However, we believe that there
are selection criteria that public utility transmission providers could
adopt, following consultation with stakeholders and with relevant state
entities in their transmission planning region's footprint, to minimize
these risks while allowing for investment in transmission facilities
that more efficiently or cost-effectively meet transmission needs
driven by changes in the resource mix and demand. For example, under a
least-regrets approach, public utility transmission providers in a
transmission planning region would select a transmission facility (or
portfolio of transmission facilities) in their regional transmission
plan for purposes of cost allocation that is net-beneficial in most or
all Long-Term Scenarios, even if other transmission facilities have
more net benefits or a higher benefit-cost ratio in a single Long-Term
Scenario. Another approach is a weighted-benefits approach, in
accordance with which public utility transmission providers in a
transmission planning region would select a transmission facility (or
portfolio of regional transmission facilities) in their regional
transmission plan for purposes of cost allocation based on its
probability-weighted average benefits, where probabilities have been
assigned to each Long-Term Scenario studied.\397\
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    \397\ Brattle-Grid Strategies Oct. 2021 Report at 59-60.
---------------------------------------------------------------------------

    252. We seek comment on the requirements proposed in this section
of the NOPR. In addition, we seek comment on whether relevant state
entities should have the opportunity to voluntarily fund the cost of,
or a portion of the cost of, a Long-Term Regional Transmission Facility
\398\ to enable such facility to satisfy the public utility
transmission provider's selection criteria (e.g., any benefit-cost
threshold), and if so, whether the Commission's final rule in this
proceeding should include requirements to facilitate such an
opportunity for the relevant state entities.\399\ Commenters on this
issue should also address preferred approaches to implement such a
voluntary funding opportunity for relevant state entities for Long-Term
Regional Transmission Facilities. For example, we seek comment on what
mechanism would be appropriate to document agreement from the relevant
state entities to voluntarily fund (e.g., commit customers within the
state to fund) the cost of, or a portion of the cost of, a Long-term
Regional Transmission Facility to enable such facility to satisfy the
public utility transmission provider's selection criteria; whether a
public utility transmission provider should be required to include a
pro forma agreement for such an opportunity in its OATT for
facilitation purposes; how the Commission and the public utility
transmission providers would be assured that the commitment by the
relevant state entity is sufficiently binding; and whether another
manner for relevant state entities to make and fulfill such a
commitment would be preferable. We also seek comment on what stage in
the regional transmission planning process is the most appropriate
point for such an opportunity for the relevant state entities. We also
seek comment on whether such opportunity for the relevant state
entities to voluntarily fund the cost of, or the portion of the cost
of, a Long-Term Regional Transmission Facility should be limited to
relevant state entities or should be expanded to include
interconnection customers.\400\
---------------------------------------------------------------------------

    \398\ As noted infra note 507, we propose to define a Long-Term
Regional Transmission Facility as a transmission facility identified
as part of Long-Term Regional Transmission Planning and selected in
the regional transmission plan for purposes of cost allocation to
address transmission needs driven by changes in the resource mix and
demand.
    \399\ For Long-Term Regional Transmission Facilities, such an
opportunity for the relevant state entities could enable them to
assign a value to achieving of their particular policy goals while
ensuring that their customers bear the corresponding costs. As the
New Jersey Commission suggests, ``some states ascribe additional
`value' to the achievement of public policy goals, backed by a
willingness to bear the costs associated with those benefits.'' NJ
Commission, Comments, Docket No. AD21-15-000, at 4 (filed Apr. 1,
2022). See also Maryland Energy Admin Comments at 8-9; Maryland
Commission Reply Comments at 2.
    \400\ We note that some commenters have suggested that
interconnection customers similarly be afforded an opportunity to
voluntarily contribute funds to a Long-Term Regional Transmission
Facility so as to facilitate its selection. Enel Comments at 12-14;
ACPA and ESA Comments at 75-79.
---------------------------------------------------------------------------

c. Implementation of Long-Term Regional Transmission Planning
    253. We recognize that the timing of the proposed Long-Term
Regional Transmission Planning requirement has the potential to overlap
with public utility transmission providers' near-term assessment of
transmission needs captured by existing regional transmission planning
processes. We propose that public utility transmission providers must
explain on compliance how the initial timing sequence for Long-Term
Regional Transmission Planning interacts with existing regional
transmission planning efforts. We recognize the possibility that there
may be overlap in the time horizon for the proposed Long-Term Regional
Transmission Planning and existing near-term regional transmission
planning processes and that they will likely inform each other. It is
also possible that, in some cases, transmission facilities selected in
a regional transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand may
provide near-term reliability or economic benefits and thus potentially
displace regional transmission facilities that are under consideration
as part of existing regional transmission planning processes.
    254. We seek comment on the requirement proposed in this section of
the NOPR. In particular, we seek comment on whether there is a need to
coordinate the initial timing sequences between Long-Term Regional
Transmission Planning and the existing near-term regional transmission
planning processes.
    255. We also seek comment on whether the Commission should host a
periodic forum for public utility transmission providers, transmission
experts, relevant federal and state agencies, and other stakeholders to
share best practices in implementing Long-Term Regional Transmission
Planning as proposed herein. The Commission could, for example, host a
tri-annual technical conference focused on topics such as choice of
best

available data, principles for developing plausible scenarios, and
techniques for evaluating benefits of proposed transmission facilities.
We seek comment on the benefits such a forum might provide, and, if
implemented, how such a forum should be structured and the frequency on
which it should be held.
2. Consideration of Dynamic Line Ratings and Advanced Power Flow
Control Devices in Long-Term Regional Transmission Planning
a. ANOPR
    256. In the ANOPR, the Commission sought comment on whether the
development of longer-term scenarios for planning purposes should be
pursued and, if so, whether and how Grid-Enhancing Technologies (GETs)
\401\ should be accounted for in determining what transmission is
needed under such scenarios.\402\ The Commission solicited input on how
it could require greater consideration of GETs and asked commenters to
describe any challenges that exist in establishing such a requirement
and how they might be addressed.\403\
---------------------------------------------------------------------------

    \401\ For purposes of a prior workshop, Commission staff stated
that GETs increase the capacity, efficiency, or reliability of
transmission facilities. Commission staff further stated that these
technologies include but are not limited to: (1) Power flow control
and transmission switching equipment; (2) storage technologies; and
(3) advanced line rating management technologies. Grid-Enhancing
Technologies, Notice of Workshop, Docket No. AD19-19-000 (issued
Sept. 9, 2019).
    \402\ ANOPR, 176 FERC ] 61,024 at P 48.
    \403\ Id. P 158.
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b. Comments
    257. The majority of commenters on the ANOPR support the Commission
requiring public utility transmission providers to consider GETs in the
regional transmission planning process, emphasizing that advanced
technologies can optimize existing transmission corridors and provide
cost-effective solutions for consumers.\404\ NARUC states that an
effective transmission planning process should maximize the use of
existing transmission and build new transmission only where necessary
or economic, asserting that the transmission planning process needs a
clear pathway for consideration of alternative transmission solutions,
including GETs.\405\
---------------------------------------------------------------------------

    \404\ See, e.g., National Grid Comments at 32; PJM Comments at
59-62; State of Massachusetts Comments at 20; see also Joint Fed.-
State Task Force on Elec. Transmission, Transcript of Nov. 10, 2021
Meeting, Docket No. AD21-15-000, at 97:5-11 (Chair Scripps)
(supporting consideration of GETs in regional transmission
planning).
    \405\ NARUC Comments at 9.
---------------------------------------------------------------------------

    258. Some commenters, such as Duke, EEI, and MISO Transmission
Owners, either oppose the use of GETs in regional transmission
planning, do not see it as a fit for regional transmission planning for
transmission needs driven by changes in the resource mix and in demand,
or urge caution, as they assert that the technologies are not always
substitutes for transmission facilities.\406\ AEP notes that GETs
should be considered as long as they are evaluated on an equal footing,
for example, evaluating technology life span on equal footing.\407\
---------------------------------------------------------------------------

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

    259. Market monitors, such as the PJM Market Monitor, emphasize the
value that dynamic line ratings \408\ and other GETs could add in
maximizing existing transmission capacity but express caution about how
they would be implemented and compensated.\409\ Potomac Economics sees
some benefit to GETs in helping transmission owners avoid inefficient
transmission upgrade costs to mitigate congestion but expresses concern
about mandating long-term planning studies that would involve RTOs/ISOs
or transmission providers ``speculating on'' GETs.\410\
---------------------------------------------------------------------------

    \408\ A dynamic line rating is ``a transmission line rating that
applies to a time period of not greater than one hour and reflects
up-to-date forecasts of inputs such as (but not limited to) ambient
air temperature, wind, solar heating, transmission line tension, or
transmission line sag.'' Managing Transmission Line Ratings, Order
No. 881, 177 FERC ] 61,179, at PP 235, 238 (2021); 18 CFR
35.28(b)(14).
    \409\ PJM Market Monitor Comments at 13.
    \410\ Potomac Economics Comments at 4.
---------------------------------------------------------------------------

    260. RTOs/ISOs generally indicate that they currently consider the
use of GETs in the regional transmission planning process. CAISO
supports the use of GETs in the regional transmission planning
process.\411\ MISO indicates that its current regional transmission
planning process allows for the consideration of GETs, but also
indicates that these technologies alone will not be able to address the
changing needs of the transmission system.\412\ PJM states that, as
part of its regional transmission planning process, it evaluates GETs
proposals, to the extent submitted, in a manner not materially
different from its evaluation of other project proposals.\413\ PJM also
notes that it conducts an advanced technology pilot program as a
testing ground for new technologies that require integration into PJM
operations and markets.\414\ Additionally, SPP states that it supports
the use of certain GETs where they can be appropriately used in
regional transmission planning. It contends that it has considered
certain GETs in the regional transmission planning process, but notes
that certain technologies, such as dynamic line ratings or topological
controls, have historically not lent themselves readily to utilization
in the regional transmission planning process.\415\
---------------------------------------------------------------------------

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

    261. RTOs/ISOs, notably MISO and PJM, also discuss the importance
of ensuring that public utility transmission providers understand any
GETs that may be deployed on the system and their limitations, as well
as understanding the challenges of integrating GETs into existing
systems; for example, whether there is a need to change telemetry,
modeling, other operating tools, and protocols, all of which
necessitate careful consideration.\416\ PJM notes the value of its
ongoing Advanced Technology Pilot Program in addressing implementation
challenges and identifying system risks associated with GETs.
Expressing concerns about the deployment of GETs by nonincumbent
transmission developers, PJM recommends that the Commission request
that the industry, via NERC and/or U.S. DOE, develop a technology
application guide addressing where, when, and how to apply GETs.\417\
MISO states that it is important not to overstate the capabilities of
GETs in the regional transmission planning process, as these
technologies generally cannot substitute for long-term investment in
transmission facilities that are needed to address the evolving
resource mix, and notes the inherent uncertainty in forecasting power
flows and congestion longer into the future.\418\
---------------------------------------------------------------------------

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

    262. A few commenters set forth criteria that public utility
transmission providers should be required to consider in the regional
transmission planning process to promote the use of GETs. These
include: Optimizing the utilization of existing and new transmission
facilities; \419\ requiring energy efficiency as a design criterion for
every transmission capital project; \420\ and requiring public utility
transmission providers to show where they have incorporated GETs in
their

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

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

    263. Other commenters offer specific suggestions on how GETs could
be implemented. TAPS urges the Commission to ``[m]ake more explicit the
mandate to consider GETs as part of regional planning processes,''
arguing that Order No. 1000's requirement to consider non-transmission
alternatives ``appears insufficient to ensure robust consideration of
GETs in the planning process.'' \422\ In addition, TAPS recommends that
the Commission expand the MISO/PJM Targeted Market Efficiency Process
to the regional transmission planning process to promote the use of
GETs for quick fixes identified in the regional transmission planning
process.\423\
---------------------------------------------------------------------------

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

    264. PJM suggests that the Commission require RTOs/ISOs and non-
RTO/ISO transmission planning regions to ``develop a robust process to
account for the potential for [GETs] to be integrated into the planning
processes as part of both near-term and long-range expansion options
before requiring that new greenfield transmission be built.'' \424\
Along similar lines, WATT Coalition suggests that for proposed
transmission projects with an initial cost estimate above $10 million,
the Commission should require the transmission planning region to show
documentation of its evaluation of alternative solutions utilizing
GETs.\425\
---------------------------------------------------------------------------

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

    265. EDF offers a specific application for GETs implementation,
suggesting that the Commission encourage and even require that GETs be
proposed to address outages that have a material impact on market
efficiency, reliability, and resiliency. EDF notes that transmission
system upgrades are often associated with multi-month outages, which
can have a severe impact on market efficiency and suggests that GETs be
proposed in combination with traditional upgrades or to minimize the
impact of outages that can result from the construction of transmission
upgrades.\426\ WATT Coalition builds on this notion, suggesting that
the Commission require transmission owners and planning authorities to
propose solutions, including GETs, that minimize the impacts of long
duration outages.\427\
---------------------------------------------------------------------------

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

    266. WATT Coalition encourages the Commission to require the
periodic publication of a report on grid utilization to show
transmission usage data in order to provide system planners with a
``more holistic profile of their system capacity, establishing a new
dataset for targeted GETs deployment and associated consumer savings.''
\428\ Arizona Commission adds that an independent transmission monitor
could use information collected to provide feedback on how public
utility transmission providers consider GETs.\429\
---------------------------------------------------------------------------

    \428\ Id.
    \429\ Arizona Commission Reply Comments at 12.
---------------------------------------------------------------------------

c. Need for Reform
    267. Since Order No. 1000, commercially available technologies to
make transmission systems operate more efficiently or cost-effectively
have greatly advanced. This influx of new and improved technologies has
the potential to improve the operation of new and existing transmission
facilities and defer new transmission investments. As such, the
consideration of new technological innovations in regional transmission
planning processes could help to ensure that these processes are
identifying more efficient or cost-effective regional transmission
facilities and in turn, that Commission-jurisdictional rates are just
and reasonable.
    268. When the Commission issued Order No. 1000, integrating these
new technologies was not a major focus of the rule, partly because many
new technologies were either still in development or not yet widely in
use. After more than a decade, the technologies available today may
help to ensure that the transmission system operates more efficiently
or cost-effectively. However, Order No. 1000-compliant regional
transmission planning processes do not appear to have kept time with
technology advancements and potentially need to be updated to ensure
that they are appropriately considering these new technologies.
    269. Recently, in Order No. 881, which required more accurate
transmission line ratings in near-term transmission service through the
use of ambient-adjusted transmission line ratings,\430\ the Commission
highlighted the benefits of dynamic line ratings, including permitting
greater power flows than would otherwise be allowed, aiding in the
detection of situations where power flows should be reduced to maintain
safe and reliable operations, and avoiding unnecessary wear on
transmission equipment.\431\ Other benefits of dynamic line ratings
that the Commission emphasized in Order No. 881 include strategic
deployments and targeted applications in which dynamic line ratings can
provide net benefits to customers by increasing the accuracy and power
carrying capabilities of a line.\432\ While the Commission declined to
mandate dynamic line ratings in Order No. 881, it required RTOs/ISOs to
establish and maintain systems and procedures necessary to allow
transmission owners to electronically update transmission line ratings
for ambient-adjusted ratings, which could facilitate the use of dynamic
line ratings.\433\ In addition, the Commission issued a Notice of
Inquiry to continue to explore the implementation of dynamic line
ratings.\434\ This Notice of Inquiry sought comment on: Whether and how
the required use of dynamic line ratings is needed to ensure just and
reasonable Commission-jurisdictional rates; potential criteria for
dynamic line ratings requirements; the benefits, costs, and challenges
of implementing dynamic line ratings; the nature of potential dynamic
line ratings requirements; and potential timeframes for implementing
dynamic line ratings requirements.\435\
---------------------------------------------------------------------------

    \430\ Order No. 881, 177 FERC ] 61,179 at P 34.
    \431\ Id. P 253.
    \432\ Id.
    \433\ Id. P 255.
    \434\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110
(2022).
    \435\ Id. P 1.
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    270. At a recent workshop held by Commission staff,\436\
participants highlighted the benefits of advanced power flow control
devices,\437\ such as their ability to modify a transmission line's
electrical characteristics to increase or decrease power flowing
through the line without increasing the capacity of the line.
Participants also highlighted that optimal transmission switching acts
to completely open or close off routes to power flow. Finally,
participants noted that advanced power

flow control devices, including optimal transmission switching, provide
the tools to effectively control and route power to lines that have
more capacity than those that do not, which can reduce congestion,
reduce costs to consumers, and increase reliability of the transmission
system.
---------------------------------------------------------------------------

    \436\ Grid-Enhancing Technologies, Notice of Workshop, Docket
No. AD19-19-000 (issued Sept. 9, 2019).
    \437\ Advanced power flow control devices serve a transmission
function. These devices can help the system operator control power
flows over a given path and can include phase shifting transformers
(also known as phase angle regulators) and devices or systems
necessary for implementing optimal transmission switching. Advanced
power flow control devices allow power to be pushed and pulled to
alternate lines with spare capacity leading to maximum utilization
of existing transmission capacity. See T. Bruce Tsuchida et al., The
Brattle Group, Unlocking the Queue with Grid-Enhancing Technologies,
at 19-20 (Feb. 1, 2021), https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf.
---------------------------------------------------------------------------

    271. To address the issues described above, we propose reforms to
require public utility transmission providers to more fully consider
two specific technologies--dynamic line ratings and advanced power flow
control devices--in regional transmission planning processes.
d. Proposed Reform
    272. In order to help ensure that regional transmission planning
processes identify more efficient or cost-effective transmission
facilities for selection in the regional transmission plan for purposes
of cost allocation, we propose to require that public utility
transmission providers in each transmission planning region more fully
consider in regional transmission planning and cost allocation
processes two specific technologies: The incorporation into
transmission facilities of dynamic line ratings and advanced power flow
control devices. We believe that selecting transmission facilities that
incorporate dynamic line ratings or advanced power flow control devices
in the regional transmission plan for purposes of cost allocation may
offer a more efficient or cost-effective alternative to other regional
transmission facilities in certain instances.
    273. Specifically, we believe it is possible that selecting
transmission facilities that incorporate such technologies serving a
transmission function in the regional transmission plan for purposes of
cost allocation could be more efficient or cost-effective than a
proposed regional transmission facility that does not use such
technologies. For example, selecting in the regional transmission plan
for purposes of cost allocation a transmission facility that is
designed with the equipment necessary to support dynamic line ratings
may provide greater benefits through reduced production costs than a
similar transmission facility that does not include such equipment.
Likewise, selecting in the regional transmission plan for purposes of
cost allocation a transmission facility that incorporates an advanced
power flow control device may provide greater production costs benefits
under transmission outage scenarios than another transmission facility.
    274. To facilitate greater use of these technologies where
warranted, we propose to require that public utility transmission
providers in each transmission planning region consider for each
identified regional transmission need whether selecting transmission
facilities in the regional transmission plan for purposes of cost
allocation that incorporate dynamic line ratings or advanced power flow
control devices would be more efficient or cost-effective than
transmission facilities that do not incorporate these technologies.
Specifically, such consideration should include first, whether
incorporating dynamic line ratings or advanced power flow control
devices into existing transmission facilities could meet the same
regional transmission need more efficiently or cost-effectively than
other potential transmission facilities. Second, when evaluating
transmission facilities for potential selection in the regional
transmission plan for purposes of cost allocation, the public utility
transmission providers in the transmission planning region must also
consider whether incorporating dynamic line ratings and advanced power
flow control devices as part of any potential regional transmission
facility would be more efficient or cost-effective. We propose that
this requirement apply in all aspects of the regional transmission
planning processes, including the existing regional transmission
planning processes for near-term regional transmission needs and Long-
Term Regional Transmission Planning, as proposed in this NOPR. As is
the case for any other transmission facility selected in the regional
transmission plan for purposes of cost allocation, we propose that the
costs to incorporate dynamic line ratings or advanced power flow
control devices that are selected in the regional transmission plan for
purposes of cost allocation--whether as an addition to an existing
transmission facility or as part of a new regional transmission
facility--will be allocated using the applicable regional cost
allocation method.
    275. As required by Order No. 1000, the evaluation process must
culminate in a determination that is sufficiently detailed for
stakeholders to understand why a particular transmission facility was
selected or not selected in the regional transmission plan for purposes
of cost allocation.\438\ This process must now include the
consideration of dynamic line ratings and advanced power flow control
devices and why they were not incorporated into selected regional
transmission facilities.
---------------------------------------------------------------------------

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

    276. As discussed above, the ANOPR requested comment on GETs as a
larger category of transmission technologies. While we recognize that
there are likely other novel technologies that public utility
transmission providers could consider as they develop their regional
transmission plans, we are not proposing to mandate their consideration
at this time. We believe that there is enough operational experience
with dynamic line ratings and power flow control devices such that
public utility transmission providers should be able to adequately
consider their operations in the regional transmission planning
process. In addition, the nature of dynamic line ratings and advanced
power flow control devices allows for consideration in regional
transmission planning and cost allocation processes in a way that may
not be possible for other technologies.\439\
---------------------------------------------------------------------------

    \439\ For example, while transmission topology optimization can
serve a useful function in optimizing system flows and deferring
transmission investment in the short-term, system conditions over 5
to 20 years in the future may be too uncertain to rely on system
reconfiguration to address identified transmission needs.
---------------------------------------------------------------------------

    277. We seek comment on the requirements proposed in this section
of the NOPR. We also seek comment on whether there are other
transmission technologies serving a transmission function that should
be considered in regional transmission planning and cost allocation
processes. Finally, we seek comment on whether non-RTO/ISO transmission
planning regions should be required to update their energy management
systems or make other similar changes if dynamic line ratings are
identified as a more efficient or cost-effective transmission facility
selected in the regional transmission plan for purposes of cost
allocation.\440\
---------------------------------------------------------------------------

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

V. Regional Transmission Cost Allocation

    278. We preliminarily find that reforms to public utility
transmission providers' regional cost allocation methods are necessary
to ensure that Commission-jurisdictional rates are just and reasonable
and not unduly discriminatory or preferential. As discussed below, we
propose to require that public utility transmission providers in each
transmission planning region seek the agreement of relevant state
entities within the transmission planning region regarding the cost
allocation method or methods that will

apply to transmission facilities selected in the regional transmission
plan for purposes of cost allocation through Long-Term Regional
Transmission Planning and revise their OATTs to include the method or
methods.\441\
---------------------------------------------------------------------------

    \441\ We are not proposing to require any changes to existing
interregional cost allocation methods for interregional transmission
facilities that are selected in the regional transmission plan for
purposes of cost allocation and that the Commission previously
accepted as compliant with Order No. 1000.
---------------------------------------------------------------------------

    279. We also propose a reform to facilitate an additional
opportunity for involvement of state regulators in decisions about how
the costs of transmission facilities selected in a regional
transmission plan for purposes of cost allocation through Long-Term
Regional Transmission Planning will be allocated. Specifically, this
reform would require public utility transmission providers in each
transmission planning region to add a time period for states to
negotiate an alternate cost allocation method for a transmission
facility selected in the regional transmission plan for purposes of
cost allocation through Long-Term Regional Transmission Planning.

A. Background

    280. In Order No. 890, the Commission noted that for a transmission
planning process to comply with the final rule, it must address the
allocation of costs of new transmission facilities. The Commission
required public utility transmission providers and their stakeholders
to develop a new cost allocation method, if needed, for any new
transmission facilities that did not fall under public utility
transmission providers' existing cost allocation methods.\442\ The
Commission stated that such methods should consider: (1) Whether a
proposed cost allocation method fairly assigns costs among
participants, including those that cause them to be incurred and those
that otherwise benefit from them; (2) whether a proposed cost
allocation method provides adequate incentives to construct new
transmission; and (3) whether a proposed cost allocation method is
generally supported by the region's state authorities and
participants.\443\
---------------------------------------------------------------------------

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

    281. In Order No. 1000, the Commission determined that, while
existing cost allocation methods may have sufficed in the past,
changing circumstances in the industry led to the need for changes to
cost allocation requirements.\444\ The Commission observed that, as
transmission needs increased, the challenges in allocating the cost of
transmission appeared to grow more acute.\445\ The Commission further
found that, in ``the absence of clear cost allocation rules for
regional transmission facilities, there is a greater potential that
public utility transmission providers and nonincumbent transmission
developers may be unable to develop transmission facilities that are
determined by the region to meet their needs.'' \446\ As a result, the
Commission required each public utility transmission provider to have
in place a method, or set of methods, for allocating the costs of new
transmission facilities selected in the regional transmission plan for
purposes of cost allocation and established a set of six cost
allocation principles that public utility transmission providers'
regional cost allocation methods must satisfy.\447\ The Commission
determined that this principles-based approach requires the allocation
of the costs of new transmission facilities in a manner that is at
least roughly commensurate with the benefits received by those that pay
those costs while allowing for regional flexibility.\448\
---------------------------------------------------------------------------

    \444\ Order No. 1000, 136 FERC ] 61,051 at P 497.
    \445\ Id. P 498.
    \446\ Id. P 558.
    \447\ Id.
    \448\ Id. P 10; Order No. 1000-A, 139 FERC ] 61,132 at P 647.
---------------------------------------------------------------------------

    282. The six regional transmission cost allocation principles
adopted in Order No. 1000 are: (1) The costs of transmission facilities
selected in a regional transmission plan for purposes of cost
allocation must be allocated to those within the transmission planning
region that benefit from those facilities in a manner that is at least
roughly commensurate with estimated benefits; (2) those that receive no
benefit from transmission facilities, either at present or in a likely
future scenario, must not be involuntarily allocated any of the costs
of those transmission facilities; (3) a benefit to cost threshold
ratio, if adopted, cannot exceed 1.25 to 1; (4) costs must be allocated
solely within the transmission planning region unless another entity
outside the region voluntarily assumes a portion of those costs; (5)
the method for determining benefits and identifying beneficiaries must
be transparent; and (6) there may be different regional cost allocation
methods for different types of transmission facilities, such as those
needed for reliability, congestion relief, or to achieve Public Policy
Requirements.\449\ The Commission declined to require that public
utility transmission providers adopt a universal or comprehensive
definition of ``benefits'' and ``beneficiaries'' of regional
transmission facilities, instead permitting regional flexibility and
examining each transmission planning region's definitions on
compliance.\450\
---------------------------------------------------------------------------

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

    283. While the Commission determined that generator interconnection
was outside the scope of Order No. 1000, it also stated that public
utility transmission providers could propose a regional transmission
cost allocation method that allocates costs directly to generators as
beneficiaries, but any effort to do so must be consistent with the
Order No. 2003 generator interconnection process.\451\ No public
utility transmission providers have proposed a regional cost allocation
method that allocates costs directly to generators, instead allocating
all costs of transmission facilities selected in a regional
transmission plan for purposes of cost allocation to transmission
customers.
---------------------------------------------------------------------------

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

    284. On compliance, public utility transmission providers in each
transmission planning region adopted varying regional transmission cost
allocation methods to comply with the cost allocation principles of
Order No. 1000. The majority of these methods allocate the costs of
transmission facilities selected in a regional transmission plan for
purposes of cost allocation that address reliability needs separately
from those that address economic needs, and separately from those that
address transmission needs driven by Public Policy Requirements.
    285. Some public utility transmission providers' Order No. 1000-
compliant regional transmission cost allocation methods identify
benefits across a portfolio of transmission facilities rather than on a
facility-by-facility basis. An example of a transmission planning
region accounting for broader benefits is MISO, which accounts for the
following benefits in their MVP portfolio:\452\
---------------------------------------------------------------------------

    \452\ MISO, Multi-Value Project Portfolio, Detailed Business
Case, https://cdn.misoenergy.org/2011%20MVP%20Portfolio%20Detailed%20Business%20Case117056.pdf. More
general benefits requirements for MVP Projects are described at
MISO, FERC Electric Tariff, Attachment FF, Section II.C.2, .5.
---------------------------------------------------------------------------

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

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

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

     Reliability: transmission line overloads and system
voltage constraints mitigated, transient stability benefits, mitigation
of fault conditions that could cause system instability, voltage
stability, increased transfer capacity, increased transfer capability;
\454\
---------------------------------------------------------------------------

    \454\ Id. at 17-19.
---------------------------------------------------------------------------

     Policy: reliably enables the delivery of energy in support
of policy mandates.\455\
---------------------------------------------------------------------------

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

B. ANOPR

    286. In the ANOPR, the Commission recognized that reforms to
regional transmission planning cannot be successful without ensuring
that transmission providers and customers alike are able to identify
the types of benefits these transmission facilities can provide and
also identify the beneficiaries that would receive those benefits,
along with the relative proportion of benefits that accrue to each of
those beneficiaries.\456\ Acknowledging that cost allocation methods
can be ``difficult and controversial,'' particularly for regional
transmission facilities that may be both more costly and have
potentially broad benefits, the Commission sought comment on whether
there should be reforms to cost allocation in regional transmission
planning and cost allocation processes.\457\
---------------------------------------------------------------------------

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

    287. Additionally, the Commission noted that one way to add
oversight to the regional transmission planning and cost allocation
processes could be to involve state commissions in those
processes.\458\ For example, the Commission pointed to SPP's Regional
State Committee (RSC), which provides collective state regulatory
agency input in areas under the RSC's primary responsibilities and on
matters of regional importance related to the development and operation
of the bulk electric transmission system. Pursuant to the SPP Bylaws,
``with respect to transmission planning, the RSC will determine whether
transmission upgrades for remote resources will be included in the
regional transmission planning process and the role of transmission
owners in proposing transmission upgrades in the regional planning
process.'' \459\ The Commission sought comment on whether this type of
model, or other models that may be proposed, could be expanded to other
regions and other topics; for example, whether a state-led committee
could, inter alia, provide insight into regional transmission facility
costs and cost allocation methods.\460\
---------------------------------------------------------------------------

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

C. Comments

    288. In response to the ANOPR, the Commission received comments
from a broad range of stakeholders, generally recognizing the
importance of cost allocation to successful development of more
efficient or cost-effective regional transmission facilities and
advocating different ways to reduce the likelihood that controversy
regarding who pays for regional transmission facilities obstructs their
development and to ensure the costs of regional transmission facilities
are allocated roughly commensurate with benefits.
    289. In their comments, many state regulators and groups advocate
for increased state involvement in cost allocation decisions.\461\
NARUC explains that most states think that more should be done to
encourage and incent states with similar public policy profiles to use
the State Agreement Approach, which it says has the benefit of being a
stakeholder-driven product that enjoys significant state support.\462\
NARUC further asserts that planners could provide a platform for states
with similar policy objectives to better coordinate and agree upon cost
allocation, while urging that regions should ``retain the flexibility
to develop innovative approaches to allocating the costs.'' \463\
NESCOE asserts that states need to occupy a central role in cost
allocation, consistent with applicable state requirements.\464\ NESCOE
calls for state decision making in the evaluation and selection of
projects providing public policy benefits and for a robust role in the
regional transmission planning processes.\465\ Some commenters note
that they are already pursuing cost allocation reforms with
transmission planning regions.\466\ Arizona Commission contends that,
because state commissions are already tasked with ensuring retail rates
are just and reasonable for their ratepayers, increased state
commission involvement in cost allocation processes would better allow
state commissions to establish just and reasonable retail rates.\467\
New Jersey Commission states that to enable cost allocation reforms the
Commission could mandate public utility transmission providers
institute a process for states to submit portions of their public
policies for consideration into PJM's RTEP.\468\ Mississippi Commission
notes that where one or more states have common economic development,
environmental, or other goals, and require transmission investment to
achieve those goals, the cost of such projects could be allocated to
those states in an agreed upon amount.\469\ Northwest and Intermountain
notes that a strong state role is particularly important in non-RTO/ISO
regions.\470\ ACPA and ESA state that a Commission approach to cost
allocation could include cost contributions from states and
interconnection customers.\471\
---------------------------------------------------------------------------

    \461\ Members of the Task Force similarly advocated for state
regulatory involvement in cost allocation processes, emphasizing
that states are not merely stakeholders. See, e.g., Joint Fed.-State
Task Force on Elec. Transmission, Transcript of Feb. 16, 2022
Meeting, Docket No. AD21-15-000, at 107:1-6 (Chair French), 108:17-
18 (Comm'r Duffley), 109:2 (Chair Nelson), 110:4-5, 15-16 (Chair
Stanek), 112:3-5 (Comm'r Rechtschaffen).
    \462\ NARUC Comments at 25; see also Ohio Commission Comments at
15 (noting the PJM State Agreement Approach and related ``hard work
and progress that has already been made in incorporating state
policy goals into transmission planning in the PJM region.'');'');
Pennsylvania Commission Comments at 6 (similarly calling for respect
of the State Agreement Approach).
    \463\ NARUC Comments at 25-26.
    \464\ NESCOE Comments at 21-25.
    \465\ Id. at 49.
    \466\ NESCOE CommentsId. at 47-48; MISO Comments at 8, 21.
    \467\ Arizona Commission Comments at 7; see also SPP RSC
Comments at 10 (urging the Commission to seek approaches that
enhance state authority rather than diminishing or diluting it).
    \468\ New Jersey Commission Comments at 12-15.
    \469\ Mississippi Commission Comments at 14.
    \470\ Northwest and Intermountain Comments at 28-30.
    \471\ ACPA and ESA Comments at 75.
---------------------------------------------------------------------------

    290. But while there is broad agreement on the importance of
states' role in cost allocation, a number of states indicate that it is
difficult for them to participate in a timely manner in the regional
transmission planning and cost allocation processes to address concerns
regarding cost allocation.\472\ District of Columbia's Office of the
People's Counsel calls for the Commission to facilitate ``the
participation of any group that may be subject to cost allocation in
early planning stages to determine which outcome best serves the needs
of all the customers in that region.'' \473\ Other state commissions
also call for greater involvement in cost allocation

decisions.\474\ Maryland Energy Admin asserts that earlier state
involvement in cost allocation for the Artificial Island transmission
facility, for example, could have ``avoided significant delays and
additional costs, including some that were ultimately assigned to
ratepayers.'' \475\ Other commenters note that failure to gain state
support for selection and cost allocation for transmission facilities
can result in states subsequently blocking or delaying transmission
facilities selected in regional transmission planning and cost
allocation processes through subsequent state siting proceedings.\476\
---------------------------------------------------------------------------

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

    291. Many commenters support consideration of a wider set of
benefits than those currently used to evaluate transmission facilities
in the regional transmission plan for purposes of cost allocation.\477\
PIOs advocate that the Commission conduct a survey of all potential
benefits that can result from multi-value, scenario-based planning and
require that public utility transmission providers consider those
benefits for regional cost allocation as well as for regional
transmission planning.\478\ U.S. DOE states that the Commission should
establish a minimum set of potential benefits (and costs) to be
considered, to ensure that they are taken into account in both project
selection and in the allocation of costs for selected projects, adding
this practice would help ensure that benefits not currently fully
valued will be more appropriately incorporated in the planning process
and foster consistency among planning regions.\479\ Certain TDUs
express that cost allocation reforms must be equitable for
consumers.\480\
---------------------------------------------------------------------------

    \477\ ACORE Comments at ii; AEE Comments at 31-32; ACEG Comments
at 6-8; ACPA and ESA Comments at 75; AEP Comments at 14; Amazon
Comments at 4; Anbaric Comments at 29; Avangrid Comments at 9;
Business Council for Sustainable Energy Comments at 2; Citizens
Energy Comments at 6-7; City of New York Comments at 3-4; Union of
Concerned Scientists Comments at 66-75; Consumers Council Comments
at 4, 16; Duke Comments at 12; EDF Comments at 8-10; EEI Comments at
33; ITC Comments at 28-34; Massachusetts Attorney General Comments
at 24-25; New Jersey Commission Comments at 13-14, 17-19; NextEra
Comments at 83-88; Northwest and Intermountain Comments at 35-38;
Orsted Comments at 6-7; PIOs Comments at 30, 60; Policy Integrity
Comments at 43; PSEG Comments at 25-27; REBA Comments at 17; RMI
Comments at 4; SEIA Comments at 9; Shell Comments at 18-20; State
Agencies Comments at 21-22; State of Massachusetts Comments at 16-
17; U.S. DOE Comments at 7-9, 23-24; WIRES Comments at 18.
    \478\ PIOs Comments at 30; see also Orsted Comments at 6.
    \479\ U.S. DOE Comments at 23.
    \480\ Certain TDUs Comments at 5-6.
---------------------------------------------------------------------------

    292. Some RTOs/ISOs support the Commission requiring public utility
transmission providers to consider a broader set of transmission
benefits. For example, NYISO states that requiring public utility
transmission providers to adopt a broader range of evaluation and
selection criteria in their transmission planning processes would
enable them to consider the reliability, economic, and public policy
benefits of proposed solutions to a transmission need regardless of the
underlying driver of the need, which would enhance their ability to
select the more efficient or cost-effective transmission solution.\481\
SPP states that the Commission should adopt a minimum, standardized set
of benefit metrics for all public utility transmission providers to
ensure that transmission is valued consistently between regions and to
allow for an apples-to-apples comparison of potential projects.\482\
CAISO and MISO state that the Commission could consider requiring
public utility transmission providers to consider the resilience
benefits of transmission.\483\ If the Commission expands the set of
benefits that public utility transmission providers must consider, PJM
urges the Commission to provide clear decision criteria on whether and
when it is appropriate for public utility transmission planners to
order construction of new transmission for anticipated future
generation not yet in the interconnection queue.\484\ If the Commission
requires the consideration of a broader set of transmission benefits,
several RTOs/ISOs urge the Commission to provide for regional
flexibility.\485\
---------------------------------------------------------------------------

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

    293. Minnesota Commerce acknowledges that cost allocation is a
central factor in determining whether to build needed regional
transmission.\486\ Many commenters state that existing regional
transmission cost allocation methods are sound and/or should
continue.\487\ At least one commenter suggests that ultimate cost
allocation reforms should not unintentionally disrupt settled
methods.\488\
---------------------------------------------------------------------------

    \486\ Minnesota Commerce Comments at 6-7 (noting cost allocation
is one of the more difficult barriers to new transmission
development); see also November 2021 Technical Conference Tr. at 79.
    \487\ See, e.g., NASUCA Comments at 6; North Carolina Commission
Comments at 23; Ohio Commission Comments at 12-13; SERTP Comments at
4, 21-23; SoCal Edison Comments at 6.
    \488\ See NESCOE Comments at 50.
---------------------------------------------------------------------------

    294. Some commenters suggest special cost allocation methods for
transmission facilities resulting from scenario-based planning. Exelon
asserts that the default cost allocation method for transmission
projects resulting from scenario-based planning should reflect a load-
ratio share method,\489\ but that the Commission should allow suitable
substitute cost allocations as agreed to by the participating states to
reflect the particular aggregation of benefits provided by the
portfolio.\490\ On the other hand, Michigan Commission notes that
postage stamp cost allocation is highly divisive.\491\
---------------------------------------------------------------------------

    \489\ Under the load-ratio share regional cost allocation
method, the costs of new transmission facilities are allocated based
on some measure of system usage, whether at peak or overall.
Specifically, load-ratio share cost allocation methods include both
demand charge approaches and volumetric (energy) approaches. Under
the demand charge approach, costs are allocated in proportion to
each transmission customer's contribution to the system peak load
(which can be coincident or non-coincident peak). In contrast, under
the volumetric approach, costs are allocated based on each
transmission customer's share of total system usage. See CAISO,
Review Transmission Access Charge Structure Issue Paper, at 18, tbl.
2: Summary of ISO/RTO approaches to transmission charges (June 30,
2017).
    \490\ Exelon Comments at 30-31.
    \491\ Michigan Commission Comments at 20.
---------------------------------------------------------------------------

    295. Some commenters state that further analysis is necessary to
determine if prescriptive action by the Commission is necessary and
whether alteration of Order No. 1000's six regional transmission cost
allocation principles is warranted.\492\ AEP urges that benefits and
methodologies to measure those benefits should be consistent throughout
regions.\493\
---------------------------------------------------------------------------

    \492\ See, e.g., EEI Comments at 32-33; NARUC Comments at 22;
see also Joint Fed.-State Task Force on Elec. Transmission,
Transcript of Feb. 16, 2022 Meeting, Docket No. AD21-15-000, at
36:12-13 (Chair Brown Dutrieuille) (reiterating NARUC's comments
that the Order No. 1000 cost allocation principles should remain in
place).
    \493\ AEP Comments at 15.
---------------------------------------------------------------------------

    296. Some commenters propose cost allocation pursuant to benefits
related to anticipated future generation, resilience, and/or climate
and environmental benefits.\494\ APPA states that, to the extent that
regions shift their transmission planning processes to place a greater
emphasis on anticipated future generation or otherwise modify existing
planning protocols towards a more holistic analysis, it may be
appropriate to consider conforming changes to cost allocation
methods.\495\
---------------------------------------------------------------------------

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

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

D. Need for Reform

    297. The Commission has previously recognized that knowing how the
costs of transmission facilities would be allocated is critical to the
development of new transmission infrastructure.\496\ Without such
clarity, the likelihood that transmission facilities selected in a
regional transmission plan for purposes of cost allocation will be
developed is diminished, undermining the entire purpose of the regional
transmission planning process, namely, the development of more
efficient or cost-effective transmission facilities.\497\ Yet,
identifying a cost allocation method that is perceived as fair,
especially within transmission planning regions that encompass several
states, remains challenging. Litigation contesting regional
transmission cost allocation methods persists.\498\ Moreover, even
where the cost allocation method is reasonably settled, regional
transmission facilities face significant uncertainty and risk of not
reaching construction if certain stakeholders--in particular, a state
regulator responsible for permitting transmission facilities--do not
perceive the regional transmission facilities' value as commensurate
with their costs.\499\
---------------------------------------------------------------------------

    \496\ Order No. 1000, 136 FERC ] 61,051 at P 496 (discussing
findings in Order No. 890).
    \497\ Id.
    \498\ See, e.g., Long Island Power Auth. v. FERC, 27 F.4th 705,
709 (D.C. Cir. 2022) (addressing a ``long-running dispute'' over
regional transmission cost allocation in PJM); Pub. Serv. Elec. &
Gas Co. v. FERC, 989 F.3d 10 (D.C. Cir. 2021) (addressing dispute
over cost allocation for particular transmission upgrades).
    \499\ See, e.g., Transource Pa., LLC v. Dutrieuille, Case No.
1:2021cv0110 (filed June 22, 2021, M.D. Pa.) (lawsuit challenging
state commission's denial of an application for siting and
construction of regional transmission facilities).
---------------------------------------------------------------------------

    298. We are concerned that these challenges are likely to be
exacerbated in the context of Long-Term Regional Transmission Planning
and Cost Allocation. We recognize that, by requiring a longer-term
planning horizon, consideration of multiple scenarios, and accounting
for the longer-term factors that affect transmission needs, Long-Term
Regional Transmission Planning entails a more complex set of
considerations as compared to existing regional transmission planning
requirements. We are concerned that this increased complexity could
make cost allocation decisions more contentious, which may risk
undermining the development of more efficient or cost-effective
regional transmission facilities to address transmission needs driven
by changes in the resource mix and demand. For example, we anticipate
that stakeholders, including state regulators, may diverge in their
views of which scenarios best reflect future transmission needs, and
these conflicting perceptions may lead to disagreements regarding who
should pay for selected transmission facilities.
    299. For these reasons, we preliminarily find that the cost
allocation requirements for transmission facilities identified and
selected in the regional transmission plan through Long-Term Regional
Transmission Planning proposed in this proceeding may differ in part
from those established in Order No. 1000. In particular, we believe
that providing state regulators with a formal opportunity to develop a
cost allocation method for regional transmission facilities selected
through Long-Term Regional Transmission Planning could help increase
stakeholder--and state--support for those facilities, which, in turn,
may increase the likelihood that those facilities are sited and
ultimately developed with fewer costly delays and better ensure just
and reasonable Commission-jurisdictional rates.
    300. The Commission has long recognized the critical role of states
in transmission planning.\500\ The Commission recently issued a Policy
Statement addressing state efforts to develop transmission facilities
through voluntary agreements to plan and pay for those facilities.\501\
In the statement, the Commission recognized that such voluntary
agreements may allow state-prioritized transmission facilities to be
planned and built more quickly than would comparable facilities that
are planned through the regional transmission planning process, and
encouraged elimination to barriers to such agreements.\502\ The
Commission has also recently taken action to further federal-state
coordination and cooperation in this area through the establishment of
the Task Force.\503\ The Commission included in the list of topics that
the Task Force may consider: (1) ``[E]xploring potential bases for one
or more states to use FERC-jurisdictional transmission planning
processes to advance their policy goals, including multi-state goals;''
and (2) ``[e]xploring opportunities for states to voluntarily
coordinate in order to identify, plan, and develop regional
transmission solutions.'' \504\ The Task Force, comprised of FERC
Commissioners and state regulators, discussed the role of states in
regional transmission planning and cost allocation processes at two
meetings thus far, and numerous state regulators and other stakeholders
filed comments in response to the ANOPR on this topic. The general
consensus is that involving state regulators when it comes to
allocating the costs of new regional transmission facilities is
particularly important given states' role in siting those transmission
facilities, including consideration of the costs and benefits when
making state public interest determinations.\505\
---------------------------------------------------------------------------

    \500\ See Order No. 1000, 136 FERC ] 61,051 at P 688 (citing
Order No. 890, 118 FERC ] 61,119 at P 574). In 2015, the Commission
accepted NYISO's proposal to facilitate the timely participation of
the New York State Public Service Commission (New York Commission)
in review of transmission facilities proposed to address
transmission needs driven by Public Policy Requirements. Under
NYISO's process, the New York Commission is provided a time period
during which it may propose a cost allocation method or negotiate a
cost allocation method with the developer of such a proposed
transmission facility before the Order No. 1000-compliant ex ante
regional cost allocation method is applied. See NY Indep. Sys.
Operator, Inc., 151 FERC ] 61,040, at PP 119-121 (2015).
    \501\ State Voluntary Agreements to Plan and Pay for
Transmission Facilities, 175 FERC ] 61,225 (2021).
    \502\ Id. PP 2, 6.
    \503\ See Joint Fed.-State Task Force on Elec. Transmission, 175
FERC ] 61,224 at PP 1-2 (establishing the Task Force).
    \504\ Id. P 6.
    \505\ See NARUC Comments at 27, 46-47; NESCOE Comments at 21-25;
Arizona Commission Comments at 7; SPP RSC Comments at 10; Maryland
Energy Admin Comments at 2; Joint Fed.-State Task Force on Elec.
Transmission, Transcript of Feb. 16, 2022 Meeting, Docket No. AD21-
15-000, at 102:13-24 (Chair Thomas), 110:24-111:8 (Comm'r Allen),
111:24-112:5 (Comm'r Rechtschaffen), 134:4-9 (Chair Stanek)
(including in the list of three overarching themes from the meeting
that of state consultation--soliciting state input, at a minimum--on
cost allocation).
---------------------------------------------------------------------------

    301. We believe that facilitating involvement of state regulators
in the cost allocation process, as further described below, would allow
states to voluntarily coordinate to advance their policy goals through
needed transmission development and may minimize delays and additional
costs that can be associated with siting proceedings that follow the
regional transmission planning and cost allocation processes at the
federal level.\506\ We believe that providing an opportunity for state
involvement in regional transmission planning cost allocation processes
is becoming more important as states take a more active role in shaping
the resource mix and demand, which, in turn, means that those state
actions are increasingly affecting the long-term transmission

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

    \506\ E.g., Maryland Energy Admin Comments at 3 (pointing to
significant delays and costs associated with the Artificial Island
transmission facility); Exelon Comments at 31-32 (speaking generally
to states blocking or delaying transmission development through
siting).
---------------------------------------------------------------------------

E. Proposed Reform

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

    \507\ We propose to define a Long-Term Regional Transmission
Facility as a transmission facility identified as part of Long-Term
Regional Transmission Planning and selected in the regional
transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand.
---------------------------------------------------------------------------

    302. We propose to require that public utility transmission
providers in each transmission planning region revise their OATTs to
include either (1) a Long-Term Regional Transmission Cost Allocation
Method \508\ to allocate the costs of Long-Term Regional Transmission
Facilities, or (2) a State Agreement Process \509\ by which one or more
relevant state entities may voluntarily agree to a cost allocation
method, or (3) a combination thereof.\510\ We propose to require that
the Long-Term Regional Transmission Cost Allocation Method and any cost
allocation method resulting from the State Agreement Process for Long-
Term Regional Transmission Facilities comply with the existing six
Order No. 1000 regional cost allocation principles.\511\
---------------------------------------------------------------------------

    \508\ We propose to define a Long-Term Regional Transmission
Cost Allocation Method as an ex ante regional cost allocation method
that would be included in each public utility transmission
provider's OATT as part of Long-Term Regional Transmission Planning.
The developer of a Long-Term Regional Transmission Facility would be
entitled to use the Long-Term Regional Transmission Cost Allocation
Method if it is the applicable method.
    \509\ We propose to define a State Agreement Process as an ex
post cost allocation process that would be included in each public
utility transmission provider's OATT as part of Long-Term Regional
Transmission Planning, which may apply to an individual Long-Term
Regional Transmission Facility or a portfolio of such Facilities
grouped together for purposes of cost allocation. After a Long-Term
Regional Transmission Facility is selected in the regional
transmission plan for purposes of cost allocation, the State
Agreement Process would be followed to establish a cost allocation
method for that facility (if agreement can be reached). If the
Commission subsequently approves the cost allocation method that
results from the State Agreement Process, the developer of the Long-
Term Regional Transmission Facility would be entitled to use that
cost allocation method if it is the applicable method.
    \510\ For example, a ``combination'' approach may entail (i)
providing a Long-Term Regional Transmission Cost Allocation Method
for certain types of Long-Term Regional Transmission Facilities and
providing a State Agreement Process for others; or (ii) providing
for cost allocation for a Long-Term Regional Transmission Facility,
portfolio, or type of such facilities partially based on a Long-Term
Regional Transmission Cost Allocation Method and partially based on
funding contributions in accordance with a State Agreement Process.
    \511\ We are not proposing to require any changes to existing
interregional cost allocation methods for interregional transmission
facilities that are selected in the regional transmission plan for
purposes of cost allocation and that the Commission previously
accepted as compliant with Order No. 1000.
---------------------------------------------------------------------------

    303. In order to comply with this proposed requirement, public
utility transmission providers in each transmission planning region
would be required to seek the agreement of relevant state entities
within the transmission planning region regarding the Long-Term
Regional Transmission Cost Allocation Method, State Agreement Process,
or a combination thereof. We propose to require public utility
transmission providers in each transmission planning region to explain
how the proposed Long-Term Transmission Cost Allocation Method, the
proposed State Agreement Process, or a combination thereof either: (1)
Reflect the agreement of the relevant state entities, or (2) to the
extent agreement cannot be obtained, an explanation of the good faith
efforts by the relevant public utility transmission provider to seek
agreement from such entities. We seek comment below on how to resolve
the potential inability of the relevant parties to come to agreement,
noting that it will ultimately be necessary for public utility
transmission providers to have a cost allocation method on file with
the Commission for transmission facilities selected through Long-Term
Regional Transmission Planning, and recognizing a State Agreement
Process or combination cost allocation method would not comply with
this proposed rule unless the relevant public utility transmission
providers has obtained agreement from the relevant state entities.
a. Agreement of Relevant State Entities
    304. We propose to define relevant state entities for purposes of
the Long-Term Regional Transmission Planning cost allocation
requirements as any state entity responsible for utility regulation or
siting electric transmission facilities within the state or portion of
a state located in the transmission planning region, including any
state entity as may be designated for that purpose by the law of such
state. Although, as discussed below, we propose to provide public
utility transmission providers flexibility in determining what
constitutes state agreement, we preliminarily find that, for each
state, a single entity should be designated as the voting or
representative entity to avoid confusion or over-representation by a
single state in a multi-state voting process.
    305. We propose to require that public utility transmission
providers in each transmission planning region seek agreement from the
relevant state entities regarding the approach to cost allocation for
Long-Term Regional Transmission Facilities. Specifically, public
utility transmission providers in each transmission planning region
must seek to determine whether, for all or a subset of Long-Term
Regional Transmission Facilities, the relevant state entities agree to
(1) a Long-Term Regional Transmission Cost Allocation Method; (2) a
State Agreement Process; (3) forgo a role in determining the cost
allocation approach for Long-Term Regional Transmission Facilities; or
(4) some combination thereof.
    306. We further propose to afford public utility transmission
providers in each transmission planning region flexibility in the
process by which they seek agreement from the relevant state entities.
In addition, we propose to require public utility transmission
providers to provide the state entities with flexibility with regard to
defining what constitutes ``agreement'' among the relevant state
entities on the cost allocation approach for Long-Term Regional
Transmission Facilities. For example, states may choose to apply the
existing provisions for engaging with the relevant state entities.\512\
In other cases, the relevant state entities may elect to engage in new
or different ways to reach and communicate agreement regarding a cost
allocation approach for Long-Term Regional Transmission
Facilities.\513\
---------------------------------------------------------------------------

    \512\ For example, states in ISO-NE may consider NESCOE's by-
laws in defining the threshold of agreement among relevant state
entities. Likewise, states in MISO may consider OMS procedures to
define agreement and rely on existing processes by which OMS conveys
its positions to MISO.
    \513\ As discussed infra in Proposed Compliance Procedures, we
propose to establish an extended compliance period to accommodate
meaningful engagement with states with respect to this Long-Term
Regional Transmission Planning cost allocation reform.
---------------------------------------------------------------------------

    307. We note that the relevant state entities may forgo a role in
determining the cost allocation approach for all or a subset of Long-
Term Regional Transmission Facilities. In the event that the relevant
state entities do so, we propose to require public utility transmission
providers to propose a Long-Term Regional Transmission Cost Allocation
Method consistent with the requirements of Order No. 1000, including
the prohibition on relying on voluntary agreement among states or

participant funding.\514\ Relevant state entities may also fail to
reach agreement on a cost allocation method for all or a portion of
Long-Term Regional Transmission Facilities, and we request comments
below on the appropriate outcome in that situation.
---------------------------------------------------------------------------

    \514\ Under this proposed requirement, the Long-Term Regional
Transmission Cost Allocation Method that public utility transmission
providers would be required to submit would only apply to the subset
of Long-Term Regional Transmission Facilities for which the relevant
state entities did not determine a cost allocation approach.
---------------------------------------------------------------------------

    308. We clarify that we are not proposing to impose any
requirements on states to participate in processes to establish
regional cost allocation methods for Long-Term Regional Transmission
Facilities. The Commission has no authority over relevant state
entities in this regard and, as such, those entities need not engage on
a cost allocation approach if they do not wish to do so. Instead, we
propose only to require that public utility transmission providers in
each transmission planning region seek the agreement of the relevant
state entities, and demonstrate in their compliance filings how either
the proposed Long-Term Regional Transmission Cost Allocation Method,
the proposed State Agreement Process, or combination thereof: (1)
Reflects the agreement of the relevant state entities, or (2) to the
extent agreement cannot be obtained, reflects good faith efforts by the
relevant public utility transmission provider to seek agreement from
such entities.
    309. We seek comment on whether the proposed definition of relevant
state entities is appropriate. We also seek comment on the proposal to
afford relevant states entities the flexibility to define agreement
among relevant state entities, or whether it is preferable for the
Commission to adopt a specific definition of such agreement.
    310. We further recognize that it is possible that relevant states
entities may seek to agree to a cost allocation approach but be unable
to achieve agreement, or may be unwilling to seek agreement to a cost
allocation approach but do not agree to forgo their role in developing
a cost allocation approach for Long-Term Regional Transmission
Facilities. We request comment on the appropriate outcome when the
relevant state entities fail to agree on a cost allocation method for
all or a portion of Long-Term Regional Transmission Facilities.
Specifically, we request comment on whether in such circumstances the
public utility transmission providers should be required to establish a
Long-Term Regional Transmission Cost Allocation Method, the relevant
state entities should be afforded additional time to endeavor to reach
agreement, or the Commission should instead have the responsibility to
establish the Long-Term Regional Transmission Cost Allocation
Method.\515\
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    \515\ In Order No. 1000, the Commission determined that, in the
event public utility transmission providers in a region fail to
reach agreement on a cost allocation method, it would use the record
in the compliance filing to determine the cost allocation method.
Order No. 1000, 136 FERC ] 61,051 at P 607.
---------------------------------------------------------------------------

b. State Agreement Process
    311. We preliminarily find that a State Agreement Process by which
one or more relevant state entities voluntarily agree to a cost
allocation method for Long-Term Regional Transmission Facilities (or
portfolio of facilities) after it is selected in the regional
transmission plan for purposes of cost allocation may be a just and
reasonable approach to cost allocation for such regional transmission
facilities. The State Agreement Process may apply to all Long-Term
Regional Transmission Facilities or only a subset thereof.
    312. We further propose to require that a cost allocation method
that results from the State Agreement Process and is filed by the
public utility transmission providers must comply with the existing six
Order No. 1000 regional cost allocation principles.\516\ We
preliminarily find that compliance with such principles will help to
ensure that Commission-jurisdictional rates resulting from any State
Agreement Process will be just and reasonable and not unduly
discriminatory or preferential.
---------------------------------------------------------------------------

    \516\ As noted, supra, those cost principles are: (1) The costs
of transmission facilities selected in a regional transmission plan
for purposes of cost allocation must be allocated to those within
the transmission planning region that benefit from those facilities
in a manner that is at least roughly commensurate with estimated
benefits; (2) those that receive no benefit from transmission
facilities, either at present or in a likely future scenario, must
not be involuntarily allocated any of the costs of those
transmission facilities; (3) a benefit to cost threshold ratio, if
adopted, cannot exceed 1.25 to 1; (4) costs must be allocated solely
within the transmission planning region unless another entity
outside the region voluntarily assumes a portion of those costs; (5)
the method for determining benefits and identifying beneficiaries
must be transparent; and (6) there may be different regional cost
allocation methods for different types of transmission facilities,
such as those needed for reliability, congestion relief, or to
achieve Public Policy Requirements.
---------------------------------------------------------------------------

    313. If the relevant state entities decide on a State Agreement
Process, we also propose to require that the public utility
transmission providers in each transmission planning region detail the
process by which the relevant state entities would reach voluntary
agreement regarding the cost allocation for Long-Term Regional
Transmission Facilities pursuant to the State Agreement Process,
including the timeline for such processes. For example, the public
utility transmission providers in each transmission planning region
could specify, as part of the Long-Term Regional Transmission Planning
in their OATTs the procedures by which such voluntary agreements by the
relevant state entities may be filed with the Commission for
consideration under FPA section 205. Such procedures should set forth a
process by which the relevant state entities would agree to funding
contributions and the mechanism by which such costs would be allocated
(e.g., through a pro forma contract).
    314. Finally, we note that, to the extent public utility
transmission providers believe their existing cost allocation
approaches comply with the requirements adopted in any final rule in
this proceeding, including those related to the agreement of relevant
state entities, we propose that they may make such demonstration in
their compliance filings in response to any final rule. In addition, we
propose to apply the cost allocation reforms we propose in this NOPR
only to new Long-Term Regional Transmission Facilities and, therefore,
these proposed reforms would not provide grounds for re-litigation of
cost allocation decisions for transmission facilities that are selected
in the regional transmission plan for purposes of cost allocation prior
to the effective date of any final rule in this proceeding,\517\ nor
would they apply to the cost allocation methods associated with
regional transmission facilities that address shorter-term transmission
needs driven by reliability and/or economic considerations. We believe
the proposed cost allocation requirements for Long-Term Regional
Transmission Facilities will help to ensure just and reasonable
Commission-jurisdictional rates by increasing the likelihood that more
efficient or cost-effective regional transmission facilities to address
transmission needs driven by changes in the resource mix and demand are
developed, and with fewer delays. The proposed reforms would enable
relevant state entities, such as state regulators and siting
authorities, who seek greater involvement in cost allocation for Long-
Term Regional Transmission Facilities an opportunity to do so. Where
relevant state entities in a multi-state

transmission planning region are able to agree upon an approach to
allocate the costs of Long-Term Regional Transmission Facilities needed
to meet these longer-term transmission needs, applying that approach is
likely to decrease the controversy over development of such facilities,
by, for example, making the relevant state entities more confident that
ratepayers in the state are receiving benefits at least roughly
commensurate with their share of the cost of such facilities. In so
doing, the engagement of relevant state entities may help to reduce
instances in which a Long-Term Regional Transmission Facility is
selected, has an established ex ante cost allocation method that
applies to it, but nevertheless fails to be developed because it cannot
receive a necessary state regulatory approval. After all, states retain
siting authority over transmission facilities and will review whether
Long-Term Regional Transmission Facilities are consistent with the
public interest and state siting regulations.
---------------------------------------------------------------------------

    \517\ The Commission took a similar approach with respect to its
cost allocation reforms in Order No. 1000. See Order No. 1000, 136
FERC ] 61,051 at P 565.
---------------------------------------------------------------------------

    315. We recognize that, if states agree to a State Agreement
Process instead of a Long-Term Regional Transmission Cost Allocation
Method, certain Long-Term Regional Transmission Facilities selected in
the regional transmission plan for purposes of cost allocation would
lack a clear ex ante cost allocation method. We continue to believe
that the availability of an ex ante cost allocation method helps to
ensure the development of more efficient or cost-effective regional
transmission facilities identified in the regional transmission
planning process.\518\ However, given the increased uncertainty of
Long-Term Regional Transmission Planning and potential for divergent
views on the benefits of meeting transmission needs driven by changes
in the resource mix and demand, we believe that applying a cost
allocation approach agreed to by the relevant state entities may be
just and reasonable and support the viability of Long-Term Regional
Transmission Facilities.
---------------------------------------------------------------------------

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

    316. We recognize that in Order No. 1000, the Commission explained
that reliance on participant funding as a regional cost allocation
method ``increases the incentive of any individual beneficiary to defer
investment in the hopes that other beneficiaries will value a
transmission project enough to fund its development'' and would
therefore not comply with the regional cost allocation principles
adopted in Order No. 1000.\519\
---------------------------------------------------------------------------

    \519\ Order No. 1000, 136 FERC ] 61,051 at P 723. Under a
participant funding approach to cost allocation, the costs of a
transmission facility are allocated only to those entities that
volunteer to bear those costs. Id. P 486 n.375.
---------------------------------------------------------------------------

    317. Nevertheless, we preliminarily find that allowing a State
Agreement Process for Long-Term Regional Transmission Facilities, where
agreed to by the relevant state entities, appropriately balances the
concerns about increased free ridership problems against the benefit of
greater state involvement in determining the cost allocation of Long-
Term Regional Transmission Facilities.\520\ As discussed above, we are
proposing to require public utility transmission providers to engage in
transmission planning over a longer time-horizon than we have
previously required. Although we preliminarily find that such reforms
are necessary to ensure just and reasonable rates, we recognize that
the precise quantification and allocation of the benefits of Long-Term
Regional Transmission Facilities may be more uncertain than
transmission facilities that are planned on a shorter-term basis and/or
based on a more limited set of benefits. As such, we recognize that
state entities charged with siting transmission facilities within their
state may, at least in certain circumstances, take a more skeptical
approach to evaluating applications to site Long-Term Regional
Transmission Facilities. We believe that providing relevant state
entities an opportunity for involvement in establishing a cost
allocation method, including through use of a State Agreement Process,
would help to address any such concerns on the part of state
regulators, increasing the likelihood that Long-Term Regional
Transmission Facilities are actually developed, and without delay.
Accordingly, we preliminarily find that this potential benefit
outweighs concerns about free-ridership with respect to the reforms
proposed herein.
---------------------------------------------------------------------------

    \520\ Id. P 586 (stating regional cost allocation principles,
including ``[t]hose that receive no benefit from transmission
facilities, either at present or in a likely future scenario, must
not be involuntarily allocated the costs of those facilities.'').
---------------------------------------------------------------------------

    318. We seek comment on the requirements proposed in this section
of the NOPR. We also seek comment on whether the Commission should
require, instead of the reforms proposed in this section of the NOPR,
public utility transmission providers to include a Long-Term Regional
Transmission Cost Allocation Method in their OATTs.
2. Time Period in Long-Term Regional Transmission Planning Cost
Allocation Processes for State-Negotiated Alternate Cost Allocation
Method
    319. Additionally, we propose to require that public utility
transmission providers establish a process, detailed in their OATTs, to
provide a state or states (in multi-state transmission planning
regions) a time period to negotiate a cost allocation method for a
transmission facility (or portfolio of facilities) selected for
purposes of cost allocation through Long-Term Regional Transmission
Planning that is different than any ex ante regional cost allocation
method that would otherwise apply. During this time period for a state-
negotiated alternate cost allocation method, if a state or all states
within the transmission planning region in which the selected regional
transmission facility will be located unanimously agree on an alternate
cost allocation method, the public utility transmission provider may
elect to file it with the Commission for consideration under FPA
section 205. As discussed above, we anticipate the public utility
transmission provider may elect to file an alternate cost allocation
method because doing so increases the likelihood that relevant
stakeholders perceive the cost allocation as fair and that the needed
regional transmission facilities are actually constructed.
    320. If the relevant state or states cannot agree on an alternate
cost allocation method memorialized in writing within a specified
timeframe after a transmission facility is selected in the regional
transmission plan for purposes of cost allocation through Long-Term
Regional Transmission Planning (e.g., 90 days), then the transmission
developer will be entitled to use any ex ante regional cost allocation
method that would otherwise apply for that regional transmission
facility.
    321. Providing states with a time period to propose alternate cost
allocation methods could help facilitate the timely development of more
efficient or cost-effective regional transmission facilities. For
example, allowing states to negotiate an alternate cost allocation
method for selected regional transmission facilities at a time when
details of the transmission facilities are known could facilitate
agreements on the cost allocation for new regional transmission
facilities because states would have better knowledge of relevant
facts, including benefits and costs, regarding the transmission
facilities for which they are negotiating cost allocation.

Moreover, state siting proceedings may proceed more efficiently if
states have better information about the costs and benefits of such
regional transmission facilities.
    322. We propose to require that public utility transmission
providers add to their OATTs provisions that describe a time period for
state involvement in regional cost allocation for transmission
facilities selected in Long-Term Regional Transmission Planning,
including when this time period will occur, what its duration will be,
and that any alternate cost allocation method must be submitted to the
Commission for review and approval under FPA section 205 prior to
taking effect. When filed, the Commission will evaluate the alternate
cost allocation method to ensure that it is just and reasonable and
allocates costs in a manner that is at least roughly commensurate with
estimated benefits. If the Commission rejects a state-proposed cost
allocation method, the transmission developer of the transmission
facility selected in the regional transmission plan for purposes of
cost allocation through Long-Term Regional Transmission Planning would
be entitled to use the applicable ex ante regional cost allocation
method that would have applied to it in the absence of the proposed
alternative cost allocation method, just as it would be absent this
proposed provision for an alternate cost allocation method.
    323. We recognize the tension between a proposal for a time period
for state-negotiated cost allocation within an Order No. 1000-compliant
regional transmission planning process and the Commission's ex ante
cost allocation approach, which we do not propose to remove, including
the potential for delay as compared to the ex ante approach. We propose
to prescribe a 90-day time period for state-negotiated cost allocation
memorialized in writing, which is consistent with the period for state
cost allocation negotiation that the Commission accepted in NYISO's
filing described above.
    324. We seek comment on the requirements proposed in this section
of the NOPR, including the timing and duration of any time period for
state-negotiated cost allocation for transmission facilities selected
in the regional transmission plan for purposes of cost allocation
through Long-Term Regional Transmission Planning. We also seek comment
on whether there should be a requirement for a time period for state
involvement in regional cost allocation for transmission facilities
selected in existing near-term reliability and economic regional
transmission planning processes.
3. Identification of Benefits Considered in Cost Allocation for Long-
Term Regional Transmission Facilities
    325. We are concerned that the Commission's existing regional
transmission planning and cost allocation requirements may result in
public utility transmission providers undervaluing the benefits of
Long-Term Regional Transmission Facilities for purposes of allocating
the costs of such facilities to beneficiaries in a manner that is
roughly commensurate with estimated benefits. The current approach of
considering only a subset of categories of benefits based on the type
of transmission need that is being studied may result in inaccurate
valuation of a transmission facility's benefits in Long-Term Regional
Transmission Planning. We are also concerned that considering only a
subset of benefits in assigning the cost of Long-Term Regional
Transmission Facilities may contribute to the risk of free rider
problems that impede development of the more efficient or cost-
effective regional transmission facilities. At the same time, as
discussed above, we consider it important that cost allocation should
reflect the views of stakeholders, and the state entities with a role
in permitting transmission facilities in particular, and believe that
the involvement of states in cost allocation increases the likelihood
that Long-Term Regional Transmission Facilities are actually developed.
    326. Nevertheless, we acknowledge the support for the adoption of a
common set of minimum benefits, and we propose for consideration a list
of Long-Term Regional Transmission Benefits described above for public
utility transmission providers to apply in Long-Term Regional
Transmission Planning and Cost Allocation processes. In addition, we
propose to require that public utility transmission providers identify
on compliance the benefits they will use in any ex ante cost allocation
method associated with Long-Term Regional Transmission Planning, how
they will calculate those benefits, and how the benefits will
reasonably reflect the benefits of regional transmission facilities to
meet identified transmission needs driven by changes in the resource
mix and demand. As part of this compliance obligation, public utility
transmission providers should explain the rationale for using the
benefits identified.
    327. We request comment on this proposed requirement. We also
request comment on whether the Commission should require that public
utility transmission providers account for the full list of benefits
described in the Evaluation of the Benefits of Regional Transmission
Facilities section above in Long-Term Regional Transmission Planning,
or whether no change to the benefits currently used in existing
regional transmission planning processes is needed.

VI. Construction Work in Progress Incentive

A. Background

    328. In the Energy Policy Act of 2005,\521\ Congress added section
219 to the FPA, directing the Commission to establish, by rule,
incentive-based rate treatments to promote capital investment in
certain transmission infrastructure. The Commission subsequently issued
Order No. 679 in 2006, which sets forth processes by which a public
utility may seek transmission rate incentives pursuant to FPA section
219.\522\
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    \521\ Public Law 109-58, 1241, 119 Stat. 594 (2005).
    \522\ Promoting Transmission Inv. through Pricing Reform, Order
No. 679, 116 FERC ] 61,057, order on reh'g, Order No. 679-A, 117
FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 (2007).
---------------------------------------------------------------------------

    329. In Order No. 679, the Commission adopted several incentive-
based rate treatments to promote capital investment in certain
transmission infrastructure and to address impediments faced by those
investing in transmission. The Commission found that the long-lead time
to construct new transmission and associated cash flow difficulties
presented an impediment to new transmission investment.\523\ To remove
this impediment, the Commission adopted its proposal to allow for the
recovery of 100% of CWIP costs in rate base in certain circumstances
(CWIP Incentive).\524\ Allowing transmission developers to include
construction costs in rate base prior to commercial operation provides
utilities with additional cash flow in the form of an immediate earned
return, rather than delaying recovery of those costs until the plant is
placed into service.\525\ In Order No. 679, the Commission acknowledged
that the CWIP Incentive was a departure from the existing ratemaking
doctrine that rates should be based on plant costs that

are ``used and useful.'' \526\ However, the Commission clarified that
``the Commission can depart from the norm as long as it reasonably
balances consumers' interest in fair rates against investors' interest
in maintaining financial integrity and access to capital markets.''
\527\
---------------------------------------------------------------------------

    \523\ Id. P 9.
    \524\ The Commission has also provided that any public utility
engaged in the sale of electric power for resale can file to include
in rate base up to 50% of CWIP, subject to limitations. Construction
Work in Progress for Public Utilities; Inclusion of Costs in Rate
Base, Order No. 298, FERC Stats. & Regs. ] 30,455 (1983), order on
reh'g, 25 FERC ] 61,023 (1983).
    \525\ Order No. 679, 116 FERC ] 61,057 at n.70.
    \526\ Id. PP 116-117.
    \527\ Id. P 117 (quoting Jersey Cent. Power & Light Co. v. FERC,
810 F.2d 1168, 1178 (D.C. Cir. 1987)).
---------------------------------------------------------------------------

B. Need for Reform

    330. As indicated above in this NOPR, under the proposed Long-Term
Regional Transmission Planning reforms, we seek to strike a balance
between the risk of over- and under-investment regarding the selection
of transmission facilities in the regional transmission plan for
purposes of cost allocation that address transmission needs driven by
changes in the resource mix and demand. We acknowledge that there is
likely to be more uncertainty in Long-Term Regional Transmission
Planning, e.g., requiring public utility transmission providers to
conduct Long-Term Regional Transmission Planning over a minimum of 20
years (compared to the current practice of 6-15 years), than in the
existing regional transmission planning processes.
    331. In light of the incremental uncertainty associated with the
proposed Long-Term Regional Transmission Planning, we preliminarily
find that additional protection for ratepayers may be necessary to
reasonably balance consumers' interest in just and reasonable rates
against investors' interest in earning a return on their investments
and reduce the risk to ratepayers of potentially financing over-
investment in regional transmission facilities.\528\ The Commission
previously found that the CWIP Incentive is beneficial to ease the
financial pressures associated with transmission development by
providing up-front regulatory certainty, rate stability, and improved
cash flow, which in turn can result in higher credit ratings and lower
capital costs.\529\ These benefits mainly accrue to the public utility
transmission providers and their shareholders during construction,
while ratepayers mainly receive the benefits from completed
transmission facilities under a more stable rate environment.
Specifically, during the construction of the regional transmission
facilities, ratepayers do not receive benefits from the regional
transmission facilities, while simultaneously ratepayers directly
finance the construction under the CWIP Incentive. Should the regional
transmission facilities not be placed in service, then ratepayers will
have financed the construction of such facilities that were not used
and useful, while ultimately receiving no benefits from such
facilities.
---------------------------------------------------------------------------

    \528\ See, e.g., NextEra Energy Transmission Sw., LLC, 178 FERC
] 61,082 (2022) (Christie, Comm'r, concurring).
    \529\ Order No. 679, 116 FERC ] 61,057 at P 115.
---------------------------------------------------------------------------

    332. Given the Long-Term Regional Transmission Planning reforms
proposed in this NOPR and the incremental uncertainty and risk that
Long-Term Regional Transmission Facilities may not become ``used and
useful,'' we are concerned that the CWIP Incentive, if made available
for Long-Term Regional Transmission Facilities, may shift too much risk
to consumers to the benefit of public utility transmission providers in
a manner that renders Commission-jurisdictional rates unjust and
unreasonable.

C. Proposed Reform

    333. To address the concerns identified above, we propose to not
permit public utility transmission providers to take advantage of the
CWIP Incentive for Long-Term Regional Transmission Facilities. We note
that public utility transmission providers may still book costs
incurred during the pre-construction or construction phase as Allowance
for Funds Used During Construction (AFUDC) and only recover those costs
after the project is in service to customers, in accordance with
generally accepted utility accounting principles for AFUDC.\530\
---------------------------------------------------------------------------

    \530\ We further note that our proposal regarding the CWIP
Incentive for Long-Term Regional Transmission Facilities does not
affect Commission policy and regulations established before Order
No. 679. That is, public utility transmission providers would still
be allowed to request 50% CWIP in rate base, as is permitted
pursuant to 18 CFR 35.25(c)(3), subject to an FPA section 205 filing
detailing how the request meets the requirements of Order No. 298.
We believe that the ability to include 50% CWIP in rate base, if
requested and granted, reflects a more reasonable sharing of risks
and benefits than the CWIP Incentive for Long-Term Regional
Transmission Facilities given the greater uncertainty inherent in
Long-Term Regional Transmission Planning, as proposed in this NOPR.
---------------------------------------------------------------------------

    334. We seek comment on the requirements proposed in this section
of the NOPR. In particular, we seek comment on whether this proposed
reform would reasonably balance consumer and investor interests.

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

    335. Order No. 1000 instituted a number of reforms regarding the
participation of nonincumbent transmission developers in the regional
transmission planning process, which, as a whole, facilitate
competition for transmission development.\531\ As explained in more
detail below, we continue to require compliance with Order No. 1000's
nonincumbent transmission developer reforms, and we maintain our
commitment to transmission development rules and policies that align
with or advance the goals of those reforms, or otherwise ensure just
and reasonable Commission-jurisdictional rates and limit opportunities
for undue discrimination by public utility transmission providers.
---------------------------------------------------------------------------

    \531\ See ISO New Eng. Inc., 169 FERC ] 61,054, at PP 1-2 (2019)
(citations omitted); see also Order No. 1000, 136 FERC ] 61,051 at
PP 225-344.
---------------------------------------------------------------------------

    336. However, in light of the experience gained since the issuance
of Order No. 1000 and the comments received in response to the ANOPR,
we propose to amend Order No. 1000's nonincumbent transmission
developer requirements, in part. As described in more detail below, we
propose to permit the exercise of federal rights of first refusal for
transmission facilities selected in a regional transmission plan for
purposes of cost allocation, conditioned on the incumbent transmission
provider with the federal right of first refusal for such regional
transmission facilities establishing joint ownership of the
transmission facilities consistent with the proposal below.

A. Background

1. Order No. 1000's Nonincumbent Transmission Developer Reforms and
Federal Right of First Refusal Elimination Mandate
    337. In instituting nonincumbent transmission developer reforms,
the Commission in Order No. 1000 distinguished between incumbent
transmission developers (also called incumbent transmission providers)
and nonincumbent transmission developers. An incumbent transmission
developer/provider is an entity that develops a transmission facility
within its own retail distribution service territory or footprint. A
nonincumbent transmission developer refers to two categories of
transmission developer: (1) A transmission developer that does not have
a retail distribution service territory or footprint; and (2) a public
utility transmission provider that proposes a transmission facility
outside of its existing retail distribution service territory or
footprint, where it is not the incumbent for purposes of that
facility.\532\
---------------------------------------------------------------------------

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

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

utility transmission provider eliminate provisions in Commission-
jurisdictional tariffs and agreements that establish a federal right of
first refusal for an incumbent transmission provider with respect to
entirely new transmission facilities selected in a regional
transmission plan for purposes of cost allocation.\533\
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    \533\ Id. P 313; Order No. 1000-A, 139 FERC ] 61,132 at P 426
(``The concept is that there should not be a federally established
monopoly over the development of an entirely new transmission
facility that is selected in a regional transmission plan for
purposes of cost allocation to others.''). The phrase ``a federal
right of first refusal'' refers only to rights of first refusal that
are created by provisions in Commission-jurisdictional tariffs or
agreements. Order No. 1000-A, 139 FERC ] 61,132 at P 415. Before
Order No. 1000, some RTO/ISO governing documents and other utility
tariffs and agreements included federal rights of first refusal,
which ``gave incumbent utilities the option to construct any new
transmission facilities in their particular service areas, even if
the proposal for new construction came from a third party.'' S.C.
Pub. Serv. Auth., 762 F.3d at 72.
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    339. This requirement from Order No. 1000 does not apply to local
transmission facilities, which are defined as transmission facilities
located solely within an incumbent transmission provider's retail
distribution service territory or footprint that are not selected in
the regional transmission plan for purposes of cost allocation.\534\
The requirement also does not apply to the right of an incumbent
transmission provider to build, own, and recover costs for upgrades to
its own existing transmission facilities, regardless of whether an
upgrade has been selected in the regional transmission plan for
purposes of cost allocation.\535\ In addition, the Commission noted
that the requirement does not remove, alter, or limit an incumbent
transmission provider's use and control of its existing rights-of-way
under state law.\536\ The Commission has also permitted exemptions from
the federal right of first refusal elimination mandate for immediate
need reliability projects.\537\
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    \534\ Order No. 1000, 136 FERC ] 61,051 at PP 63, 226, 258, 318.
In addition, the Commission clarified in Order No. 1000-A that a
transmission facility whose costs are 100% allocated to the public
utility transmission provider in whose retail distribution service
territory or footprint the facility is located is not considered to
be selected in the regional transmission plan for purposes of cost
allocation and could remain subject to a federal right of first
refusal. Order No. 1000-A, 139 FERC ] 61,132 at PP 423-424; see also
id. P 427.
    \535\ Order No. 1000, 136 FERC ] 61,051 at PP 226, 319; Order
No. 1000-A, 139 FERC ] 61,132 at P 426. Upgrades to existing
transmission facilities include, for example, tower change outs or
reconductoring, regardless of whether or not an upgrade has been
selected in the regional transmission plan for purposes of cost
allocation. Order No. 1000, 136 FERC ] 61,051 at P 319. The
Commission clarified in Order No. 1000-A that the term ``upgrade''
means an improvement to, addition to, or replacement of a part of,
an existing transmission facility. The term does not refer to an
entirely new transmission facility. Order No. 1000-A, 139 FERC ]
61,132 at P 426.
    \536\ Order No. 1000, 136 FERC ] 61,051 at PP 226, 319.
    \537\ See, e.g., PJM Interconnection, L.L.C., 174 FERC ] 61,117,
at P 3 (2021); Sw. Power Pool, Inc., 171 FERC ] 61,213, at P 3
(2020); Midcontinent Indep. Sys. Operator, Inc., 173 FERC ] 61,203,
at P 1 (2020); ISO New Eng. Inc., 171 FERC ] 61,211, at P 1, 3
(2020); N.Y. Indep. Sys. Operator, Inc., 171 FERC ] 61,082, at PP
30-34 (2020).
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    340. In adopting Order No. 1000's nonincumbent transmission
developer reforms, the Commission identified several reasons why it
believed that eliminating federal rights of first refusal from
Commission-jurisdictional tariffs and agreements was necessary and
appropriate to ensure that Commission-jurisdictional rates are just and
reasonable. The Commission found that federal rights of first refusal
``creat[e] a barrier to entry,'' and that their existence could lead to
the loss of nonincumbent transmission developer investment
opportunities to incumbent transmission providers, which ``discourages
nonincumbent transmission developers from proposing alternative
solutions for consideration at the regional level'' in regional
transmission planning processes.\538\ The Commission found that
administering transmission planning processes with federal rights of
first refusal ``may result in the failure to consider more efficient or
cost-effective solutions to regional needs'' and thus their elimination
may give ``customers . . . the benefits of competition in transmission
development, and associated potential savings.'' \539\ The Commission
also expressed concern that federal rights of first refusal could allow
an incumbent transmission provider ``to act in its own economic self-
interest,'' which in general would not support permitting ``new
entrants to develop transmission facilities, even if proposals
submitted by new entrants would result in a more efficient or cost-
effective solution to the region's needs.'' \540\
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    \538\ Order No. 1000, 136 FERC ] 61,051 at PP 229, 256-257, 284,
320.
    \539\ Id. PP 284-286, 291; see also id. PP 229, 315. The
Commission reasoned, in part, that ``[g]reater participation by
transmission developers in the transmission planning process may
lower the cost of new transmission facilities, enabling more
efficient or cost-effective deliveries by load serving entities and
increased access to resources.'' Id. P 291.
    \540\ Id. P 256.
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    341. The Commission also found that elimination of federal rights
of first refusal was ``necessary to address opportunities for undue
discrimination and preferential treatment against nonincumbent
transmission developers within regional transmission planning
processes.'' \541\ While the Commission did not dispute the claim that
incumbent transmission providers may have some inherent advantages over
nonincumbent transmission developers in the transmission development
context,\542\ the Commission found that these claimed incumbent
advantages were ``strengths'' that could be deployed by incumbent
transmission providers to their benefit in competitive transmission
development processes, and not a reason to forgo holding those
processes.\543\
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    \541\ Order No. 1000-A, 139 FERC ] 61,132 at P 361; see also
Order No. 1000, 136 FERC ] 61,051 at PP 269, 286. The Commission
also reiterated that ``if a regional transmission planning process
does not consider and evaluate transmission projects proposed by
nonincumbents that regional transmission planning process cannot
meet the Order No. 890 transmission planning principle of being
`open.' '' Order No. 1000, 136 FERC ] 61,051 at P 229.
    \542\ See Order No. 1000, 136 FERC ] 61,051 at P 260
(acknowledging that incumbent transmission providers ``may have
unique knowledge of their own transmission systems, familiarity with
the communities they serve,'' and other potential transmission
development advantages); see also id. PP 241, 250 (summarizing other
contentions ``that incumbent transmission owners are better situated
to build new transmission facilities'').
    \543\ Id. P 260.
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    342. Importantly, while the Commission declined to eliminate
federal rights of first refusal for upgrades to existing transmission
facilities and local transmission facilities, among other specific
types of transmission facilities,\544\ and has permitted exemptions for
immediate need reliability projects,\545\ the Commission did not
otherwise qualify or limit the federal right of first refusal
elimination mandate within its defined scope (i.e., as applied to
entirely new transmission facilities selected in a regional
transmission plan for purposes of cost allocation).\546\ Instead, the

Commission ordered, with limited exceptions, the elimination of federal
rights of first refusal for entirely new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation, regardless of the specifics of or the circumstances under
which such federal rights of first refusal had been or could be used.
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    \544\ See supra notes 534-536 and associated text. The
Commission explained, in part, that its decision in this regard
would ``continue[ ] to permit an incumbent . . . to meet its
reliability needs or service obligations'' through local
transmission facilities, and the Commission hoped that this
exemption would also, in part, address concerns that Order No.
1000's reforms would ``adversely impact the collaborative nature of
current regional transmission planning processes.'' See Order No.
1000, 136 FERC ] 61,051 at PP 258, 262.
    \545\ See supra note 537 and associated text.
    \546\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 426
(``The concept is that there should not be a federally established
monopoly over the development of an entirely new transmission
facility that is selected in a regional transmission plan for
purposes of cost allocation to others.''); id. P 360 (finding on
rehearing that ``the Commission's decision to require public utility
transmission providers to adopt the nonincumbent transmission
developer reforms was an appropriate, and adequately tailored,
remedy'' and noting that the Commission did not accept the position
of some commenters that ``supported eliminating all federal rights