are examples of portfolio approaches to regional transmission cost
allocation. We seek comment on whether a portfolio approach recognizes
that a regional transmission planning process that considers a group of
transmission facilities that collectively provide multiple benefits,
including reliability, economic, and Public Policy Requirements
benefits, among others, may be able to better identify more efficient
or cost-effective transmission facilities when compared to a process
that focuses only on individual transmission facilities or individual
benefits. We seek comment on whether an approach that both estimates
broader transmission benefits for regional transmission facilities
beyond those that are currently considered and that also allocates the
costs for a portfolio of those individual transmission facilities may
provide a cost allocation method that better matches benefits to
burdens over time.\106\ We seek comment on whether such an approach may
also be more accurate or less likely to lead to anomalous results.
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    \106\ See BNP Paribas Energy, 743 F.3d at 268-69 (framing the
cost causation principle ``as a matter of making sure that burden is
matched with benefit'').
---------------------------------------------------------------------------

    92. At the same time, we seek comment on whether there are
circumstances in which the use of criteria other than reliability and
economic considerations may result in projects being selected in the
regional transmission plan for purposes of cost allocation that do not
represent the optimal solution to the reliability or congestion
problems identified and thus may not represent the most efficient or
cost-effective solution for customers of the load serving entities both
inside an RTO/ISO and in non-RTO/ISO region. Any proposals for changes
to planning criteria and cost allocation should consider whether such
proposals result in unjustly and unreasonably shifting costs to
customers. We seek comment on whether the use of planning criteria
beyond reliability and economic considerations may place the burden for
the costs driven by Public Policy Requirements of one state on
customers of load serving entities in non-participating states.
    93. We seek comment on the current approaches that transmission
providers take in defining transmission benefits for purposes
transmission planning and cost allocation. For example, we are
interested in how transmission providers calculate adjusted production
costs, the extent to which transmission providers go beyond adjusted
production costs in identifying transmission benefits, the types of
benefits, and the methods for estimating. We also seek comment on the
extent to which it may be challenging, for certain types of benefits,
to identify the beneficiaries for cost allocation purposes. We seek
comment on the extent to which the same set of benefits is currently
used in regional transmission planning processes and their associated
cost allocation processes, or whether some benefits are identified but
not factored into cost allocation. Should the same set of benefits be
used in all processes? If not, would it be appropriate to consider
different benefits during the transmission planning and cost allocation
stages? If so, what would be the basis for doing so?
    94. We seek comment on the types of benefits provided by
transmission facilities needed to meet the transmission needs of
anticipated future generation that are relevant for cost allocation
purposes and the manner in which those benefits can be quantified, if
at all. This includes consideration of whether there are transmission
benefits beyond those that transmission providers already take into
account in allocating costs that the Commission should require all
transmission providers to consider for regional transmission
facilities. In other words, should the Commission require transmission
providers to establish a broader set of transmission benefits for
purposes of cost allocation than currently in use and, likewise, should
the Commission adopt a minimum set of transmission benefits that must
be considered? Such benefits could encompass economic benefits (e.g.,

congestion reduction); resource adequacy benefits (e.g., allowing
imports to replace more expensive local generation, lowering required
planning targets through increased diversity benefits); and reliability
benefits (e.g., avoided or deferred reliability transmission
facilities, improved reserves sharing, increased voltage support). And
to what extent are there benefits that will differ from region-to-
region?
    95. If there are types of benefits that cannot be quantified, but
which are real and relevant to allocating the costs of regional
transmission facilities roughly commensurate with benefits, we seek
comment on how transmission providers can document and account for
those benefits in crafting a cost allocation method. Similarly, we seek
comment on whether the inability to precisely quantify benefits of
transmission facilities can be a barrier to the development of those
facilities, particularly those with potentially broad transmission
benefits. If so, we are interested in what types of transmission
facilities are most impacted and what types of benefits are typically
associated with those types of transmission facilities, and how those
benefits can be justified and quantified.
    96. To the extent that there are relevant benefits that are
difficult to quantify, we seek comment on ways in which the Commission
can consider whether those benefits are appropriately credited to a
regional transmission facility and accounted for as part of allocating
the costs to beneficiaries. This includes consideration of when
benefits of a transmission facility are sufficiently certain to justify
a commensurately broad cost allocation, especially where those benefits
are not susceptible to precise quantification. We also seek comment on
whether it is appropriate to credit benefits that cannot be credibly
quantified and whether, and if so, how, it is appropriate to factor
such benefits into regional cost allocation.
    97. In addition to identifying benefits, we also seek comment on
best practices for identifying the beneficiaries of a transmission
facility. For example, some interconnection-related network upgrades
for generator interconnection may benefit more than a single
interconnecting generator, however the scope (temporal and geographic)
of such beneficiaries may not be clear. We seek comment on the efficacy
and desirability of a regional transmission planning and cost
allocation process that seeks to plan for future scenarios, including
planning for anticipated future generation. What methods for
ascertaining beneficiaries are most effective in allocating the costs
of such facilities roughly commensurate with benefits? Are there
threshold transmission system conditions that would enable the
Commission to reasonably conclude that regional (or some greater or
lesser geographical scope) allocation of costs is appropriate (such as
the amount of congestion or level of interconnectedness in a particular
area)? This necessarily links to our earlier questions about how to
quantify benefits and what level of precision is required.
    98. Along the same lines of identifying beneficiaries, we seek
comment on whether the costs of transmission facilities planned in the
regional transmission planning process for which we seek comment in
this ANOPR should be allocated to both transmission and interconnection
customers. As explained earlier, we are concerned about potential free-
rider problems associated with interconnection customers that later
connect to transmission facilities planned for anticipated future
generation. We are therefore interested in approaches to cost
allocation to ensure that both transmission and interconnection
customers that benefit from those facilities pay their fair share.
While we propose to potentially reform participant funding by
interconnection customers of interconnection-related network upgrades,
we are also considering how best to allocate costs of regional
transmission facilities to interconnection customers (e.g., whether
cost allocation methods for regional transmission facilities should
allocate a portion of the costs of a regional transmission facility
directly to interconnection customers based on, for example, the
capacity of the interconnection customer's generating facility).
    99. We seek comment on the cost effectiveness of the reforms
discussed herein. If the regional transmission planning and cost
allocation processes are to consider transmission needs driven by
anticipated future generation, is there a tradeoff between facilitating
the construction of transmission facilities that are needed to connect
such anticipated future generation, and ensuring against building more
transmission than is necessary? If so, how should the Commission
approach that tradeoff?
3. Participant Funding and Crediting Policy for Funding
Interconnection-Related Network Upgrades
    100. Since the issuance of Order No. 2003, the composition of the
generation fleet has rapidly shifted from predominately large,
centralized resources to include a large proportion of smaller
renewable generators that, due to their distance from load centers,
often require extensive interconnection-related network upgrades to
interconnect to the transmission system. The significant
interconnection-related network upgrades necessary to accommodate
geographically remote generation are a result that the Commission did
not contemplate when it established the interconnection pricing policy
for interconnection-related network upgrades. Because the large-scale
changes since Order No. 2003 may have impacted the underlying rationale
for the interconnection pricing policy, we seek comment on whether the
Commission should modify the participant funding and crediting
policies, as discussed in further detail below.
a. Background
i. Original Rationale for the Order No. 2003 Interconnection-Related
Network Upgrade Funding Requirements
    101. As discussed above, the Commission in Order No. 2003 described
two general approaches for assigning the costs of interconnection-
related network upgrades needed to interconnect a generating facility
to the transmission system: (1) the crediting policy, whereby the
interconnection customer initially funds the interconnection-related
network upgrades and is reimbursed through transmission credits; \107\
and (2) participant funding, where the costs of interconnection-related
network upgrades in RTOs/ISOs are assigned directly to the
interconnection customer. Central to discussions of the Commission's
interconnection-related network upgrade funding requirements is Order
No. 2003's continued prohibition of ``and'' pricing. This prohibition
provides that, when ``a Transmission Provider must construct

[interconnection-related] Network Upgrades to provide new or expanded
transmission service, the Commission generally allows the Transmission
Provider to charge the higher of the embedded costs of the Transmission
System with expansion costs rolled in, or incremental expansion costs,
but not the sum of the two.'' \108\ The Commission also explained that
allowing the transmission provider to charge either the higher of an
embedded cost rate for transmission service or an incremental rate
designed to recover the cost of the interconnection-related network
upgrades ``provides the Transmission Provider with a cost recovery
mechanism that ensures that native load and other transmission
customers will not subsidize service to the Interconnection Customer.''
\109\
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    \107\ Order No. 2003-B states that ``the period for
reimbursement may not be longer than the period that would be
required if the Interconnection Customer paid for transmission
service directly and received credits on a dollar-for-dollar basis,
or 20 years [from the generating facility's commercial operation
date], whichever is less.'' Order No. 2003-B, 109 FERC ] 61,287 at
PP 3, 36. If credits have not fully reimbursed the upfront payment
within 20 years, Order No. 2003 requires ``a balloon payment'' at
the end of year 20. Id. P 36. The crediting policy also requires
that affected system operators provide credits for transmission
service taken on an affected system. Id. P 42. Even if the
interconnection customer does not take transmission service over the
affected system, however, the affected system operator must still
provide the 20-year balloon payment to refund any remaining balance
to the interconnection customer. Order No. 2003-C, 111 FERC ] 61,401
at P 13.
    \108\ Order No. 2003, 104 FERC ] 61,103 at n.111.
    \109\ Order No. 2003-A, 106 FERC ] 61,220 at P 613.
---------------------------------------------------------------------------

(a) Crediting Policy
    102. The Commission instituted the crediting policy to achieve
multiple objectives. First, the Commission found that this policy would
avoid prohibited ``and'' pricing for interconnection-related network
upgrades because it ensures that the interconnection customer will not
be charged twice for the use of the transmission system by paying both
for the incremental cost of the upgrade and an embedded-cost rate (with
the cost of that interconnection-related network upgrade rolled in) for
use of the transmission system.\110\ Also, the Commission stated that
the crediting policy was intended to facilitate the efficient
construction of interconnection-related network upgrades and enhance
competition in bulk power markets by promoting the construction of new
generation \111\ Furthermore, the Commission found that the crediting
policy would ensure comparable treatment for interconnection customers
that are not affiliated with the transmission provider, as transmission
providers traditionally roll the costs of interconnection-related
network upgrades associated with their own generating facilities into
their transmission rates.\112\
---------------------------------------------------------------------------

    \110\ Order No. 2003, 104 FERC ] 61,103 at P 694.
    \111\ Id. PP 612, 694.
    \112\ Id. P 694.
---------------------------------------------------------------------------

    103. Additionally, in Order No. 2003-A, the Commission stated that
it does ``not believe that the costs of [interconnection-related]
Network Upgrades required to interconnect a Generating Facility to the
Transmission System of a non-independent Transmission Provider are
properly allocable to the Interconnection Customer through direct
assignment because upgrades to the transmission grid benefit all
customers.'' \113\ The Commission also stated that the crediting policy
has a two-fold purpose. First, by providing the transmission provider
with a source of funds to construct the interconnection-related network
upgrades, the upfront payment by the interconnection customer
alleviates any delay that might result if the transmission provider
were forced to secure funding elsewhere. Second, by placing the
interconnection customer initially at risk for the full cost of the
interconnection-related network upgrades, the upfront payment provides
the interconnection customer with a strong incentive to make efficient
siting decisions and, in general, to make good faith requests for
interconnection service.\114\
---------------------------------------------------------------------------

    \113\ Order No. 2003-A, 106 FERC ] 61,220 at P 212. As noted in
the discussion below on participant funding, the Commission has
allowed direct assignment of interconnection-related network upgrade
costs to generators interconnecting to independent transmission
providers such as RTOs/ISOs.
    \114\ Id. P 613.
---------------------------------------------------------------------------

    104. In NARUC v. FERC,\115\ multiple petitioners challenged the
crediting policy established in Order No. 2003. The petitioners argued
that the crediting policy was inconsistent with the cost causation
principle because they disagreed with the Commission's conclusions that
``[interconnection-related] Network Upgrades benefit the entire
network,'' \116\ and therefore, all transmission customers should
essentially pay for those interconnection-related network upgrades
through the crediting policy.\117\ The U.S. Court of Appeals for the
District of Columbia Circuit (D.C. Circuit) agreed with the
Commission's position and noted that the D.C. Circuit had previously
``endorsed the approach of `assign[ing] the costs of system-wide
benefits to all customers on an integrated transmission grid.' '' \118\
---------------------------------------------------------------------------

    \115\ 475 F.3d 1277.
    \116\ Id., 475 F.3d at 1285.
    \117\ Id. (citing Pub. Serv. Co. of Colo., 62 FERC ] 61,013, at
61,061 (1993)).
    \118\ Id. (citing W. Mass. Elec. Co. v. FERC, 165 F.3d 922, 927
(DC Cir. 1999)).
---------------------------------------------------------------------------

(b) Participant Funding
    105. In Order No. 2003, the Commission stated that ``under the
right circumstances, a well-designed and independently administered
participant funding policy for [interconnection-related] Network
Upgrades offers the potential to provide more efficient price signals
and a more equitable allocation of costs than the crediting approach.''
\119\ Therefore, the Commission stated that it would provide RTOs/ISOs
with the flexibility to propose participant funding for
interconnection-related network upgrades for a generator
interconnection.\120\ In accordance with this flexibility, the
Commission did not prescribe specific policies for RTOs/ISOs but
instead provided them with the flexibility to adopt policies of their
own choosing, subject to Commission approval.\121\ Over time, each RTO/
ISO sought, and the Commission accepted, independent entity variations
to adopt some form of participant funding rather than the crediting
policy.
---------------------------------------------------------------------------

    \119\ Order No. 2003, 104 FERC ] 61,103 at P 695.
    \120\ Id. P 28.
    \121\ Order No. 2003-A, 106 FERC ] 61,220 at P 696.
---------------------------------------------------------------------------

    106. The Commission expressed its willingness to consider a well-
designed participant funding approach in response to commenter concerns
that the crediting policy ``mutes somewhat the Interconnection
Customer's incentive to make an efficient siting decision that takes
new transmission costs into account, and it provides the
Interconnection Customer with what many view as an improper subsidy,
particularly when the Interconnection Customer chooses to sell its
output off-system.'' \122\ Additionally, while the Commission mandated
the crediting policy for non-independent transmission providers, Order
No. 2003 acknowledged that the concerns that gave rise to the adoption
of the crediting policy do not apply to RTOs/ISOs. For example, Order
No. 2003 noted that ``a number of aspects of the `but for' approach are
subjective, and a Transmission Provider that is not an independent
entity has the ability and the incentive to exploit this subjectivity
to its own advantage'' by, for example, finding ``that a
disproportionate share of the costs of expansions needed to serve its
own power customers is attributable to competing Interconnection
Customers.'' \123\ In contrast, however, the Commission noted that RTOs
and ISOs are independent, and neither own nor have affiliates that own
generating facilities and thus do not have an incentive to discourage
new generation by competitors.\124\
---------------------------------------------------------------------------

    \122\ Order No. 2003, 104 FERC ] 61,103 at P 695.
    \123\ Id. n.111.
    \124\ Order No. 2003-A, 106 FERC ] 61,220 at P 691.
---------------------------------------------------------------------------

    107. The Commission also explained that participant funding might
speed up the development of new transmission infrastructure. In
particular, Order No. 2003 postulated that ``participant

funding of [interconnection-related network] upgrades may provide the
pricing framework needed to overcome the reluctance of incumbent
Transmission Owners in many parts of the country to build transmission,
with the result that badly needed transmission infrastructure could be
put in place quickly.'' \125\
---------------------------------------------------------------------------

    \125\ Order No. 2003, 104 FERC ] 61,103 at P 703.
---------------------------------------------------------------------------

    108. RTOs/ISOs that have adopted a participant funding approach do
not reimburse interconnection customers with transmission service
credits for the cost of the interconnection-related network upgrades.
Instead, the Commission allowed interconnection customers to receive
well-defined capacity rights that are created by the interconnection-
related network upgrades.\126\ As an example, the Commission in Order
No. 2003 pointed to PJM Firm Transmission Rights and Capacity
Interconnection Rights, which, it stated, are ``created by the
[interconnection-related] Network Upgrades for which the
Interconnection Customer pays, and they are well-defined, long-term and
tradeable.'' \127\ The Commission stated that provision of such ``well-
defined capacity rights'' in lieu of credits does not violate the
prohibition of ``and'' pricing because the ``Interconnection Customer
pays separate charges for separate services,'' namely ``an access
charge for transmission service that may involve an obligation to pay
congestion charges, and in exchange for its `but for' payment, [the
interconnection customer] receives these well-defined capacity rights,
which provide some protection for having to actually pay the congestion
charges.'' \128\
---------------------------------------------------------------------------

    \126\ Id. P 700.
    \127\ Id.
    \128\ Id.
---------------------------------------------------------------------------

    109. Commission precedent makes clear that the purpose of providing
``well-defined'' rights is not to provide full reimbursement for the
costs of interconnection-related network upgrades. In fact, where an
RTO/ISO adopts a participant funding approach for interconnection-
related network upgrades required to interconnect an interconnection
customer, there is no requirement that the capacity rights being
awarded for interconnection-related network upgrades have equal value
to the cost of the interconnection-related network upgrades because the
costs would not exist ``but for'' the proposed interconnection and are
simply part of a project's construction costs and business risk that
the interconnection customer must consider.\129\ Moreover, RTOs/ISOs
are ``not required to provide transmission capacity rights where . . .
the network upgrades create no additional transmission capability.''
\130\ To this point, the Commission in Old Dominion Electric
Cooperative v. PJM Interconnection, L.L.C. explained that, while Order
No. 2003 ``stated that generation interconnection customers would
receive capacity rights, those statements were based on the assumption
that a network upgrade provided by an interconnection customer would
create additional transmission capability beyond that needed to simply
interconnect with the grid.'' \131\
---------------------------------------------------------------------------

    \129\ PJM Interconnection, L.L.C., 108 FERC ] 61,025, at P 20
(2004); see also Midwest Indep. Transmission Sys. Operator, Inc.,
114 FERC ] 61,106, at P 66 (2006).
    \130\ Old Dominion Elec. Coop. v. PJM Interconnection, L.L.C.,
119 FERC ] 61,052, at P 18 (2007) (ODEC v. PJM).
    \131\ ODEC v. PJM, 119 FERC ] 61,052 at P 18; see also id. P 16
(``Not every system upgrade required simply to interconnect a
generating facility safely to the grid entitles the generator to
capacity rights; however, a generation interconnection customer
would be `allowed to receive' capacity rights if a [interconnection-
related] network upgrade creates additional transmission
capability.'').
---------------------------------------------------------------------------

    110. Again, each RTO/ISO sought an independent entity variation to
adopt a participant funding approach rather than adopt the crediting
policy. In MISO, an interconnection customer is responsible for 100% of
interconnection-related network upgrade costs, with a possible 10%
reimbursement or ``crediting'' for interconnection-related network
upgrades that are 345 kV and above.\132\ In CAISO, the interconnection
customer's cost responsibility for a particular interconnection-related
network upgrade depends on how CAISO classified the interconnection-
related network upgrade (i.e., whether the interconnection-related
network upgrade is considered area, local, or reliability) and the
interconnection-related network upgrade's deliverability status (e.g.,
full capacity, partial capacity, or energy-only).\133\ In CAISO, full
cash reimbursement is only available for the costs of certain
categories of interconnection-related network upgrades, up to $60,000
per MW of installed generation capacity, and interconnecting generators
receive congestion revenue rights in exchange for funding any upgrades
that are not eligible for cash reimbursement. SPP, NYISO, PJM, and ISO-
New England, Inc. use a participant funding approach where the
transmission provider assigns 100% of the interconnection-related
network upgrade costs to the interconnection customer and the
interconnection customer may receive compensation through transmission
capacity rights.\134\
---------------------------------------------------------------------------

    \132\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 164
FERC ] 61,158, at P 5 (2018) (``MISO's Interconnection Customer
Funding Policy . . . requiring the interconnection customer to
`participant fund' 90-100 percent of its [interconnection-related]
network upgrades . . . was accepted, under the Order No. 2003
independent entity variation standard in 2009.''); Midwest Indep.
Transmission Sys. Operator, Inc., 129 FERC ] 61,060, at P 8 (2009)
(accepting MISO's ``proposed change [that] would result in the
interconnection customer bearing 100 percent of the costs of
[interconnection-related] network upgrades rated below 345 kV and
bearing 90 percent of the costs of [interconnection-related] network
upgrades rated at 345 kV and above (with the remaining 10 percent
being recovered on a system-wide basis'')); Midwest Indep. Trans.
Sys. Operator, Inc., 114 FERC ] 61,106, at P 62 (2006).
    \133\ Cal. Indep. Sys. Operator Corp., 140 FERC ] 61,070, at PP
24-27 (2012).
    \134\ PJM Interconnection, L.L.C., 108 FERC ] 61,025 (2004); Sw.
Power Pool, Inc., 127 FERC ] 61,283 (2009); Sw. Power Pool, Inc.,
171 FERC ] 61,272 (2020); N.Y. Indep. Sys. Operator, Inc., 108 FERC
] 61,159 (2004), order on reh'g, 111 FERC ] 61,347 (2005); ISO New
Eng. Inc., 133 FERC ] 61,229 (2010).
---------------------------------------------------------------------------

b. Potential Need for Reform
i. Participant Funding
    111. Since the issuance of Order No. 2003, changing circumstances
have cast doubt on whether it continues to be just and reasonable to
provide RTOs/ISOs with the flexibility to adopt participant funding
approaches for interconnection-related network upgrades. We seek
comment on whether these developments suggest that the allowance of
participant funding for interconnection-related network upgrades, both
as a concept and in its application, may no longer be just and
reasonable. Moreover, it appears that the incentives created by
participant funding in this context may produce outcomes that are
counter to the Commission's intentions in allowing flexibility for
RTOs/ISOs to adopt participant funding in Order No. 2003.
    112. To begin with, participant funding may allocate the costs of
extensive interconnection-related network upgrades entirely to
interconnection customers without accounting for the significant
benefits that these interconnection-related network upgrades may
provide to transmission customers. As a result, there are circumstances
where this allocation of interconnection-related network upgrade costs
may not be roughly commensurate with the distribution of benefits. For
instance, a large interconnection-related network upgrade built on a
consistently congested portion of the transmission system may provide
significant

economic and reliability benefits to transmission customers. Also,
transmission customers, in some instances, can make use of any excess
transmission capacity created by a participant funded interconnection-
related network upgrade without paying any of the capital costs that
are paid for through a participant funding approach. Allowing
transmission customers to receive the benefits of interconnection-
related network upgrades without paying for a proportionate share of
their costs is an example of the ``free rider'' problem that the
Commission's ``beneficiary pays'' cost causation principle is supposed
to avoid.\135\
---------------------------------------------------------------------------

    \135\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 562
(``Given the nature of transmission operations, it is possible that
an entity that uses part of the transmission grid will obtain
benefits from transmission facility enlargements and improvements in
another part of that grid regardless of whether they have a contract
for service on that part of the grid and regardless of whether they
pay for those benefits. This is the essence of the `free rider'
problem the Commission is seeking to address through its cost
allocation reforms.'').
---------------------------------------------------------------------------

    113. Furthermore, while the interconnection customer may receive
well-defined capacity rights associated with the increased transfer
capability caused by the interconnection-related network upgrade, these
well-defined capacity rights do not compensate the interconnection
customer for the broad range of benefits that the interconnection-
related network upgrades can provide to the transmission system and
therefore do not solve the ``free rider'' problem. This is because the
well-defined capacity rights do not capture reductions in congestion
costs paid by transmission customers that were the result of the
expansion of the transfer capability created by the interconnection-
related network upgrade; nor do they capture transmission service
charges for use of the excess capacity created by the interconnection-
related network upgrade. Instead, well-defined capacity rights capture
congestion costs paid by transmission customers on a going forward
basis across the relevant transmission path on which the
interconnection-related network upgrade increased transmission
capacity. To the extent that the interconnection-related network
upgrade may have eliminated most of the ex ante congestion on the
relevant paths, the transmission customers that transact across such
paths and have their congestion costs reduced as a result of the large
interconnection-related network upgrade now in service will receive
this benefit for free in most cases.
    114. We seek comment on whether costs allocated to interconnection
customers pursuant to participant funding approaches have increased
over time, and if so, why. We seek comment on whether this increase in
costs is evidence that regional transmission planning processes are not
building adequate transmission system capacity. We seek comment on
whether the Commission's policies on participant funding have impacted
the interconnection queue, e.g., through late-state withdrawals, and if
so, how and to what degree. In the case that there are late-stage
withdrawals from the interconnection queue, we seek comment on the
ability of transmission providers to efficiently process
interconnection requests from other interconnection customers affected
by the withdrawal. Finally, we seek comment on whether uncertainty
regarding interconnection costs drives up the cost of developing supply
resources and thereby ultimately increases the cost of electricity
supply for customers.
    115. Participant funding also may create a separate incentive for
the interconnection customer that may undermine the development of
interconnection-related network upgrades that produce greater benefits.
Specifically, the interconnection customer, knowing that it will be
responsible for all interconnection-related network upgrade costs, is
likely to strongly oppose any addition or modification to the
transmission system beyond what is necessary to support its own
interconnection, even if such additions and modifications may
ultimately benefit it and others by providing improved reliability or
economic outcomes.\136\
---------------------------------------------------------------------------

    \136\ See Review of Generator Interconnection Agreements and
Procedures, Technical Conference Transcript, Docket No. RM16-12-000
at Tr: 193: 20-24 (Steve Naumann, Exelon) (filed Aug. 23, 2016)
(``[Y]ou need to also deal with the [interconnection] customer who
says, `Okay, I will be perfectly willing to take the risk, but I
don't want to pay for a single upgrade more than I have to [to] have
a the reliability interconnection.'').
---------------------------------------------------------------------------

    116. An additional rationale that the Commission provided in Order
No. 2003 for allowing participant funding was the concern that the
interconnection crediting policy would ``mute somewhat the
Interconnection Customer's incentive to make an efficient siting
decision that takes transmission costs into account.'' \137\ The
Commission in Order No. 2003 also found that participant funding in
RTOs/ISOs is consistent with the policy of promoting competitive
wholesale markets because it causes the interconnection customer to
face the same marginal cost price signal that it would face in a
competitive market.\138\ We seek comment on whether to reconsider these
findings in light of current circumstances.
---------------------------------------------------------------------------

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

    117. We note, for instance, that the Commission's view of efficient
siting of generation in Order No. 2003 was from a transmission costs
perspective, i.e., which points of interconnection would require the
least expensive interconnection-related network upgrades. We seek
comment on whether this perspective may be at odds with the primary
siting considerations for renewable generation developers decades
later. That is, interconnection at locations where renewable generation
may experience higher efficiency factors (e.g., because they have
abundant wind or sun) may still be uneconomic where participant funding
applies because the costs of interconnection-related network upgrades
for that location may be significant and would not be allocated beyond
the interconnection customer. We seek comment on whether
interconnection at such locations may be considered economic, however,
if the cost of the interconnection-related network upgrades were
allocated more broadly among those that benefit. Thus, because the
price signal participant funding sends does not account for the broader
economic efficiencies from siting renewable generation in fuel-rich
areas, it can instead encourage the development of renewable generation
in less productive locations. Because increased renewable resource
penetration in RTOs/ISOs is likely to continue, it may make less sense
to retain a policy that encourages renewable developers to develop
lower quality, less dependable renewable resources.
    118. Further, given the uncertainty created by the RTO/ISO queue
backlogs and cascading interconnection-related network upgrade cost
allocations that move from withdrawing higher-queued interconnection
customers to lower-queued interconnection customers, participant
funding may no longer provide efficient price signals that allow
generators to act freely to achieve the desirable level of entry of new
cost-effective generating capacity. We understand that a contributing
factor to the interconnection queue backlog is a tendency by
interconnection customers to submit multiple interconnection requests
at different points of interconnection, with the intention of
discovering the lowest cost site for a

project (from an interconnection perspective), and then withdrawing
higher-cost projects from the queue later in the process. This tendency
can require numerous restudies and reallocation of interconnection-
related network upgrade costs, compounding the uncertainty surrounding
the amount of interconnection-related network upgrade costs that will
be attributable to viable projects as the queue progresses.
    119. We seek comment on whether it is appropriate to eliminate or
reduce participant funding for interconnection-related network upgrades
in RTOs/ISOs and whether any specific proposed changes to
interconnection funding mechanisms allocate costs in a manner roughly
commensurate with benefits and are otherwise consistent with the
Commission's authority under the FPA and do not unjustly or
unreasonably shift costs to customers of load serving entities.
ii. Crediting Policy
    120. We seek comments on whether we should revisit the crediting
policy in all regions by requiring that transmission providers, instead
of interconnection customers, fund upfront all or a portion of the
interconnection-related network upgrade costs. We describe multiple
variations of this proposal below. Some generation developers may find
it difficult to provide upfront funding for the costs of network
upgrades when the reimbursement period can be as long as 20 years.
Accordingly, we seek comment on whether the current approach may
unjustly and unreasonably allocate significant financing costs for
interconnection-related network upgrades to interconnection customers
when the benefits of the interconnection-related network upgrades
accrue to the broader system. We seek comment on whether, if
interconnection-related network upgrade costs are increasing on
average, it is possible that these upfront funding costs may pose an
unjust and unreasonable barrier to entry for generation developers.
Given these considerations, below we seek comment on some potential
reforms to the crediting policy.
c. Potential Reforms and Request for Comment
    121. We seek comment on whether the Commission should eliminate the
independent entity variations that allow RTOs/ISOs to use participant
funding for interconnection-related network upgrades. We also seek
comment on potential approaches for modifying or replacing the existing
crediting policy for the costs of interconnection-related network
upgrades in all regions. We seek comment on these options and invite
alternative suggestions by commenters that take into consideration the
concerns discussed above.
    122. Additionally, for each of the reforms contemplated below, we
seek comment on whether there are articulable and plausible reasons to
believe that these reforms would allocate the costs of interconnection-
related network upgrades in a manner that is at least roughly
commensurate with the benefits of those interconnection-related network
upgrades and that do not unjustly and unreasonably shift costs to
customers of load serving entities or are otherwise inconsistent with
the Commission's statutory authority.
i. Eliminate Participant Funding for Interconnection-Related Network
Upgrades
    123. We seek comment on whether participant funding of
interconnection-related network upgrades may be unjust and
unreasonable. We seek comment on whether RTOs/ISOs with previously
approved independent entity variations that directly assign some or all
the cost responsibility for interconnection-related network upgrades to
interconnection customers should be required to revise their tariffs to
remove the participant funding of interconnection-related network
upgrade requirements and instead implement the crediting policy as
prescribed in the pro forma LGIA.
    124. The potential proposal to eliminate participant funding of
interconnection-related network upgrades in RTOs/ISOs would recognize,
however, that simply because an interconnection request makes an
interconnection-related network upgrade necessary for interconnection
(and in that sense, ``causes'' the need for interconnection-related
network upgrades that would not be needed ``but for'' an
interconnection request), an interconnection-related network upgrade
may sufficiently benefit transmission customers that it is appropriate
to allocate the interconnection-related network upgrade costs more
broadly. Also, this potential proposal could address the free rider
problem that is created by participant funding of interconnection-
related network upgrades. We note, however, that the specific proposal
is to eliminate participant funding and replace it with the crediting
policy, a pricing approach that still requires interconnection
customers to initially fund interconnection-related network
upgrades.\139\ Moreover, no potential reform presented here would
modify the existing requirement that an interconnection customer bear
cost responsibility for the interconnection facilities that would not
be needed but for its interconnection request.
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    \139\ As noted below, however, we are exploring reforms to the
existing crediting policy approach (that could be adopted alone or
in combination with the elimination of participant funding) that
could reduce the level of upfront funding to be provided by the
interconnection customers.
---------------------------------------------------------------------------

    125. We seek comment on whether the removal of participant funding
of interconnection-related network upgrades may also have the potential
to increase integration of generation by removing the possibly
prohibitive cost assignment that participant funding can place on some
interconnection customers. Furthermore, it may reduce cost uncertainty
to those resources in the interconnection queue, and by extension,
increase the likelihood that an interconnection request will result in
a developed generating facility.\140\
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    \140\ See, e.g., Review of Generator Interconnection Agreements
and Procedures, Technical Conference Transcript, Docket No. RM16-12-
000, at Tr. 25: 8-15 (May 13, 2016) (Dean Gosselin, NextEra) (filed
Aug. 23, 2016) (``I'd like to just talk about what is optimal . . .
as a developer . . . trying to advance [a project] to fruition . . .
. I would say for the interconnection queue that the initial results
closely match final results in a defined and reasonable timeline,
that would be my definition.''); id. at 134:5-7 (Omar Martino, EDF
Renewable Energy) (``[C]osts can change dramatically between [the]
system impact and [the] facility study.'').
---------------------------------------------------------------------------

    126. Additionally, we seek comment on whether eliminating
participant funding may reduce the queue backlogs that plague many
regions because interconnection customers would have less incentive to
submit multiple interconnection requests in an attempt to lower their
interconnection costs, and may no longer drop out of interconnection
queues at late stages due to unforeseen interconnection-related network
upgrade cost increases. To these points, we seek comment on the number
of interconnection requests that have withdrawn from the queue because
the direct assignment of significant interconnection-related network
upgrade costs made otherwise viable interconnection requests
uneconomic.
    127. We seek comment on whether the independent entity variation
granted to RTOs/ISOs in Order No. 2003 is no longer just and
reasonable. In general, we seek comment on whether the incentives
created by participant funding of interconnection-related network
upgrades in RTOs/ISOs may produce outcomes that are counter to the
Commission's transmission planning and cost allocation efforts.

    128. We are aware that there could be complications associated with
implementing the crediting policy in RTOs/ISOs with zonal transmission
rates that do not occur outside RTOs/ISOs. Outside RTOs/ISOs, a single
transmission provider owns and operates its transmission system and
generally charges a single rate for the entire system, regardless of
the specific transmission customer's location. In contrast, an RTO/ISO
operates the combined transmission assets of multiple transmission
owners within its footprint at non-pancaked transmission rates, and
generally has separate transmission pricing zones. The transmission
rates for each zone are generally designed to recover the costs of
transmission facilities located within each zone. As a result, we seek
comment on whether simply applying the crediting policy currently used
outside RTOs/ISOs in RTOs/ISOs may disproportionately increase the
burden to the native load of transmission zones where large amounts of
interconnection-related network upgrades are constructed to facilitate
the interconnection of location-constrained resources, which ultimately
may benefit the entire RTO/ISO footprint.
    129. Under a crediting policy in an RTO/ISO, there may be a need
for an appropriate mechanism to reimburse the interconnection
customers, including a mechanism for determining which transmission
owner(s) or zonal transmission rates will include the interconnection-
related network upgrade costs. For example, there is a question of
whether it would be just and reasonable to allocate the costs only
within the transmission zone where the interconnection-related network
upgrade is located or more broadly to multiple transmission zones.\141\
We therefore seek comment on how to implement the crediting policy in
RTOs/ISOs and what principles should be used to guide the application
of the crediting policy in RTOs/ISOs.
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    \141\ See, e.g., Interstate Power & Light Co. v. ITC Midwest,
LLC, 144 FERC ] 61,052, at P 40 (2013), order on reh'g,
clarification and compliance, 146 FERC ] 61,113 (2014). See also Sw.
Power Pool, Inc., 127 FERC ] 61,283, at P 5 (2009).
---------------------------------------------------------------------------

    130. Finally, given the concerns about the free-rider problem and
whether the ``well-defined capacity rights'' received by
interconnection customers capture the benefits the interconnection-
related network upgrades provide to the system, we seek comment on: (1)
The value of the ``well-defined capacity rights'' that interconnection
customers have received for funding interconnection-related network
upgrades; and (2) the value of the benefits that interconnection-
related network upgrades have provided to the system, such as the value
of congestion relieved by interconnection-related network upgrades. We
are also interested in any other concerns related to the ``well-defined
capacity rights'' that interconnection customers receive and the
ability of these ``well-defined capacity rights'' to reflect the value
of the full incremental capacity and congestion benefits added to the
transmission system by the interconnection-related network upgrades.
ii. Revisions to the Existing Crediting Policy
    131. We seek comment on possible revisions to the Order No. 2003
interconnection crediting policy, which requires that interconnection
customers provide upfront funding for interconnection-related network
upgrades and receive reimbursement through transmission service credits
or a balloon payment after 20 years. We enumerate multiple proposals
below. Not all of these proposals are mutually exclusive, and some
could be implemented in tandem.
(a) Transmission Providers Provide Upfront Funding for All
Interconnection-Related Network Upgrades
    132. Pursuant to this potential proposal, each transmission
provider would provide upfront funding for all the interconnection-
related network upgrades on its transmission system. Then, once such an
interconnection-related network upgrade is in service, the transmission
provider would be able to include the cost of that interconnection-
related network upgrade in its transmission service rate base and
recover a return on, and of, the network upgrade capital costs through
the cost-of-service transmission rates in its OATT. Thus,
interconnection customers that take transmission service on a
transmission system would still pay for a portion of interconnection-
related network upgrades through transmission rates. We seek comment on
(1) this approach and (2) how this approach could be implemented in a
just and reasonable manner.
    133. This option would reduce the initial financing burden that
interconnection customers currently may encounter when significant
interconnection-related network upgrades are required for their
interconnection request. Furthermore, this option may increase
generator competition by lowering barriers to entry, which in turn will
benefit customers by creating a more competitive market for energy.
    134. There may also be additional efficiency benefits to removing
the crediting policy because the financing of interconnection-related
network upgrades would follow the same financing process that the
transmission owners apply to the other transmission infrastructure that
they fund and build on their system. That is, there could be an
efficiency gain from using one financing process for all transmission
system facilities instead of the existing two: one for interconnection-
related network upgrades and another for other transmission system
facilities. In addition to that particular inefficiency, under the
current crediting approach applied in non-RTO/ISO regions, each
interconnection-related network upgrade is financed twice--initially by
the interconnection customer and then again by the transmission
provider when the interconnection customer receives credits as it takes
transmission service or receives a balloon payment after 20 years.
Without the initial funding by the interconnection customer,
interconnection-related network upgrades would only need to be financed
once.
(b) Interconnection Customers Contribute to the Upfront Funding of
Interconnection-Related Network Upgrades Through a Fee
    135. Another possible reform to the current crediting policy is to
consider the establishment of a non-refundable fee to be charged for
submitting an interconnection request and that is not reimbursable
through transmission service credits. Under this approach, an
appropriate fee should not be so large that it creates barriers to
entry for smaller developers. Potential benefits of this type of fee
could include: (1) Defraying some of the cost to transmission customers
for interconnection-related network upgrades and therefore decreasing
the overall impact on transmission customers of the related potential
reform to eliminate participant funding of interconnection-related
network upgrades in RTOs/ISOs; (2) discouraging the submission of
speculative interconnection requests; and (3) for some variable fees,
providing a price signal to interconnection customers that could incent
efficient siting decisions where possible. We seek comment on (1)
whether to impose a non-refundable, non-reimbursable fee on each
submitted interconnection request and (2) how this approach could be
implemented in a just and reasonable manner.

    136. We seek comment on two specific versions of this approach.
First, we seek comment on the potential establishment of a fixed fee
applied to each interconnection request, which would be the same for
all interconnection requests, irrespective of the generating facility's
capacity or project location. We seek comment on whether establishing a
fixed fee would be appropriate and, if so, the appropriate amount of
such a fee.
    137. Second, we seek comment on the potential establishment of a
variable fee applied to each interconnection request. The amount of the
variable fee could depend upon the generating facility capacity
associated with the interconnection request and/or the identified
interconnection-related network upgrades. For example, the fee could be
based on a percentage of the estimated interconnection-related network
upgrade costs or be calculated based on the generating facility
capacity and/or the voltage rating of the interconnection-related
network upgrade. We seek comment on the appropriate size of this fee
and the structure of the fee, if the Commission were to require one. We
also seek comment on whether it is possible to use a percentage of
interconnection-related network upgrade cost estimates for this fee,
and if so, at which point in the generator interconnection process a
transmission provider would calculate that cost.
    138. Finally, we seek comment on whether such a fee should be
established at the outset of the generator interconnection process, or
whether an escalating fee should be imposed as the interconnection
request moves through the study process. For example, a smaller fee
could be required for entry into the feasibility study phase, with a
larger fee for the system impact study phase and the largest fee
required to enter the facilities study.\142\ In this manner,
speculative projects could be discouraged from entering the later
stages of the generator interconnection process, while still allowing
interconnection customers to use the feasibility study process as it
was designed, to determine project feasibility for a broader range of
project sizes and locations.
---------------------------------------------------------------------------

    \142\ These non-refundable fees would be in addition to, and
distinct from, the initial deposit submitted with an interconnection
request and study deposits that are applied toward an
interconnection customer's interconnection study costs.
---------------------------------------------------------------------------

(c) Transmission Providers Provide Upfront Funding for Only Higher
Voltage Interconnection-Related Network Upgrades
    139. We seek comment on whether it would be appropriate to require
transmission providers to fund upfront the costs of any
interconnection-related network upgrade that is rated at or above a
certain voltage threshold. Interconnection customers would be
responsible for upfront funding the cost of interconnection-related
network upgrades below that threshold and be reimbursed through
transmission service credits pursuant to the crediting policy.
    140. Because higher voltage transmission facilities tend to produce
greater and broader benefits to transmission systems than lower voltage
transmission facilities, this option may better satisfy the requirement
that the allocation of costs be at least roughly commensurate with the
distribution of benefits.\143\ Thus, where an interconnection-related
network upgrade's voltage exceeds a defined threshold and is likely to
produce system-wide benefits, it may be appropriate to require that
transmission providers fund the costs of such interconnection-related
network upgrades upfront.
---------------------------------------------------------------------------

    \143\ See, e.g., Old Dominion Elec. Coop. v. FERC, 898 F.3d
1254, 1260 (D.C. Cir. 2018) (adopting Commission finding that
``high-voltage power lines produce significant regional benefits'').
---------------------------------------------------------------------------

    141. The Commission could also adopt a modified version of this
approach by requiring transmission providers to upfront fund the
portion of the costs of higher voltage interconnection-related network
upgrades that exceeds a pre-determined cost threshold. For example, the
Commission could require transmission providers to upfront fund the
costs of a 345 kV interconnection-related network upgrade that exceed
$10 million. Pursuant to this modified version, in this example of a
345 kV interconnection-related network upgrade, the Commission would
require the interconnection customer to fund all network upgrade costs
up to $10 million and require the transmission provider to provide
upfront funding for all interconnection-related network upgrade costs
above the $10 million threshold. Even in this situation, however, the
transmission provider would still have to provide transmission service
credits to reimburse the interconnection customer for its $10 million
subject to the crediting policy.
    142. We note that the Commission has approved a version of this
cost sharing approach in MISO, albeit in the context of responsibility
for payment of interconnection-related network upgrade costs themselves
and not just the upfront funding of them as discussed here. MISO's
tariff provides for some cost sharing for interconnection-related
network upgrades under which transmission providers recover the costs
of 10% of interconnection-related network upgrades rated 345 kV and
above on a system-wide basis while directly assigning through
participant funding 90% of the costs of such upgrades to the
interconnection customer whose interconnection required the network
upgrade.\144\ Furthermore, on multiple occasions, the Commission has
permitted RTOs/ISOs to define different transmission facility
categories and adopt different cost allocation methods for transmission
facilities based on the transmission facility's voltage threshold.\145\
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    \144\ MISO Tariff, Attach. FF (Transmission Expansion Planning
Protocol), Section III.A2.d (81.0.0).
    \145\ See Midcontinent Indep. Sys. Operator, Inc., 172 FERC ]
61,095 (2020) (accepting MISO's proposal to change the qualifying
voltage threshold for a certain class of project from 345 kV to 230
kV).
---------------------------------------------------------------------------

    143. If the Commission were to split the upfront funding
responsibility for interconnection-related network upgrades between the
transmission provider and the interconnection customer, it may be
useful to create a split based on voltage. For example, adopting an
interconnection-related network upgrade voltage threshold to be funded
upfront by the transmission provider has the potential to significantly
reduce interconnection-related network upgrade financing costs by
eliminating interconnection customers' need to fund upfront the likely
more expensive higher voltage interconnection-related network upgrades.
It could be appropriate to require the transmission provider to fund
upfront the cost of higher voltage interconnection-related network
upgrades because higher voltage transmission facilities are likely to
produce greater region-wide benefits than lower voltage ones.
    144. Whatever the selected voltage threshold might be,
interconnection customers would still be required to upfront fund the
costs of interconnection-related network upgrades (subject to the
crediting policy) that do not meet that threshold. Thus, the selection
of a voltage threshold would necessarily exclude from transmission
provider upfront funding some interconnection-related network upgrades
that produce regional

transmission benefits. We think it important to ensure that, if the
Commission requires that transmission providers establish a voltage
threshold for sharing the responsibility to fund upfront the cost of
interconnection-related network upgrades, then the voltage threshold
should be based upon the likelihood that interconnection-related
network upgrades that meet that threshold produce more transmission
benefits than interconnection-related network upgrades below that
threshold. Furthermore, we recognize that there is some tension between
such an approach, which would eliminate the requirement that
interconnection customers upfront fund some interconnection-related
network upgrades based on voltage, thus reducing the interconnection
customers' financing costs only on larger interconnection-related
network upgrades, and Order No. 2003's general acknowledgement that
interconnection-related network upgrades, regardless of voltage or
size, ``benefit all users.'' \146\ Additionally, if the Commission
adopted this option, in order to avoid the responsibility to upfront
fund, transmission providers will have an incentive to identify a lower
voltage interconnection-related network upgrade rather than identifying
a higher voltage project that may be more efficient or cost-effective.
---------------------------------------------------------------------------

    \146\ Order No. 2003, 104 FERC ] 61,103 at P 65.
---------------------------------------------------------------------------

    145. We seek comment on: (1) This approach; (2) the appropriate
voltage threshold and any pre-determined cost threshold; and (3) how
this approach could be implemented in a just and reasonable manner.
(d) Allocate the Upfront Cost of Interconnection-Related Network
Upgrades on a Percentage Basis
    146. We seek comment on whether to reduce the allowable percentage
of interconnection-related network upgrade costs that interconnection
customers must fund upfront (i.e., from 100% to a lower percentage).
The crediting policy would apply to the portion of the interconnection-
related network upgrade costs that the interconnection customer upfront
funds. To allow flexibility, we seek comment on whether an
interconnection customer should have the option to elect to upfront
fund 100% of the interconnection-related network upgrade if it chooses.
    147. This method could benefit both the interconnection customer
and the transmission provider. With the ability to provide partial to
full upfront funding for interconnection-related network upgrades,
interconnection customers will have the ability to retain some control
over the speed of interconnection-related network upgrade construction
because they will be able to provide initial funding in cases where the
transmission owner does not have the funding readily on hand to pay for
certain construction milestones. Transmission providers will benefit
because this construct will retain the price signal to interconnection
customers regarding siting decisions, as interconnection customers
would still have to upfront fund (i.e., finance) the costs of more
expensive larger interconnection-related network upgrades associated
with their interconnection requests and the costs related to financing
interconnection-related network upgrades (e.g., interest payments due
on the loan) should increase as the costs of the interconnection-
related network upgrades increase.
    148. We note that adoption of the transmission planning and cost
allocation reforms discussed above is likely to result in the
development of regional transmission facilities intended to accommodate
significant amounts of generation, and thus, has the potential to
reduce the need for more extensive and costly interconnection-related
network upgrades relative to those identified in the generator
interconnection process at present. Thus, the adoption of this
generator interconnection reform, in conjunction with the regional
transmission planning and cost allocation reforms discussed above,
could result in a significant reduction in interconnection customer
financing costs while still maintaining a price signal for siting
decisions.
    149. We seek comment on: (1) This approach; (2) the appropriate
percentage for the interconnection customer's upfront funding; and (3)
how this approach could be implemented in a just and reasonable manner.
As part of this inquiry, we are interested in hearing perspectives on
the extent to which partial upfront funding by an interconnection
customer may preserve or reduce the incentive for that customer to
efficiently site a project. We seek comment on whether there are there
other mechanisms, beyond customer upfront funding, that may incent a
customer to site efficiently, and that could be adopted in conjunction
with the elimination of participant funding.
iii. Additional Considerations
(a) Interconnection-Related Network Upgrade Cost Sharing
    150. If the Commission does not eliminate participant funding of
interconnection-related network upgrades, we seek comment regarding
potential cost-sharing measures to account for the fact that later-in-
time interconnection customers may accrue benefits from
interconnection-related network upgrades built to accommodate a prior
interconnection request. That is, if a later-in-time interconnection
customer benefits from the interconnection-related network upgrades
required to interconnect an earlier-in-time interconnection customer,
the later-in-time interconnection customers may also be assigned a
portion of those costs. The transmission provider could require the
allocation of costs in proportion to the benefits that the later-in-
time interconnection customers receive from network upgrades or be
based on a different method, such as a percent share based on usage. To
make this approach workable, the transmission provider could also
dictate a point after which a later-in-time interconnection customer
would be insulated from bearing the costs of a specific
interconnection-related network upgrade, e.g., prohibiting allocation
of interconnection-related network upgrade costs to interconnection
customers that enter the queue five years or more after the
interconnection-related network upgrade's energization.\147\ As we
noted above, the Commission has previously approved tariff provisions
pursuant to which earlier-in-time interconnection customers receive a
form of reimbursement for the network upgrade costs from later-in-time
customers.\148\ We note that the sharing of costs between earlier-in-
time and later-in-time interconnection customers would only apply in
situations where the earlier-in-time interconnection customer was
assigned any of the costs of the interconnection-related network
upgrade under the participant funding framework. We seek comment on a
just and reasonable method to calculate cost sharing for shared network
upgrades. We also seek comment on whether to require, and the
appropriate duration of, a time after which a later-in-time
interconnection customer would not be

allocated the costs of an interconnection-related network upgrade.
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    \147\ For the purpose of this order, we will refer to this time
period as the sunset period.
    \148\ See NYISO Tariff, attach S (Rules to Allocate
Responsibility for the Cost of New Interconnection Facilities),
Section 25.7.2; see also MISO Tariff, Attach. FF Section III.A.2.d.2
(81.0.0).
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(b) Option To Build
    151. Order No. 2003 established, and Order No. 845 expanded, the
interconnection customer's option to build transmission provider's
interconnection facilities \149\ and stand alone network upgrades.\150\
In a non-RTO/ISO, if an interconnection customer elects to exercise the
option to build, the interconnection customer assumes the
responsibility to design, procure, and construct the transmission
provider's interconnection facilities and stand alone network upgrades
and is repaid by the transmission provider pursuant to the crediting
policy.
---------------------------------------------------------------------------

    \149\ Order No. 2003 defined two categories of interconnection
facility: (1) Transmission provider's interconnection facilities,
which refer to all facilities and equipment owned, controlled or
operated by the transmission provider from the point of change of
ownership to the point of interconnection, including any
modifications, additions or upgrades to such facilities and
equipment;'' and (2) interconnection customer's interconnection
facilities, which are located between the generating facility and
the point of change of ownership and which the interconnection
customer must design, procure, construct, and own. See pro forma
LGIA art. 1 (Definitions); pro forma LGIA art. 5.10.
    \150\ Order No. 2003, 104 FERC ] 61,103 at P 353; Reform of
Generator Interconnection Procedures and Agreements, Order No. 845,
163 FERC ] 61,043, at P 85 (2018), order on reh'g, Order No. 845-A,
166 FERC ] 61,137, order on reh'g, Order No. 845-B, 168 FERC ]
61,092 (2019). Stand alone network upgrades refer to
interconnection-related network upgrades ``that are not part of an
Affected System that an Interconnection Customer may construct
without affecting day-to-day operations of the Transmission System
during their construction. Both the Transmission Provider and the
Interconnection Customer must agree as to what constitutes Stand
Alone Network Upgrades and identify them in Appendix A to the
Standard Large Generator Interconnection Agreement.'' See pro forma
LGIP Section 1 (Definitions).
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    152. Importantly, the option to build allows interconnection
customers to have some control over their own timelines and
construction schedules and potentially achieve cost savings associated
with the design, procurement, and construction of the transmission
provider's interconnection facilities and stand alone network upgrades.
If the Commission revises the requirement that interconnection
customers upfront fund all or some of the costs all of interconnection-
related network upgrades, corresponding changes may be necessary to the
option to build provisions as they apply to stand alone network
upgrades to recognize that an interconnection customer that wants to
exercise the option to build would no longer be responsible to upfront
fund the full cost of those network upgrades. Therefore, we seek
comment on what changes may be necessary to ensure that the option to
build provisions remain just and reasonable and to retain flexibility
for interconnection customers in light of the potential change to the
funding policy.
(c) Interconnection Request Limit
    153. We understand that a contributing factor to the
interconnection queue backlog is a tendency by interconnection
customers to submit multiple interconnection requests at different
points of interconnection, with the intention of discovering the lowest
cost location to site the generating facility (from an interconnection
perspective), and then withdrawing higher-cost interconnection requests
from the queue later in the process. We also understand that, absent an
appropriately-sized penalty (or reasonable restriction) associated with
submitting an interconnection request and then subsequently withdrawing
such an interconnection request, there still may be an incentive to
submit speculative interconnection requests under any of the potential
interconnection reforms discussed above. Therefore, we seek comment on
whether there should penalties for submitting speculative requests, how
such should be defined, and whether there should be a limit on the
number of interconnection requests that a developer can submit in an
interconnection queue study year and how narrowly such a limit should
apply (e.g., by transmission provider or by transmission pricing zone).
We also seek comment on how to determine a just and reasonable limit to
the number of interconnection requests. Finally, we seek comment on how
to address interconnection requests made by affiliated companies and
whether those interconnection requests should count against the limit
to the number of interconnection requests if one is imposed.
(d) Fast-Track for Interconnection of Generating Facilities Committed
to Regional Transmission Facilities
    154. As discussed above, we seek comment on the model established
by ERCOT to construct the CREZ transmission projects. For those
transmission projects to be approved, ERCOT required a certain
percentage of capacity to be reserved by generation developers with
existing projects, projects under construction, projects with signed
interconnection agreements, or posted collateral. In the case that this
model may improve the coordination between transmission planning and
the development of future generation, it may become important to
streamline the generator interconnection process for generating
facilities that are committed to interconnecting to these transmission
facilities.
    155. Therefore, we seek comment on whether a fast-track generator
interconnection process should be developed to facilitate
interconnection of generating facilities that have firmly committed to
connecting to new regional transmission facilities. An example of such
a fast-track option may be to allow the transmission provider to
perform a limited system impact study for only the cluster of
generating facilities committed under the regional transmission
planning process and to move to the facilities study without waiting
for earlier studies to complete. We recognize that the timeline for
transmission facility permitting and construction often far exceeds
that of the generator interconnection and construction process but seek
comment nonetheless on whether a faster generator interconnection
process in this scenario would be beneficial.
    156. We seek comment on whether such a process would constitute
inappropriate ``queue jumping,'' or instead would be more appropriately
viewed as an extension of the previously approved first-ready, first-
served queueing practice. In this case, are generating facilities that
have put up financial collateral to ensure that a regional transmission
facility is constructed to serve them appropriately considered
``ready'' projects? We seek comment on the feasibility of establishing
such a proposal, as well as the implications on the rest of the
generator interconnection queue and on any legal challenges related to
a potential ``queue jumping'' concern.
(e) Fast-Track for Interconnection of ``Ready'' Generating Facilities
    157. In addition to considering a fast-track generator
interconnection process for interconnection customers that have
committed financially to new regional transmission facilities, we are
considering whether allowing a fast-track for ``ready'' interconnection
requests would remove barriers to entry for interconnection requests
that have met certain readiness criteria. For example, interconnection
requests for which the developer has already executed a power purchase
agreement or that have been chosen in a state or utility request for
proposals may be appropriately deemed more ``ready'' than projects that
enter the interconnection queue without either contractual arrangement.
Another

example of an interconnection request that demonstrates a higher degree
of readiness could be one sited at a previously developed point of
interconnection that can make use of existing interconnection
facilities. Such interconnection requests may be considered more ready
because they have more ready access to the transmission system. Both of
these examples could be considered more ready than interconnection
requests proposed at points of interconnection where the
interconnection customer or the transmission provider must acquire new
rights-of-way, permits, and agreements with landowners, or that face
other obstacles to rapid development. We seek comment on which types of
interconnection requests could be considered more ``ready'' and able to
advance through the interconnection queue more quickly, as well as
comments on the just and reasonable structure for such a fast-track
option. We also seek comment on how to implement such a proposal in a
manner that is not unduly discriminatory. As in the prior proposed
reform, we seek comment on how to address possible concerns related to
what some may consider ``queue jumping'' or whether appropriate factors
may justify such measures.
(f) Grid-Enhancing Technologies
    158. We seek comment on whether there is the potential for Grid-
Enhancing Technologies not only to increase the capacity, efficiency,
and reliability of transmission facilities, but, in so doing, also to
reduce the cost of interconnection-related network upgrades.\151\ In
light of the potential of Grid-Enhancing Technologies, we seek comment
on whether the Commission should require that transmission providers
consider Grid-Enhancing Technologies in interconnection studies to
assess whether their deployment can more cost-effectively facilitate
interconnections. To the extent transmission providers currently
consider Grid-Enhancing Technologies in the generator interconnection
process, what, if any, shortcomings exist in that consideration? If the
Commission were to require greater consideration of Grid-Enhancing
Technologies, how should it do so? What, if any, challenges exist in
establishing such a requirement and how might these challenges be
addressed?
---------------------------------------------------------------------------

    \151\ Commission staff led a workshop in 2019 to explore the
role, benefits, and challenges of Grid-Enhancing Technologies. FERC,
Grid-Enhancing Technologies, Notice of Workshop, Docket No. AD19-19-
000 (Sept. 9, 2019).
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C. Enhanced Transmission Oversight

    159. The potential for a significant investment in the transmission
system in the coming years underscores the importance of ensuring that
ratepayers are not saddled with costs for transmission facilities that
are unneeded or imprudent. As part of this package of potential
reforms, we are considering whether reforms may be needed to enhance
oversight of transmission planning and transmission providers' spending
on transmission facilities to ensure that transmission rates remain
just and reasonable.
1. Potential Need for Reform
    160. As discussed above, the electricity sector is in the midst of
a fundamental transition as the generation mix shifts rapidly from
largely centralized resources located close to population centers
towards renewable resources located far from customers. Potential
reforms to regional transmission planning and cost allocation and
generator interconnection should help protect customers throughout this
transition by directing planning toward the more efficient or cost-
effective transmission facilities. Nevertheless, particularly in light
of potential costs of new transmission infrastructure that may be
needed to meet the needs of the changing resource mix, we seek comment
on whether additional measures may be necessary to ensure that the
planning processes for the development of new transmission facilities,
and the costs of the facilities, do not impose excessive costs on
consumers.
    161. We seek comment on whether the relatively large investment in
transmission facilities resulting from the regional transmission
planning and cost allocation processes reflects the more efficient or
cost-effective solutions for meeting transmission needs, including
those associated with a changing resource mix. The transparency with
which transmission needs are identified and transmission facilities
approved is an important element in ensuring that excessive costs are
not being imposed on consumers. Although Order No. 890 requires that
transmission planning processes comply with the transmission planning
principles, including transparency and openness, transmission providers
comply with those requirements in various ways.
    162. We seek comment on whether the current transmission planning
processes provide sufficient transparency for stakeholders to
understand how best to obtain information and fully participate in the
various processes. For example, we seek comment whether in non-RTO/ISO
regions individual transmission owning members' local transmission
planning processes may not be as well publicized or follow as well
understood processes to provide information as in RTO/ISO regions. We
seek comment on whether this may result in material costs being imposed
on consumers with limited visibility into the actual need for a local
transmission facility or support for a specific local transmission
solution. We also seek comment on whether, in light of the significant
potential costs of transmission and this potential deficit in
transparency, customers and other stakeholders might benefit from
enhanced oversight over identification and costs of transmission
facilities.
2. Potential Reforms and Request for Comment
a. Independent Transmission Monitor
    163. We seek comment on which potential measures the Commission
could take to ensure that there is appropriate oversight over how new
regional transmission facilities are identified and paid for. For
example, we seek comment on whether, to improve oversight of
transmission facility costs, it would be appropriate for the Commission
to require that transmission providers in each RTO/ISO, or more
broadly, in non-RTO/ISO transmission planning regions, establish an
independent entity to monitor the planning and cost of transmission
facilities in the region.
    164. We seek comment on the Commission's authority to require an
independent entity to monitor transmission spending in each
transmission planning region, as well as the role that such monitor(s)
would play. For example, this independent transmission monitor might
potentially review transmission planning processes, planning criteria
that lead to the identification of particular transmission needs and
facilities, as well as the rules and regulations governing such
processes. Additionally, the independent transmission monitor could
review transmission provider spending on transmission facilities and
identify instances of potentially excessive transmission facility
costs, including through inefficiencies between local and regional
transmission planning processes. Further, the independent transmission
monitor could identify instances in which transmission facilities were
selected in the regional transmission plan for cost allocation when it
may not be clear that such projects were the more efficient or

cost-effective transmission solutions, or were approved for regional
cost allocation when credible less-costly alternatives were available.
If the independent transmission monitor identifies such examples, it
could make a referral to the Commission. The Commission could then
conduct a review of the relevant transmission planning processes and/or
transmission facility costs under section 206 of the FPA. We seek
comment on the proposal outlined in this paragraph.
    165. We seek comment on whether the independent transmission
monitor's review could potentially focus on the transmission planning
process and costs of transmission facilities before construction
starts.\152\ We seek comment on whether and how the Commission might
modify the regional transmission planning and cost allocation processes
or rate recovery rules and procedures so as to facilitate such up-front
review.
---------------------------------------------------------------------------

    \152\ This is different than the safeguards provided under the
transmission formula rate protocols that have been implemented for
formula rates in transmission providers' OATTs. The transmission
formula rate protocols are generally designed to provide interested
parties sufficient opportunity to obtain and review information
necessary to evaluate the implementation of the formula rate, which
allows public utilities to recover the cost for transmission
facilities that are already constructed and placed in service,
except in limited circumstances (e.g., a transmission provider may
recover a return on costs of plant that is in the process of
construction by receiving regulatory approval to include such costs
of construction work in progress in rate base under its formula
rate). The protocols outline the process for the annual formula rate
informational filing at the Commission, transparency around the
transmission formula rate information exchange, the scope of
participation, and the ability of customers to challenge
transmission providers' implementation of the formula rate. See
Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ] 61,127
(2012); Midwest Indep. Transmission Sys. Operator, Inc., 143 FERC ]
61,149 (2013); Midcontinent Indep. Sys. Operator, Inc., 146 FERC ]
61,212 (2014); Midcontinent Indep. Sys. Operator, Inc., 150 FERC ]
61,025 (2015).
---------------------------------------------------------------------------

    166. We also seek comment on how an independent transmission
monitor could approach cost oversight. One possible method would be to
scrutinize the relevant regional transmission plan(s) to determine
whether a different portfolio of local and regional transmission
facilities would lead to higher net benefits. With regard to individual
transmission facilities selected via the regional transmission planning
processes or chosen through the local transmission planning processes,
the independent entity could provide information to assist the
Commission in determining whether the selection of a given transmission
facility warrants additional Commission review. Such assistance may
include the development of independent cost estimates for transmission
facilities. Given the challenges of reviewing all transmission
facilities, we seek comment on whether it would be useful for the
Commission or the independent entity to develop criteria (such as a
minimum spending threshold) to determine which transmission facilities
should be subject to review.
    167. We seek comment on tools that could be developed to assist
such a transmission monitor or the Commission in reviewing
transmission-related spending. For example, such a monitor might
develop benchmark cost estimates that would be independent of cost
estimates developed by a transmission provider, which could serve as a
mechanism to assess performance for each transmission provider for the
applicable transmission facilities. The independent transmission
monitor could create separate estimates for regional versus local
transmission facilities and classify facility costs by criteria (such
as voltage level), with estimates based on well-established methods
using the best information available just prior to the start of
construction to minimize the error in cost estimation. The Commission
could then review the costs for transmission facilities that
significantly exceed the cost estimates, either sua sponte or on the
recommendation of the independent transmission monitor or a third
party. An independent transmission monitor could also seek information
from transmission providers regarding the variances between actual and
estimated costs for selected regional transmission facilities and use
this information in its assessment of whether further Commission review
is recommended.
    168. We seek comment on whether an independent transmission monitor
should provide advice on the design and implementation of the regional
transmission planning and cost allocation processes in addition to
oversight of the regional transmission planning process and the costs
of the development of individual transmission facilities. The
independent transmission monitor could review the design of the
regional transmission planning and cost allocation processes on an
ongoing basis and highlight areas where improvements could be made (for
example, optimization between local and regional transmission
planning). The independent transmission monitor could also review
mechanisms used in transmission planning processes, such as adjusted
production cost modeling tools, and assess the extent to which
modifications to such mechanisms might yield more efficient
transmission spending decisions.
    169. The independent transmission monitor could also identify and
report on situations in which non-wires alternatives could more cost-
effectively address transmission system needs. We seek comment on the
value of such reporting and whether such information could improve the
ability for states to participate in the regional transmission planning
process and provide a greater opportunity for input. Similarly, we seek
comment on whether an independent transmission monitor or other
oversight mechanism should evaluate and report on transmission
providers' consideration of Grid-Enhancing Technologies in the
transmission planning process. If so, how should that evaluation be
conducted and what information should be reported?
    170. Additionally, we seek comment on whether oversight of the
planning and approval of local transmission facilities is necessary to
ensure that transmission rates are just and reasonable. We seek comment
on whether an independent transmission monitor should evaluate whether
the transmission needs identified in the local transmission planning
processes could be better considered during regional transmission
planning processes to allow for the identification of more efficient or
cost-effective transmission solutions. In addition, we seek comment on
whether oversight should consider the development and application of
transmission planning criteria. Finally, we encourage commenters to
identify any other factors that they believe the Commission should
consider for oversight within the local transmission planning process.
At the same time, we seek comment on whether such a role for a
federally-regulated regional transmission monitor would improperly or
inappropriately expand the role of federal regulation over local
utility regulation and/or potentially increase administrative and legal
costs of local transmission planning with no commensurate benefits for
customers. More broadly, we seek comment on whether there is a need to
delineate more clearly the oversight roles of federal and state
regulators over local transmission planning.
    171. In addition, we seek comment on whether there is sufficient
clarity on the roles and responsibilities between state and federal
regulators regarding the local transmission planning criteria and the
development of local transmission facilities (e.g., ``Supplemental
Projects'' in PJM). We seek comment on whether such transmission
facilities require additional oversight and whether

additional coordination among state and federal regulators would be
beneficial. Similarly, we seek comment on whether and how greater
oversight may improve coordination between individual transmission
provider's planning processes and regional transmission planning
processes. Order No. 1000 requires the evaluation of ``alternative
transmission solutions that might meet the needs of the transmission
planning region more efficiently or cost-effectively than solutions
identified by individual public utility transmission providers.'' \153\
We seek comment on whether current rules and processes are adequately
aligned with and facilitate such consideration or evaluation, and if
not, whether there are oversight measures or other mechanisms,
including via an independent transmission monitor, that could better
facilitate the consideration of more efficient or cost-effective
alternatives. For example, we seek comment on whether individual
transmission provider practices regarding retirement and replacement of
transmission facilities sufficiently align with the directive to ensure
evaluation of alternative transmission solutions and whether these
practices sufficiently consider the more efficient or cost-effective
ways to serve future needs. We also seek comment on whether sufficient
transparency exists in retirement decisions to allow for such regional
assessment. We seek comment on what role can or should an independent
transmission monitor play in facilitating enhanced coordination.
---------------------------------------------------------------------------

    \153\ Order No. 1000, 136 FERC ] 61,050 at P 148.
---------------------------------------------------------------------------

    172. Furthermore, we seek comment on whether additional
transparency measures are appropriate or should be in place for
transmission providers, including those outside of RTO/ISO regions. If
so, we seek comment on whether the Commission should apply transparency
measures, some of which are currently utilized within RTO/ISO regions
(e.g., dedicated transmission planning web pages, requirements to
publish and detail full transmission plan at end of each transmission
planning cycle, scorecards), or consider different or new transparency
measures for transmission providers outside of RTO/ISO regions. We seek
comment on whether new or different transparency measures are needed
within the RTO/ISO regions.
    173. An independent transmission monitor would not replace the
Commission's rate jurisdiction but instead could provide the Commission
with an additional means of ensuring that rates are just and
reasonable. With respect to other aspects of prudence, or transmission
facility selection against alternatives, the independent transmission
monitor would not supplant the Commission's authority with respect to
prudence, but could inform the Commission as to whether a further
review is warranted; the final determination on whether costs are
prudently incurred remains with the Commission. Similarly, the record
created by the independent transmission monitor could help the
Commission in ensuring that the design of the regional transmission
planning and cost allocation processes remain just and reasonable and
not unduly discriminatory or preferential.
    174. We seek comment on (1) the independent transmission monitor
proposal, and (2) any alternative options for improving oversight of
transmission costs or the effectiveness of transmission planning
processes. Additionally, we seek comment on whether the concerns
regarding transmission oversight are best addressed by an independent
entity similar to the role of an independent market monitor, or whether
the concerns can be adequately addressed by the RTO/ISO or transmission
providers in non-RTO/ISO regions, or through another approach.
    175. We also seek comment on (1) how an independent transmission
monitor (or set of regional monitors) would be created or authorized;
(2) whether a single monitor should be appointed for each transmission
region, or instead a given monitor might review transmission across
several regions; (3) the Commission's authority to require an
independent transmission monitor in all transmission planning regions;
(4) how this entity would work in practice, in both the RTO/ISO and
non-RTO/ISO regions; and (5) the scope of review such monitor(s) should
be charged with carrying out, including whether such monitoring should
extend to oversight of the generator interconnection process.
b. State Oversight
    176. Another way to add oversight to the transmission planning and
cost allocation processes could be to involve state commissions in
those processes. By way of example, SPP has a Regional State Committee
(RSC), which provides collective state regulatory agency input in areas
under the RSC's primary responsibilities and on matters of regional
importance related to the development and operation of the bulk
electric transmission system. Pursuant to the SPP Bylaws, ``with
respect to transmission planning, the RSC will determine whether
transmission upgrades for remote resources will be included in the
regional transmission planning process and the role of transmission
owners in proposing transmission upgrades in the regional planning
process.'' \154\
---------------------------------------------------------------------------

    \154\ SPP, Governing Documents Tariff, Bylaws, Section 7.2
(Regional State Committee) (1.0.0).
---------------------------------------------------------------------------

    177. We seek comment on whether this type of model, or other models
that may be proposed, could be expanded to other regions and other
topics; for example, whether a state-led committee could: Provide
insight into regional transmission facility costs and cost allocation
methods; evaluate whether the transmission needs identified in the
local transmission planning processes could be better considered during
regional transmission planning processes; inform the Commission as to
whether a further review is warranted of whether incurred costs are
prudent; or provide the Commission with an additional means of ensuring
that rates are just and reasonable. We also seek comment on how such a
model may be combined with other oversight tools or mechanisms explored
herein. For example, given state regulatory authority over the approval
of non-wires solutions, can or should a regional state committee play a
role in identifying circumstances under which a non-wires solution
would be the more efficient or cost-effective solution to solving an
identified regional transmission need, and facilitating a process by
which the relevant state regulator could be given an opportunity to
approve such a solution?
c. Limitation on Recovery of Costs for Abandoned Projects
    178. There is always a risk that once approved, a regional project
may be abandoned before going into service for a variety of reasons
including a failure to obtain all necessary state and federal
approvals, including, for example, state certificates of public
convenience and necessity. The Commission's general policy for recovery
of the costs of abandoned plant under section 205 of the FPA allows
recovery of and return on 50% of the prudently incurred investment
costs incurred in connection with the abandoned plant.\155\ In

addition, the Commission may grant as an incentive under section 219 of
the FPA for transmission facilities meeting the qualifications for the
incentive, recovery of 100% of prudently-incurred costs related to such
facilities if they are abandoned for reasons beyond the control of the
transmission owner.\156\ In light of potential costs of new regional
transmission infrastructure and the corresponding risk that some of
those projects may be abandoned, we seek comment on whether the
Commission should revisit its policies regarding abandoned plant to
better protect consumers from increased costs due to never-built
transmission facilities.
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    \155\ New Eng. Power Co., Opinion No. 295, 42 FERC ] 61,016, at
61,081-82, order on reh'g, Opinion No. 295-A, 43 FERC ] 61,285
(1988). The Commission also allows recovery under section 205 of
return on 50% of investment costs incurred to construct transmission
facilities (and other non-pollution control plant) through the
inclusion of Construction Work in Progress (CWIP) in rate base
during the construction period, provided certain conditions are met.
Construction Work In Progress for Public Utilities; Inclusion of
Costs in Rate Base, Order No. 298, 48 FR 24,323 (June 1, 1983), FERC
Stats. & Regs. ] 30,455, order on reh'g, Order No. 298-A, 48 FR
46,012 (Oct. 11, 1983), FERC Stats. & Regs., ] 30,500 (1983), order
on reh'g, Order No. 298-B, 48 FR 55,281 (Dec. 12, 1983), FERC Stats.
& Regs. ] 30,524 (1983) (Order No. 298).
    \156\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, 116 FERC ] 61,057, order on reh'g, Order No. 679-A,
117 FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 (2007).
---------------------------------------------------------------------------

    179. For example, one proposal to protect consumers would be to
limit the recovery of costs through abandonment by allowing only the
recovery of some portion of actual development or pre-commercial costs,
and/or no recovery of a return on equity on such costs prior to the
project receiving all necessary regulatory approvals. We therefore seek
comment on this or other proposals to limit the amount that can be
recovered for regional transmission facilities that are abandoned prior
to going into service. Commenters are, of course, welcome to address
all issues and concerns pertinent to such proposals.
d. Additional Oversight Approaches
    180. Finally, we seek comment on additional oversight approaches
the Commission might take to ensure that wholesale transmission
spending is cost effective. For example, performance-based regulation.
We ask how performance-based regulation may be designed to ensure that
rates are just and reasonable, ensure reliability of the transmission
system, promote regional expansion of transmission facilities for a
sufficiently wide range of future scenarios, including anticipated
future generation, and encourage transmission provider participation.

D. Transition

    181. To implement any of the proposals outlined above, transmission
providers must transition to new interconnection pricing paradigms and
new regional transmission planning and cost allocation processes.
Therefore, we seek comment on appropriate transition plans, including
treatment of interconnection customers in the various stages of the
generator interconnection process and those that have already
interconnected as well as when the more holistic regional transmission
planning and cost allocation processes would begin (including when the
broader category of regional transmission facilities would be
established).
    182. The Commission also seeks input as to the length of time that
might be necessary to implement any reforms that result from this
process. Specifically, the Commission requests input as to how much
time transmission providers might need to develop compliance filings
related to all of the proposals in this ANOPR.

V. Comment Procedures

    183. The Commission invites interested persons to submit comments
on these matters and any related matters or alternative proposals that
commenters may wish to discuss. Comments are October 12, 2021 and Reply
Comments are due November 9, 2021. Comments must refer to Docket No.
RM21-17-000 and must include the commenter's name, the organization
they represent, if applicable, and their address in their comments. All
comments will be placed in the Commission's public files and may be
viewed, printed, or downloaded remotely as described in the Document
Availability section below. Commenters on this proposal are not
required to serve copies of their comments on other commenters
    184. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software must be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    185. Commenters that are not able to file comments electronically
may file an original of their comment by USPS mail or by courier-or
other delivery services. For submission sent via USPS only, filings
should be mailed to: Federal Energy Regulatory Commission, Office of
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of
filings other than by USPS should be delivered to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.

VI. Document Availability

    186. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (https://www.ferc.gov). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
    187. From the Commission's Home Page on the internet, this
information is available in its eLibrary. The full text of this
document is available in the eLibrary in PDF and Microsoft Word format
for viewing, printing, and/or downloading. To access this document in
eLibrary, type the docket number of this document excluding the last
three digits in the docket number field.
    188. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>    By direction of the Commission. Chairman Glick and Commissioner
Clements are concurring with a joint separate statement attached.
Commissioner Chatterjee is not participating. Commissioner Danly is
concurring with a separate statement. Commissioner Christie is
concurring with a separate statement.

    Issued: July 15, 2021.
Debbie-Anne A. Reese,
Deputy Secretary.

Department of Energy

Federal Energy Regulatory Commission

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

Docket No. RM21-17-000
    GLICK, Chairman, CLEMENTS, Commissioner, concurring:
    1. The generation resource mix is changing rapidly. Due to a myriad
of factors--including improving economics, customer and corporate
demand for clean energy, public utility commitments and integrated
resource plans, as well as federal, state, and local public policies--
renewable resources in particular are coming online at an

unprecedented rate.\1\ As a result, the transmission needs of the
electricity grid of the future are going to look very different than
those of the electricity grid of the past.
---------------------------------------------------------------------------

    \1\ See, e.g., Joseph Rand et al., Queued Up: Characteristics of
Power Plants Seeking Transmission Interconnection as of the End of
2020, Lawrence Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/queued_up_may_2021.pdf;
Electric Power Monthly, Table 6.1 Electric Generating Summer
Capacity Changes (MW), U.S. Energy Information Administration, (Mar.
2021 to Apr. 2021), https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=table_6_01.
---------------------------------------------------------------------------

    2. We are concerned that the current approach to transmission
planning and cost allocation cannot meet those future transmission
needs in a manner that is just and reasonable and not unduly
discriminatory or preferential. In particular, we believe that the
status quo approach to planning and allocating the costs of
transmission facilities may lead to an inefficient, piecemeal expansion
of the transmission grid that would ultimately be far more expensive
for customers than a more forward-looking, holistic approach that
proactively plans for the transmission needs of the changing resource
mix. A myopic transmission development process that leaves customers
paying more than necessary to meet their transmission needs is not just
and reasonable.
    3. In that regard, we are pleased to see the Commission taking a
consensus first step toward updating its rules and regulations to
ensure that we are meeting the nation's evolving transmission needs in
a cost-effective and efficient fashion. Today's action complements our
recently established joint federal-state task force with the National
Association of Regulatory Utility Commissioners,\2\ which we expect to
produce a robust dialogue on many of the issues addressed herein. In
our view, this advance notice of proposed rulemaking (ANOPR) is just
the first step. Ensuring that transmission rates remain just and
reasonable will require further action, including reforms to
interregional transmission planning and cost allocation, as well as
other reforms to our regional transmission planning and cost allocation
and generator interconnection processes beyond those contemplated
herein. Nevertheless, we believe that today's unanimous Commission
action represents a solid foundation for an expeditious inquiry into
how we can regulate to achieve the transmission needs of our changing
electricity system in a manner consistent with our statutory
obligations under the Federal Power Act.
---------------------------------------------------------------------------

    \2\ Joint Federal-State Task Force on Electric Transmission, 175
FERC ] 61,224 (2021).
---------------------------------------------------------------------------

* * * * *
    4. The generation mix is shifting rapidly from large resources
located close to population centers toward renewable resources, often
combined with onsite storage, that tend to be located where their fuel
source is best--i.e., where the wind blows hardest or the sun shines
brightest. According to the National Renewable Energy Laboratory
(NREL), total renewable generation capacity nearly doubled from 2009 to
2018, increasing from 11.7% of total generation capacity to 20.5%.\3\
And that is just the beginning: Of the roughly 750 GW of generation in
interconnection queues around the country, nearly 700 GW are renewable
resources,\4\ providing every reason to believe that the dramatic shift
toward renewable generation will only accelerate in the years ahead.
---------------------------------------------------------------------------

    \3\ 2018 Renewable Energy Data Book at 26, NREL, https://www.nrel.gov/docs/fy20osti/75284.pdf. Wind and solar resources, in
particular, have grown at a disproportionate rate, with solar
generation capacity increasing roughly 5,000% from 1,054 MW to
51,899 MW nationwide, and wind generation capacity more than
tripling from 31,155 MW to 96,442 MW.
    \4\ See Joseph Rand, Queued Up: Characteristics of Power Plants
Seeking Transmission Interconnection as of the End of 2020, Lawrence
Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/queued_up_may_2021.pdf.
Equally important, this shift is taking place across the country,
not just in a few areas. For example, as of the issuance of this
ANOPR, in Midcontinent Independent System Operator, Inc. (MISO),
solar and wind projects comprise 80% of all active projects in the
current interconnection queue, or about 73 GW of total capacity.
MISO, Generator Interconnection Queue--Active Projects Map, https://giqueue.misoenergy.org/PublicGiQueueMap/index.html. Similarly, in
PJM Interconnection, L.L.C. (PJM), solar and wind projects with a
total capacity of 62 GW comprise 79% of all active projects in the
current interconnection queue as of the issuance of this ANOPR. PJM,
New Services Queue, https://www.pjm.com/planning/services-requests/interconnection-queues.aspx. In California Independent System
Operator Corporation (CAISO), renewable and storage capacity of 23
GW comprise 78% of all active projects in the current
interconnection queue as of the issuance of this ANOPR. CAISO,
Generator Interconnection Queue, https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueueExcel.xls.
---------------------------------------------------------------------------

    5. That shift is the result of many factors. First and foremost,
the cost of renewable resources is plummeting. For example, in its
annual report on the levelized cost of energy, Lazard found that
between 2009 to 2020, the levelized cost of energy from unsubsidized
wind generation and unsubsidized utility-scale solar generation
decreased by 71% and 90%, respectively \5\--enough to make utility-
scale solar and wind generation cost-competitive with central station
fossil generation sources in many parts of the country.\6\ Moreover,
customers--both residential and commercial--are increasingly demanding
clean energy, particularly energy from renewable resources--which is
itself causing utilities and independent power producers to attempt to
send large quantities of renewable energy onto the grid.\7\ In
addition, dozens of the biggest utilities in the country have
established their own decarbonization goals, the achievement of which
will require their

own significant investment in renewable generation.\8\
---------------------------------------------------------------------------

    \5\ See, e.g., Lazard's Levelized Cost of Energy Analysis--
Version 14.0, at 9 (Oct. 19, 2020), https://www.lazard.com/
perspective/levelized-cost-of-energy-and-levelized-cost-of-storage-
2020/#:~:text=Lazard's%20latest%20annual%20Levelized%
20Cost,build%20basis%2C%20continue%20to%20maintain; Ryan Wiser et
al., Expert elicitation survey predicts 37% to 49% declines in wind
energy costs by 2050, Lawrence Berkeley National Laboratory (Apr.
2021), https://eta-publications.lbl.gov/sites/default/files/wind_lcoe_elicitation_ne_pre-print_april2021.pdf (finding that the
decrease in levelized cost of energy for wind power from 2015-2020
outpaced the decrease predicted by experts, and that experts
continue to predict significant declines in levelized cost of
energy).
    \6\ See Lazard's Levelized Cost of Energy Analysis--Version
14.0, at 3, 7 (Oct. 19, 2020), https://www.lazard.com/perspective/
levelized-cost-of-energy-and-levelized-cost-of-storage-2020/
#:~:text=Lazard's%20latest%20annual%20Levelized%
20Cost,build%20basis%2C%20continue%20to%20maintain.
    \7\ See, e.g., Deloitte Resources 2020 Study at 22, https://www2.deloitte.com/content/dam/insights/us/articles/6655_Resources-study-2020/DI_Resources-study-2020.pdf (showing that U.S. corporate
renewable generation purchase power agreements increased from 0.3 GW
in 2009 to 13.6 GW in 2019); Kevin O'Rourke & Charles Harper,
Corporate Renewable Procurement and Transmission Planning:
Communicating Demand to RTOs Necessary to Secure Future Procurement
Options, A Renewable America (October 2018), https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf (indicating that a group of corporations,
forming the Renewable Energy Buyers Alliance, has set a goal to
purchase 60 GW of new renewable energy capacity in the U.S. by
2025); Stanley Porter et al., Utility Decarbonization Strategies,
Renew, Reshape, and Refuel to Zero, Deloitte Insights (Sept. 2021),
https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/utility-decarbonization-strategies.html (indicating that
43 of 55 utilities surveyed have emissions reductions targets and 22
have net-zero or carbon-free electricity goals); Esther Whieldon,
Path to net zero: 70% of biggest US utilities have deep
decarbonization targets, S&P Global Market Intelligence (Dec. 9,
2020) at 3-6, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651 (indicating
that review of utilities' climate goals decarbonization plans, as of
December 2020, shows that 70% of the 30 largest utilities have net-
zero carbon targets or are moving to comply with similarly
aggressive state mandates); see also Rich Glick and Matthew
Christiansen, FERC and Climate Change, 40 Energy L.J. 1, 7-12 (2019)
(``The growth of renewable resources is also a function of
consumers' desire for clean energy. Customers--including
residential, commercial, and even industrial consumers--are
increasingly demanding that their energy come from renewable or
zero-emissions sources'').
    \8\ See, e.g., Corporate Renewable Procurement and Transmission
Planning: Communicating Demand to RTOs Necessary to Secure Future
Procurement Options, A Renewable America, October 2018, https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf; Esther Whieldon, Path to
net zero: 70% of biggest US utilities have deep decarbonization
targets, S&P Global Market Intelligence, Dec. 9, 2020, at 3-6,
https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651.
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    6. Finally, federal, state, and local policymakers have adopted a
range of public policies that are driving the changing resource mix.
For example, 30 states and the District of Columbia have adopted
renewable portfolio standards,\9\ with those standards contributing to
roughly 50% of the total growth in renewable generation over the last
two decades.\10\ In addition, several states have doubled down on the
clean energy transition by enacting measures that require that most or
all of their electricity come from zero emissions resources.\11\ All
told, ``states and utilities that have committed to transitioning to
100 percent clean power serve nearly 83 million households and
businesses, representing around 50 percent of all U.S. electricity
demand in 2019.'' \12\
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    \9\ Nat'l Conference of State Legislatures, State Renewable
Portfolio Standards and Goals (Nov. 7, 2021), https://www.ncsl.org/
research/energy/renewable-portfolio-
standards.aspx#:~:text=Thirty%20states%2C%20Washington%2C%20DC%2C,hav
e%20set%20renewable%20energy%20goals. Renewable portfolio standards
are policies that are designed to increase the amount of renewable
energy sources used for electricity generation.
    \10\ See, e.g., Berkeley Lab, U.S. Renewables Portfolio
Standards: 2019 Annual Status Update (Aug. 2019), https://emp.lbl.gov/publications/us-renewables-portfolio-standards-2.
    \11\ Carbon Pricing in Organized Wholesale Elec. Markets, 175
FERC ] 61,036, at P 2 (2021) (``Thirteen states--California, Hawaii,
Maine, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New
York, Oregon, Vermont, Virginia, and Washington--and the District of
Columbia have adopted clean energy or renewable portfolio standards
of 50% or greater.''). In addition, ``a number of states--including
Colorado, Connecticut, Nevada, Rhode Island, and Wisconsin--have
established 100% clean electricity goals or targets by executive
order or other non-binding commitment.'' See id. At the local level,
cities and counties are also accelerating clean energy commitments.
Kelly Trumbull et al., Progress Toward 100% Clean Energy in Cities
and States Across the U.S., University of California--Los Angeles
Luskin Center for Innovation (November 2019) at 10, https://innovation.luskin.ucla.edu/wp-content/uploads/2019/11/100-Clean-Energy-Progress-Report-UCLA-2.pdf (finding over 200 cities and
counties across 37 U.S. states have 100 percent clean energy
commitments).
    \12\ National Resources Defense Council (NRDC), NRDC's 8th
Annual Energy Report: Slow and Steady Will Not Win the Climate Race
(Dec. 2, 2020), https://www.nrdc.org/resources/nrdcs-8th-annual-energy-report-slow-and-steady-will-not-win-race?nrdcpreviewlink=rmmB6NM6zpiOTruhuObZJdH92bCOvmZTY1hx72xCSzQ#renewables.
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    7. Dramatic changes in the resource mix inevitably come with
similarly dramatic changes in transmission needs. As noted, the
increasingly cost-competitive renewable resources that customers and
public policies demand tend to be developed farther away from customers
where their fuel sources are strong and development costs are low
rather than in close proximity to their ultimate customers. As a
result, the future resource mix will likely present new transmission
needs, different from those of the large resources located close to
population centers that have dominated electricity generation in the
past. Meeting those transmission needs will likely require both the
infrastructure necessary to interconnect new resources to the
transmission system efficiently and the infrastructure necessary to
reliably move the electricity produced by those resources to where it
is needed. This could make it considerably more expensive than
necessary to bring in the low-cost generation demanded by customers and
meet federal, state, and local public policies.
    8. This Commission cannot sit idly by. Our role is to ensure just
and reasonable rates and support reliability in light of changes in the
market, not to pretend those changes are not happening. We are
concerned that, in light of evolving transmission needs, the current
regional transmission planning and cost allocation and generator
interconnection processes may no longer ensure just and reasonable
rates for transmission service.\13\ In particular, we are concerned
that existing regional transmission planning processes may be siloed,
fragmented, and not sufficiently forward-looking, such that
transmission facilities are being developed through a piecemeal
approach that is unlikely to produce the type of transmission solutions
that could more efficiently and cost-effectively meet the needs of the
changing resource mix. Regional transmission planning processes
generally do little to proactively plan for the resource mix of the
future, including both commercially established resources, such as
onshore wind and solar, as well as emerging ones, such as offshore
wind. We are also concerned that current regional transmission planning
processes are not sufficiently integrated with the generator
interconnection processes, and are overwhelmingly focused on relatively
near-term transmission needs, and that attempting to meet the needs of
the changing resource mix through such a short-term lens will lead to
inefficient transmission investments. As a result, under the status
quo, customers could end up paying far more to meet their transmission
needs than they would under a more forward-looking approach that
identifies the more efficient or cost-effective investments in light of
the changing resource mix.\14\
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    \13\ 16 U.S.C. 824e.
    \14\ See generally Eric Larson et al., Net-Zero America:
Potential Pathways, Infrastructure, and Impact (2020),
Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf (discussing
different pathways for meeting decarbonization goals, including
differing approaches to transmission investment).
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    9. Relatedly, we are also concerned that the current approach to
transmission planning and cost allocation is failing to adequately
identify the benefits and allocate the costs of new transmission
infrastructure. Although the regional transmission planning process
considers transmission needs driven by reliability, economics, and
Public Policy Requirements,\15\ those transmission needs are often
viewed in isolation from one another and the cost allocation methods
for projects selected to meet those needs are similarly siloed. As a
result, the status quo may be disproportionately producing transmission
facilities that address a narrow set of needs, providing comparatively
modest benefits, but at a still-substantial total cost instead of
developing the type of transmission infrastructure that could provide
the most significant benefits for customers. In the same vein, we are
also concerned that many customers who share in the diverse array of
benefits that transmission infrastructure can offer may not be paying
their fair share, as required by the cost causation principle.\16\
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    \15\ See Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public Utilities, Order No. 1000,
136 FERC ] 61,051, at P 11 (2011), order on reh'g, Order No. 1000-A,
139 FERC ] 61,132, order on reh'g and clarification, Order No. 1000-
B, 141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v.
FERC, 762 F.3d 41 (D.C. Cir. 2014).
    \16\ Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264,
268-269 (D.C. Cir. 2014) (``[T]he cost causation principle itself
manifests a kind of equity. This is most obvious when we frame the
principle (as we and the Commission often do) as a matter of making
sure that burden is matched with benefit.'' (citing Midwest ISO
Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004)
and Se. Michigan Gas Co. v. FERC, 133 F.3d 34, 41 (D.C. Cir.
1998))).
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    10. In addition, we are concerned that, largely due to the
potential shortcomings with the current regional transmission planning
and cost allocation processes, transmission infrastructure is
increasingly being

developed through the generator interconnection process. That means
that infrastructure with potentially significant benefits for a broad
range of entities may be developed through a process that focuses
exclusively on the needs of a comparatively small number of
interconnection customers--a dynamic that is almost sure to result in
comparatively inefficient investment decisions. The participant funding
approach to financing interconnection-related network upgrades will
often mean that the interconnection customer(s) alone must pay for
all--or the vast majority--of the costs of that transmission
infrastructure, even where it provides significant benefits to other
entities. That, in turn, may cause those interconnection customers to
withdraw projects from the queue, causing considerable uncertainty and
delay, and may mean that net beneficial transmission infrastructure is
never developed due to a misalignment in how that infrastructure would
be paid for.
    11. Finally, we are also concerned that the Commission's current
approach to overseeing transmission investment may not adequately