studies used to evaluate Electric Storage Resources should reflect
reasonable operating assumptions, such as charging during off-peak
hours.\374\ The American Clean Power Association and U.S. Energy
Storage Association (ACPA/ESA) noted that the unrealistic assumption
that storage will charge at full capacity during peak load incentivizes
developers to site storage far from binding transmission elements to
avoid costly network upgrades.\375\ ACPA/ESA argued that siting this
way is inefficient because the expected dispatch of storage near a
binding transmission element in response to wholesale market prices
would most likely relieve the binding transmission element rather than
exacerbate it. The Union of Concerned Scientists agreed that assuming
electric storage resources will charge during peak load periods and
exacerbate transmission constraints is unrealistic because electric
storage resources are typically deployed with a specific operating
strategy in mind to reduce or eliminate a transmission constraint.\376\
ACPA/ESA further argued that current operating assumptions in
interconnection studies disregard the ability of storage to install
software and hardware controls to prevent dispatch in response to
predefined line loading criteria and/or predetermined time periods.
---------------------------------------------------------------------------

    \374\ NARUC, Comments, Docket No. RM21-17-000, at 9 (filed Oct.
12, 2021).
    \375\ ACPA/ESA, Comments, Docket No. RM21-17-000, at 41-42
(filed Oct. 12, 2021).
    \376\ Union of Concerned Scientists, Comments, Docket No. RM21-
17-000, at 63-64 (filed Oct. 12, 2021).
---------------------------------------------------------------------------

    273. Other commenters noted that the issue concerning inaccurate
operating assumptions applies beyond the electric storage resource and
co-located resource or hybrid resource context and argued that the
requirement for accurate operating assumptions should apply to all
generating facility types. Using the framework of fuel-based dispatch
as a reference to accurate operating assumptions, Enel explains,
``[t]he Commission should direct all Transmission Providers to
implement fuel-based dispatch assumptions in studies to further reduce
interdependency between interconnection requests.'' \377\ Enel further
states,
---------------------------------------------------------------------------

    \377\ Enel, Comments, Docket No. RM21-17-000, at 16 (filed Oct.
12, 2021).

by studying new generators only in seasons and load profiles that
match the likely generation profile of the fuel source,
interconnection requests become less dependent on the results of
interconnection studies for generators of different fuel types. For
instance, a solar project may produce more during the summer, and a
wind project may produce more during the winter. Studying the two
projects as if they will achieve maximum output at the same time for
several hours of the year could create the false impression that
upgrades are necessary to integrate the two projects on the grid.
This would create interdependence, such that one project dropping
out would trigger a restudy for the other project and queue delays.
With fuel-based dispatch [assumptions,] the two projects will not
achieve maximum output at the same time for many hours of the year
and

avoid the interdependence and need to restudy.\378\
---------------------------------------------------------------------------

    \378\ Id.

    Enel also noted that MISO and PJM already employ such an approach.
    274. Commenters in the hybrid resources proceeding also noted that
modern control technology can limit an entire hybrid facility's impact
at the point of interconnection.\379\ This ability would apply to
variable energy resources and stand-alone electric storage resources,
as well as co-located resources containing electric storage resource
(including hybrid resources).
---------------------------------------------------------------------------

    \379\ Pine Gate, Comments, Docket No. AD20-9-000, at 4 (filed
Sept. 20, 2021).
---------------------------------------------------------------------------

    275. Commenters also suggested that transmission providers should
provide guidance regarding required control equipment, such that
developers can better plan for any additional costs of this equipment,
because this may influence how a developer configures its project.\380\
Commenters further recommended that the Commission require transmission
providers to use operating assumptions for interconnection studies that
are based on a hybrid resource's specific configuration.\381\ In one
example, Clean Grid Alliance asserted that the MISO generator
interconnection process does not account for all applications of
electric storage resources because it studies storage at 100% dispatch
in all planning scenarios.\382\ Clean Grid Alliance noted that this
problem is particularly pronounced for hybrid resources, where each
component is separately submitted to the MISO queue, because the
electric storage component is assessed for impacts to the transmission
system in operating scenarios that will never exist.
---------------------------------------------------------------------------

    \380\ Hybrid Resources Coalition, Comments, Docket No. AD20-9-
000, at 12 (filed Sept. 20, 2021).
    \381\ Id. at 10-11; Pine Gate, Comments, Docket No. AD20-9-000,
at 6 (filed Sept. 20, 2021).
    \382\ Clean Grid Alliance, Comments, Docket No. AD20-9-000, at 3
(filed Sept. 20, 2021).
---------------------------------------------------------------------------

    276. Providing another perspective, EEI stated that transmission
providers may need to gain more experience with the operation of hybrid
resources before determining whether new study approaches are
necessary. EEI contended that this could allow transmission providers
the time needed to gain more experience with hybrid resources in order
to inform the need for new study approaches in the future.\383\
---------------------------------------------------------------------------

    \383\ Edison Electric Institute, Comments, Docket No. AD20-9-
000, at 6 (filed Sept. 20, 2021).
---------------------------------------------------------------------------

    277. In addition, commenters such as NYISO raised concerns that
requiring transmission providers to change operating assumptions for
interconnection studies could pose reliability and market
concerns.\384\ NYISO argued that it needs to study the actual minimum
and maximum capabilities of a proposed resource to consider potential
market impacts of that resource. NYISO asserted that studying a
proposed resource based on its planned operational parameters would
limit the resources available to system operators to address system
needs during real-time operation and could result in directing the
operation or curtailment of other generating facilities out of economic
merit order because the transmission system is not sufficiently
robust.\385\
---------------------------------------------------------------------------

    \384\ NYISO, Reply Comments, Docket No. AD20-9-000, at 8 (filed
Oct. 20, 2021).
    \385\ Id. at 8-9.
---------------------------------------------------------------------------

    278. Some participants in and commenters to the Commission's 2016
technical conference on generator interconnection agreements identified
CAISO's approach as a best practice for modeling electric storage
resources in interconnection studies during the conference and in post-
technical conference comments.\386\
---------------------------------------------------------------------------

    \386\ Review of Generator Interconnection Agreements and
Procedures, Technical Conference Transcript, Docket No. RM16-12-000,
at Tr. 239-240 (May 13, 2016); RES Americas, Comments, Docket No.
RM16-12-000, at 3 (filed June 30, 2016).
---------------------------------------------------------------------------

iii. Need for Reform
    279. We expect that, in many cases, the operating assumptions used
for interconnection studies will be sufficient to accurately identify
the network upgrades needed to reliably interconnect many generating
facilities. However, as newer technologies with operating parameters
that differ from traditional generation seek to interconnect, we
preliminarily find that it is necessary for transmission providers to
use assumptions that accurately reflect the operating parameters of
electric storage resources and co-located resources containing electric
storage resources (including hybrid resources), so that the unique
operating characteristics of such resources are taken into account
during the generator interconnection process. If the operating
assumptions for interconnection studies do not reflect the operational
pattern of the interconnecting generating facilities, it is possible
that interconnection studies will overestimate the proposed generating
facilities' impact on the transmission system, thereby assigning
network upgrades to the interconnection customer that would be
unnecessary under planned operations. Because the pro forma LGIP
includes only general requirements regarding the operating assumptions
for generating facilities in interconnection studies, we are concerned
that electric storage resources, and co-located resources containing
electric storage resources (including hybrid resources), may be studied
under inappropriate operating assumptions that result in assigning
unnecessary network upgrades and increased costs to interconnection
customers. We therefore preliminarily find that the lack of realistic
operating assumptions used in interconnection studies for electric
storage resources and co-located resources containing electric storage
resources (including hybrid resources) can result in excessive and
unnecessary network upgrades and may hinder the timely development of
new generation, thereby stifling competition in the wholesale markets,
and resulting in rates, terms, and conditions that are unjust and
unreasonable. Further, we preliminarily find that the lack of
appropriate operating assumptions used in interconnection studies may
present an unduly discriminatory or preferential barrier to the
interconnection of electric storage resources and co-located resources
containing electric storage resources (including hybrid resources).
iv. Proposal
    280. We propose to revise the pro forma LGIP to require
transmission providers, at the request of the interconnection customer,
to use operating assumptions for interconnection studies that reflect
the proposed operation of an electric storage resource or co-located
resource containing an electric storage resource (including hybrid
resources)--i.e., whether the interconnecting resource will or will not
charge during peak load conditions, unless good utility practice,
including applicable reliability standards, otherwise require the use
of different operating assumptions. Such operating assumptions shall be
proposed by the interconnection customer as part of its initial
interconnection request. We believe this will ensure that the
flexibility provided by this reform does not delay the cluster study
process as proposed earlier in this NOPR, and does not delay
interconnection studies, or otherwise harm other interconnection
customers in the cluster because all operating assumptions for
interconnection studies would be clarified prior to entering a cluster
study process. Such operating assumptions must be reasonably
representative of the likely behavior of an electric storage resource
or co-located resource containing an electric storage resource
(including hybrid resources) and, in cases where available, consistent

with the historical performance of such resources in the relevant
geographic area. Further, to help facilitate alignment between as-
studied and real-world conditions, we propose to allow transmission
providers to hold interconnection customers to the intended operation
of their electric storage resource or co-located resource containing an
electric storage resource (including hybrid resources) by: (1)
memorializing these operating restrictions in the interconnection
customer's LGIA; (2) requiring control technologies (software and/or
hardware) in cases where appropriate, such as for electric storage that
wishes to limit its operations, with such protection devices included
in Appendix C of the LGIA. If the interconnection customer fails to
operate its electric storage resource or co-located resource containing
an electric storage resource (including hybrid resources) in accordance
with these conditions as memorialized in the LGIA, the interconnection
customer may be considered in breach and the transmission provider may
pursue termination pursuant to article 17 of the LGIA.
    Additionally, we propose to require that any transmission provider
that requires electric storage resources or co-located resources
containing an electric storage resource (including hybrid resources) to
install control technologies to publicly post a list of acceptable
control technologies. Furthermore, we propose revisions to the
description of the ERIS and NRIS studies in sections <IP_ADDRESS>. and
<IP_ADDRESS> of the pro forma LGIP to accommodate this proposed reform.
    281. We propose to require that interconnection customers clearly
communicate to the transmission provider the expected operating
patterns of the electric storage resource, or co-located resource
containing an electric storage resource (including hybrid resources).
In addition, for the electric storage resource or co-located resource
containing an electric storage resource (including hybrid resources) to
be studied, the interconnection customer must specify, as part of its
initial interconnection request, the ancillary services that it would
or would not provide so that the proper operating assumptions may be
made in interconnection studies. Regardless of any changes to operating
assumptions, all electric storage resources, or co-located resources
containing an electric storage resource (including hybrid resources)
must continue to meet all requirements in the pro forma LGIP and pro
forma LGIA, as well as all applicable reliability standards.
    282. Under this proposed reform, studies based on operational use
cases would reflect the planned operation of the electric storage
resource, or co-located resource containing electric storage resource
(including hybrid resources). Order No. 845 provides precedent for the
Commission to require transmission providers to revise their
interconnection study assumptions to ensure just and reasonable rates.
In Order No. 845, the Commission revised the pro forma LGIP to require
transmission providers to allow interconnection customers' requests to
be studied and modeled below their full generating capacity.\387\ Under
this proposed reform, each transmission provider's operating
assumptions used in their interconnection studies would be required to
take into consideration the services that the generating facility would
provide and the timing of such services, as applicable.\388\ This could
be done in a variety of ways, and the transmission provider would have
flexibility to consider services as best fits its transmission system.
---------------------------------------------------------------------------

    \387\ Order No. 845, 163 FERC ] 61,043 at P 343.
    \388\ This could include potential ancillary services any
generating facility, including hybrid resources, could provide, such
as contingency reserves, ramping or other operating reserves, which
when dispatched or called upon, causes the electric storage device
to be recharged in the peak period to meet its obligations later in
the day.
---------------------------------------------------------------------------

    283. We acknowledge the concern held by some entities that
transmission providers should not be required to study electric storage
resources, or co-located resources containing an electric storage
resource (including hybrid resources) according to their intended
operation because it is not possible to guarantee that those resources
will not deviate from the intended operating assumptions.\389\ However,
we preliminarily find that this concern can be addressed by requiring
interconnection customers to utilize control technologies inherent to
electric storage resources \390\ to ensure that the operation does not
deviate from the proposed operational pattern, consistent with the
Commission's requirements for requesting interconnection service below
full generating capacity. We seek comment on the extent of the
potential burden on transmission providers in tracking the usage of
such operating limitations.
---------------------------------------------------------------------------

    \389\ NYISO, Reply Comments, Docket No. AD20-9-000, at 8 (filed
Oct. 20, 2021).
    \390\ See, e.g., AES Companies, Comments, Docket No. RM16-12-
000, at 14-15 (filed June 21, 2016); Energy Storage Association,
Comments, Docket No. RM16-12-000, at 2-3, 7-8 (filed June 30, 2016);
Hybrid Resources Coalition, Comments, Docket No. AD20-9-000, at 16
(filed Sept. 20, 2021).
---------------------------------------------------------------------------

    284. As noted previously, when studying the charging of an electric
storage resource or co-located resources containing an electric storage
resource (including hybrid resources), assuming for purposes of
operating assumptions in interconnection studies that all such
resources will behave like firm load and add to peak demand without the
ability to respond to signals from the transmission provider to curtail
charging, is inaccurate and can lead to expensive and unnecessary
network upgrades.
    285. For that reason, we propose to clarify that the proposed
reform described in this section to study electric storage resources,
or co-located resources containing an electric storage resource
(including hybrid resources) according to their planned operating
assumptions at the request of the interconnection customer as part of
its initial interconnection request is intended to mean the operating
assumptions for withdrawals of energy (e.g., the charging of an energy
storage resource) in interconnection studies. In line with the proposed
reform as described above, we propose to require that the
interconnection customer include in its initial interconnection request
any operating assumptions for withdrawals of energy to be used by the
transmission provider in interconnection studies.
    286. We seek comment on whether the Commission should expand this
reform to address operating assumptions for additional generating
facility technologies that may currently be inaccurately modeled, such
as variable energy resources. For example, we seek comment on whether
the Commission should expand this proposal to specify only that, at the
interconnection customer's request, a transmission provider must not
study generating facilities in ways that are not physically possible,
for example studying a solar resource as producing energy at night, or
a wind resource as producing maximum energy during low wind seasons, or
other circumstances wherein any resource is studied in ways that are
not physically possible, subject to the same proposed requirement that
the generating facility be equipped with sufficient control technology,
such as special protection systems, and/or subject to penalties for
deviating from dispatch. We seek comment on whether other operating
assumptions, in addition to the assumption that electric storage
resources withdraw energy during peak load periods, should be
considered as part of this proposed reform.
    287. We seek comment on how the Commission should define the study
parameters (e.g., should the Commission

define the ``peak load period'' and/or ``net peak load'' during which
transmission providers must not study a generating facility as
withdrawing energy, and if so how).
    288. In addition to this proposed reform, we seek comment on
whether, and if so how, the Commission should define firm and non-firm
charging for electric storage resources and require transmission
providers to define study criteria and possible ways to interconnect
related to both firm and non-firm charging. We seek comment on whether
providing such options would improve the effectiveness of this proposed
reform and whether there would be other consequences of implementing
such an approach. With respect to the definition of firm and non-firm
charging, we seek comment on whether the Commission should, for
example, (1) define firm charging service as interconnection service
that allows the interconnection customer to be eligible to receive
electric energy in a manner comparable to a transmission provider's
load, and (2) define non-firm charging service as interconnection
service that allows the interconnection customer to be eligible to
receive electric energy using the existing firm or non-firm capacity of
the transmission system on an ``as available'' basis, noting that in an
RTO/ISO with market-based congestion management, a generating facility
with non-firm charging service must respond to the RTO's/ISO's dispatch
instructions, including curtailment to manage congestion.
2. Incorporating Alternative Transmission Technologies Into the
Generator Interconnection Process
a. Background
    289. Under the pro forma LGIP and pro forma SGIP, transmission
providers often do not consider newer technologies--such as dynamic
line ratings or advanced power flow control devices--as they identify
network upgrades, and instead tend toward solutions they have more
experience with, such as reconductoring a line or upgrading a
transformer at a transmission substation.\391\ For example,
reconductoring a transmission line provides a certain MW capacity
increase, while dynamic line ratings or advanced power flow control
devices may increase capacity dependent on ambient or transmission
system conditions.
---------------------------------------------------------------------------

    \391\ See supra note 90.
---------------------------------------------------------------------------

    290. To date, the Commission has provided few requirements
regarding how to consider dynamic line ratings and advanced power flow
control devices in generator interconnection processes, and only a
small number of such technologies have been deployed to address impacts
that result from the potential addition of a generating facility.\392\
In the Commission's transmission incentives proceedings, the Commission
is considering reforms to encourage the deployment of ``transmission
technologies that, as deployed in certain circumstances, enhance
reliability, efficiency, and capacity, and improve the operation of new
or existing transmission facilities,'' \393\ which includes the
transmission technologies we discuss in this NOPR. In the ANOPR, the
Commission sought comment on whether there is the potential for grid-
enhancing technologies (GETs) \394\--which also include the
transmission technologies we discuss in this NOPR--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.\395\
---------------------------------------------------------------------------

    \392\ See, e.g., Advanced Energy Economy, Comments, Docket No.
RM21-17-000, at 21 (filed Oct. 12, 2021); EDF Renewables, Comments,
Docket No. RM21-17-000, at 17-18 (filed Oct. 12, 2021).
    \393\ See Elec. Transmission Incentives Pol'y Under Section 219
of the Fed. Power Act, Notice of Proposed Rulemaking, 85 FR 18784
(Apr. 2, 2020), 170 FERC ] 61,204, at P 9, errata notice, 171 FERC ]
61,072 (2020).
    \394\ We do not use or define the term GETs for purposes of
these reforms. However, for accuracy, we use the term GETs to
summarize comments from the ANOPR because many of the technologies
contemplated here are often considered GETs. In the ANOPR, the
Commission referred to GETs as technologies that ``increase the
capacity, efficiency, or reliability of transmission facilities,''
including ``(1) power flow control and transmission switching
equipment; (2) storage technologies, and (3) advanced line rating
management technologies.'' ANOPR, 176 FERC ] 61,024 at n.68. See
also, Transmission Planning and Cost Allocation NOPR, 179 FERC ]
61,028 at P 270 (``Advanced power flow control devices serve a
transmission function. These devices can help the system operator
control power flows over a given path and can include phase shifting
transformers (also known as phase angle regulators) and devices or
systems necessary for implementing optimal transmission switching.
Advanced power flow control devices allow power to be pushed and
pulled to alternate lines with spare capacity leading to maximum
utilization of existing transmission capacity.'')
    \395\ ANOPR, 176 FERC ] 61,024 at P 158.
---------------------------------------------------------------------------

    291. In comments responding to the ANOPR, several commenters \396\
support the consideration of GETs during the generator interconnection
process, with some advocating for a requirement that GETs be considered
in all interconnection studies.\397\ Several commenters note that GETs
can reduce the cost of network upgrades \398\ and the duration of time
spent in interconnection queues.\399\ Commenters state that GETs are
not currently considered in generator interconnection processes.\400\
---------------------------------------------------------------------------

    \396\ American Clean Power Association and Energy Storage
Association (ACPA/ESA), Comments, Docket No. RM21-17-000, at 49
(filed Nov. 30, 2021); CAISO, Comments, Docket No. RM21-17-000, at
113-114 (filed Nov. 30, 2021); Clean Energy Coalition, Supplemental
Comments, Docket No. RM21-17-000, at 7 (filed Nov. 30, 2021); EDF
Renewables, Comments, Docket No. RM21-17-000, at 16-17 (filed Nov.
30, 2021); Environmental Advocates, Comments, Docket No. RM21-17-
000, at 23-25 (filed Nov. 30, 2021); Industrial Customers, Comments,
Docket No. RM21-17-000, at 37 (filed Nov. 30, 2021); Potomac
Economics, Comments, Docket No. RM21-17-000, at 8-9 (filed Nov. 30,
2021); United States Department of Energy, Comments, Docket No.
RM21-17-000, at 48 (filed Nov. 30, 2021).
    \397\ Environmental Advocates, Comments, Docket No. RM21-17-000,
at 23-25 (filed Nov. 30, 2021); Industrial Customers, Comments,
Docket No. RM21-17-000, at 37 (filed Nov. 30, 2021).
    \398\ ACPA/ESA, Comments, Docket No. RM21-17-000, at 49 (filed
Nov. 30, 2021); Environmental Advocates, Comments, Docket No. RM21-
17-000, at 23-25 (filed Nov. 30, 2021); Industrial Customers,
Comments, Docket No. RM21-17-000, at 36-37 (filed Nov. 30, 2021);
Potomac Economics, Comments, Docket No. RM21-17-000, at 8-9 (filed
Nov. 30, 2021).
    \399\ ACPA/ESA, Comments, Docket No. RM21-17-000, at 64-65
(filed Nov. 30, 2021); Environmental Advocates, Comments, Docket No.
RM21-17-000, at 23-25 (filed Nov. 30, 2021).
    \400\ EDF Renewables, Comments, Docket No. RM21-17-000, at 16-17
(filed Nov. 30, 2021).
---------------------------------------------------------------------------

    292. Environmental Advocates state that the Commission should not
simply allow transmission providers to independently decide on the
viability of an alternative transmission technology; rather, the
Commission should ensure that consideration of alternatives is open and
transparent, and that interconnection customers should be able to
determine if the analysis is sufficiently comprehensive.\401\
Similarly, EDF Renewables and ACPA/ESA argue that interconnection
customers should have the opportunity to request GETs as an alternative
solution to a network upgrade.\402\ ACPA/ESA state that electric
storage could be considered a GET for interconnection purposes and
submit that electric storage (and potentially other GETs) should
qualify as a standalone network upgrade and be included under the
option to build.\403\
---------------------------------------------------------------------------

    \401\ Environmental Advocates, Comments, Docket No. RM21-17-000,
at 23-25 (filed Nov. 30, 2021).
    \402\ ACPA/ESA, Comments, Docket No. RM21-17-000, at 64-65
(filed Nov. 30, 2021); EDF Renewables, Comments, Docket No. RM21-17-
000, at 16-17 (filed Nov. 30, 2021).
    \403\ ACPA/ESA, Comments, Docket No. RM21-17-000, at 64-65
(filed Nov. 30, 2021) (citing Order 845-A, 166 FERC ] 61,137 at P 2
n.5 (``Stand alone network upgrades: shall mean Network Upgrades
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.'')).

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

    293. On the other hand, EEI states that there are significant risks
involved with the deployment of new technologies, such as uncertainties
regarding long-term effectiveness, rapidly evolving technology
rendering formerly installed technology obsolete, and concerns
regarding cost recovery for these new investments. Thus, EEI advocates
flexibility, but not a requirement, to evaluate them in the generator
interconnection process.\404\
---------------------------------------------------------------------------

    \404\ EEI, Comments, Docket No. RM21-17-000, at 39 (filed Nov.
30, 2021).
---------------------------------------------------------------------------

b. Need for Reform
    294. Alternative transmission technologies \405\ can provide
substantial benefits to optimize the transmission system in specific
scenarios. Namely, the below identified transmission technologies often
can be deployed both more quickly and at lower costs than other network
upgrades.\406\ As a result, selecting alternative transmission
technologies as a network upgrade or in-lieu of a network upgrade may
reduce interconnection costs by providing lower cost transmission
solutions to interconnect new generating facilities. These technologies
also have the potential to be used as temporary solutions while new
network upgrades are constructed or used in combination with other
network upgrades in generator interconnection processes.\407\
---------------------------------------------------------------------------

    \405\ For purposes of these reforms, alternative transmission
technologies are: advanced power flow control, transmission
switching, dynamic line ratings, static synchronous compensators,
and/or static VAR compensators.
    \406\ See, e.g., State Agencies, Comments, Docket No. RM21-27-
000, at 30-33 (filed Nov. 30, 2021).
    \407\ See, e.g., TAPS, Comments, Docket No. RM21-27-000, at 21-
22 (filed Nov. 30, 2021).
---------------------------------------------------------------------------

    295. Specific opportunities to use alternative transmission
technologies include resolving thermal overloads and/or redirecting
flows following contingencies so that the transmission system will be
operated within system operating limits. This could be achieved with
advanced power flow control or by switching transmission system or
generation elements. Transmission switching can reduce local congestion
and increase transfer capacity. Dynamic line ratings, along with other
alternative transmission technologies, can be used to enable dynamic
injection limits at the point of interconnection and accommodate
additional energy or ancillary services from generating facilities
behind the point of interconnection. Devices such as static synchronous
compensators and static VAR compensators can support or maintain
voltages to avoid voltage collapse situations by increasing load and
generation transfer capability.
    296. Despite these potential benefits, alternative transmission
technologies often do not receive the same consideration during
generator interconnection processes as other network upgrades and have
only been deployed in a small number of instances.\408\ Furthermore,
the current LGIP does not require transmission providers to consider
such technologies. Therefore, reforms to require their consideration
may be necessary to achieve their benefits in generator interconnection
processes. We preliminarily find that failing to consider alternative
transmission technologies that can be deployed both more quickly and at
lower costs than network upgrades may render Commission-jurisdictional
rates unjust and unreasonable.
---------------------------------------------------------------------------

    \408\ See, e.g., Department of Energy, Advanced Transmission
Technologies, at 28-30 (Feb. 12, 2020), https://www.energy.gov/oe/downloads/advanced-transmission-technologies-report; Environmental
Advocates, Comments, Docket No. RM21-17-000, at 20 (filed Oct. 12,
2021); R Street Institute, Comments, Docket No. RM21-17-000, at 3-4
(filed Oct. 12, 2021).
---------------------------------------------------------------------------

c. Proposals
i. Consideration of Alternative Transmission Technologies in
Interconnection Studies Upon Request of the Interconnection Customer
    297. In order to ensure just and reasonable Commission-
jurisdictional rates, we propose to revise the pro forma LGIP and pro
forma SGIP to require transmission providers, upon request of the
interconnection customer, to evaluate the requested alternative
transmission solution(s) during the LGIP cluster study and the SGIP
system impact study and facilities study within the generator
interconnection process.
    298. Here, to provide more certainty for evaluation purposes, and
focus on technologies that serve a transmission function and thus are
subject to Commission jurisdiction, we propose to specify the
technologies that the interconnection customer may request to be
evaluated. Specifically, we propose revisions to the LGIP and SGIP to
require transmission providers to consider the following technologies
within the cluster study of the LGIP and within the system impact study
and facilities study of the SGIP upon request of the interconnection
customer: advanced power flow control, transmission switching, dynamic
line ratings, static synchronous compensators, and static VAR
compensators. Advanced power flow control devices serve a transmission
function. These devices can help the system operator control power
flows over a given path and can include phase shifting transformers
(also known as phase angle regulators) and devices or systems necessary
for implementing optimal transmission switching. Advanced power flow
control devices allow power to be pushed and pulled to alternate lines
with spare capacity leading to maximum utilization of existing
transmission capacity.\409\ Transmission switching, an application of
transmission topology control, consists of strategically removing or
inserting transmission elements into the transmission topology.
Transmission switching can be used to route energy around areas with
high congestion.\410\ A dynamic line rating is a transmission line
rating that applies to a time period of not greater than one hour and
reflects up-to-date forecasts of inputs such as (but not limited to)
ambient air temperature, wind, solar heating, transmission line
tension, or transmission line sag.\411\ Static synchronous compensators
are voltage source converter \412\ devices that consists of a direct
current (DC) voltage source behind a power electronic interface
connected to the alternating current (AC) transmission system through a
transformer. This results in a controllable voltage source and hence
reactive power output.\413\ Static VAR compensators are flexible
alternating current transmission system (FACTS) devices that consist of
thyristor-controlled reactors (TCR), thyristor-switched capacitors
(TSC), and fixed capacitors acting as a harmonic filter.

The TCR consists of reactors in series with thyristor valves that
continuously control the reactive power output by varying the current
flow through the reactor. A TSC consists of capacitors, reactors, and
thyristor valves that simply switch the capacitor in and out of
service. The fixed capacitor is part of the filter that absorbs the
harmonics generated by the thyristor switching, supplying a fixed
reactive power to the transmission system.\414\ We believe that the
deployment of these transmission technologies may reduce
interconnection costs by providing lower cost network upgrades to
interconnect new generating facilities.
---------------------------------------------------------------------------

    \409\ Transmission Planning and Cost Allocation NOPR, 179 FERC ]
61,028, at P 261 (citing T. Bruce Tsuchida et al., Brattle Unlocking
the Queue with Grid-Enhancing Technologies, at 19-20 (Feb. 1, 2021),
https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf).
    \410\ T. Bruce Tscuchida & Rob Gramlich, Improving Transmission
Operation with Advanced Technologies: A Review of Deployment
Experience and Analysis of Incentives 12 (Sustainable FERC Project,
WATT Coalition, White Paper, June 2019), https://www.brattle.com/wp-content/uploads/2021/05/16634_improving_transmission_operating_with_advanced_technologies.pdf
.
    \411\ Managing Transmission Line Ratings, Order No. 881, 87 FR
2244 (Jan. 13, 2022), 177 FERC ] 61,179, at PP 235, 238 (2021).
    \412\ A voltage source converter is a self-commutated device
that synthesizes a voltage waveform with variable magnitude with
respect to the system voltage to control the reactive power
production and consumption of the device.
    \413\ NERC, Reliability Guideline: Reactive Power Planning, at 6
(Dec. 2016) https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Reliability%20Guideline%20-%20Reactive%20Power%20Planning.pdf.
    \414\ Id. at 7.
---------------------------------------------------------------------------

    299. Under this proposal, the interconnection customer may request,
at the relevant scoping meeting, that the transmission provider
consider a single, multiple, or all technologies on this list. The
transmission provider would be required to evaluate the transmission
technologies identified above for feasibility, cost, and time savings
within the cluster study for the LGIP and the system impact study and
facilities study for the SGIP, upon request of the interconnection
customer. The transmission provider, upon this request, must evaluate
the identified transmission technology and, if feasible, determine
whether it should be used, consistent with good utility practice and
other applicable regulatory standards. Transmission providers continue
to retain discretion regarding whether to use the transmission
technology. Potential applications of these transmission technologies
include deployments either as an alternative to a network upgrade or to
go into service on a temporary basis to enable provisional
interconnection service \415\ pending the completion of a network
upgrade. The transmission provider must include evaluation of the
requested transmissions technology or technologies in the cluster study
report and interconnection facilities study report for the LGIP or the
relevant feasibility study, system impact study and/or facilities study
reports for the SGIP.
---------------------------------------------------------------------------

    \415\ Provisional interconnection service is ``Interconnection
Service provided by a Transmission Provider associated with
interconnecting the Interconnection Customer's Generating Facility
to Transmission Provider's Transmission System and enabling that
Transmission System to receive electric energy and capacity from the
Generating Facility at the Point of Interconnection, pursuant to the
terms of the Provisional Large Generator Interconnection Agreement
and, if applicable, the Tariff.'' Pro forma LGIP section 1, pro
forma LGIA art. 1; see Order No. 845, 163 FERC ] 61,043 at P 438.
---------------------------------------------------------------------------

    300. We seek comment on whether the list of alternative
transmission technologies is sufficient. In particular, we seek comment
on whether storage that performs a transmission function, synchronous
condensers, and voltage source converters should be included in the
list of alternative transmission technologies.
    301. We seek comment on whether there are software, operational, or
other barriers to the use of these transmission technologies as
proposed herein. Additionally, we seek comment on whether the use of
alternative transmission technologies as supplements for, in the place
of, traditional network upgrades is sufficient to guarantee a level of
service to accommodate an interconnection customer seeking NRIS, or
whether such a network upgrade can only relate to ERIS. We seek comment
on whether the existing study processes and models in the generator
interconnection process remain suitable for considering alternative
transmission technologies, whether additional processes or models are
needed, and if so, which entity should be responsible for developing
them. We seek comment on how costs incurred for evaluating alternative
transmission technology study requests would be allocated among
interconnection customers in the cluster. We also seek comment on what
reasonable number of transmission technology study requests from each
interconnection customer would be workable, the burden (in terms of
both time and resources) on transmission providers required to evaluate
such requests, and whether interconnection study deadlines may need to
be extended to account for time needed to evaluate the alternative
transmission technology study requests. Lastly, we seek comment on
whether provisional interconnection service consideration for
transmission technologies should be mandatory.
ii. Annual Informational Report
    302. In order to add transparency to the evaluation process and
deployment of alternative transmission technologies in generator
interconnection processes, we propose to revise the pro forma LGIP and
pro forma SGIP to require transmission providers to submit an annual
informational report to the Commission that details whether, and if so
how, advanced power flow control, transmission switching, dynamic line
ratings, static synchronous compensators, and static VAR compensators
were considered in interconnection requests over the last year. We
propose to create a new docket to collect all annual informational
report filings. Any informational reports that transmission providers
file at the Commission would be for informational purposes and would
neither be formally noticed nor require additional action by the
Commission.\416\ In addition, we note that future interconnection
customers, as well as transmission providers, may benefit from
information as to why an alternative transmission technology that was
considered was not deployed. Because identifying common obstacles to
the use of these alternative transmission technologies would allow
potential interconnection customers to submit more meaningful requests,
we seek comment as to whether to require transmission providers to
include such explanations in their annual reports. Additionally, we
seek comment on the scope of the annual informational report, and
whether additional information should be included.
---------------------------------------------------------------------------

    \416\ Order No. 845, 163 FERC ] 61,043 at P 305 (citing Grid
Assurance LLC, 154 FERC ] 61,244, at n.106, order on clarification,
156 FERC ] 61,027 (2016)).
---------------------------------------------------------------------------

3. Modeling and Performance Requirements for Non-Synchronous Generating
Facilities
a. Background
    303. The transmission system is experiencing change driven by the
differing characteristics of generating facilities seeking to
interconnect and the increased penetration of non-synchronous
generating facilities.\417\ We are concerned that the pro forma LGIP
and pro forma SGIP may be inadequate to address certain challenges
associated with these changes, which is rendering Commission-
jurisdictional rates unjust and unreasonable and unduly discriminatory
or preferential through less specific or less strict modeling and
performance requirements compared to synchronous generating facilities.
We begin with background on: (1) prior Commission action relating to
modeling and performance requirements for all interconnection
customers; (2) the unique attributes of non-synchronous generating
facilities; (3) NERC-documented non-synchronous generation disturbance
events; (4) NERC actions to address the impact of non-synchronous
generating facilities on the bulk-power system; and (5) initiatives by
individual transmission providers to address the reliability challenges
associated with non-synchronous

generating facilities during the generator interconnection process.
---------------------------------------------------------------------------

    \417\ See, e.g., U.S. Energy Info. Admin., Monthly Energy Review
at section 10.1 (Mar. 2022), https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf (EIA March Review).
---------------------------------------------------------------------------

i. Commission Precedent
    304. To ensure that transmission providers can model an
interconnecting generating facility's impact on the transmission
system, Order Nos. 2003 and 2006 established that interconnection
customers must submit technical data specified in Attachment A to
Appendix 1 of the pro forma LGIP or Attachment 2 of the pro forma SGIP
along with their interconnection request. Order Nos. 2003 and 2006 also
established section 4.4 (Modification) of the pro forma LGIP and
section 1.4 (Modification of the Interconnection Request) of the pro
forma SGIP, which detail the process for any type of interconnection
customer seeking to modify its interconnection request.
    305. Additionally, the Commission has imposed certain performance
requirements on generating facilities through the generator
interconnection process. Order No. 2003 required large generating
facilities to ensure that they can ``ride through'' abnormal over-
frequency and under-frequency deviations.\418\ Specifically, article
9.7.3 of the pro forma LGIP requires an interconnection customer to
implement under-frequency and over-frequency relay set points for a
large generating facility as required by the applicable reliability
council \419\ to ensure ``ride through'' capability of the transmission
system. Article 9.7.3 of the pro forma LGIP defines ``ride through'' as
the ability of the large generating facility to stay connected to and
synchronized with the transmission system during system disturbances
within a range of under-frequency and over-frequency conditions. The
pro forma LGIA does not define specific voltage ride through
capability; rather, article 9.1 of the pro forma LGIP requires the
interconnection customer to comply with the applicable reliability
council requirements.
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    \418\ Order No. 2003, 104 FERC ] 61,103 at PP 562, 566.
    \419\ As discussed below, we also propose in this NOPR to update
the term ``Applicable Reliability Council'' to ``Electric
Reliability Organization'' to reflect current terminology.
---------------------------------------------------------------------------

    306. The Commission later extended ride-through requirements in
other contexts. In Order Nos. 661 and 661-A, the Commission established
uniform standards in Appendix G of the pro forma LGIA that require
large wind generating facilities to demonstrate low voltage ride
through capability.\420\ In Order No. 828, the Commission required
small generating facilities interconnecting pursuant to the pro forma
SGIP to have ride through capability in a manner comparable to large
generating facilities.\421\ In that order, the Commission added
subsection 1.5.7 to the pro forma SGIA, which requires newly
interconnecting small generating facilities to have and enable ride
through capability so that they shall not disconnect during abnormal
frequency and voltage events.\422\ The Commission did not establish
generic ride through requirements, but required (1) each transmission
provider to coordinate the protective equipment settings of small
generating facilities with any automatic load shedding programs and (2)
that the specific ride through settings be consistent with good utility
practice and any standards and guidelines applied by the transmission
provider to other generating facilities on a comparable basis.\423\
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    \420\ Interconnection for Wind Energy, Order No. 661, 70 FR
34993 (June 16, 2005), 111 FERC ] 61,353, order on reh'g, Order No.
661-A, 70 FR 75005 (Dec. 19, 2005), 113 FERC ] 61,254 (2005).
    \421\ Requirements for Frequency & Voltage Ride Through
Capability of Small Generating Facilities, Order No. 828, 81 FR
50290 (Aug. 1, 2016), 156 FERC ] 61,062 (2016).
    \422\ Id. P 25.
    \423\ Id. P 2.
---------------------------------------------------------------------------

    307. Relatedly, in Order No. 842, the Commission required newly
interconnecting large and small generating facilities, both synchronous
and non-synchronous, to install, maintain, and operate equipment
capable of providing primary frequency response as a condition of
interconnection.\424\
---------------------------------------------------------------------------

    \424\ Essential Reliability Servs. & the Evolving Bulk-Power
Sys.--Primary Frequency Response, Order No. 842, 83 FR 9639 (Mar. 6,
2018), 162 FERC ] 61,128, order on clarification and reh'g, 164 FERC
] 61,135 (2018).
---------------------------------------------------------------------------

ii. Non-Synchronous Generating Facilities
    308. While synchronous generating facilities convert rotating
mechanical energy into electrical energy, non-synchronous generating
facilities convert energy using solid-state switches.\425\ Examples of
non-synchronous generating facilities include but are not limited to
solar photovoltaics (PV), wind, fuel cell, and battery storage.
---------------------------------------------------------------------------

    \425\ See e.g., Paul Evans, Engineering Mindset, Power Inverters
Explained (Apr. 25, 2020), https://theengineeringmindset.com/power-inverters-explained/.
---------------------------------------------------------------------------

    309. Present day non-synchronous generating facilities
predominantly use grid-following inverters.\426\ This means that they
rely on sensed information from the transmission system (e.g., voltage
waveform) to achieve the desired AC active and reactive power output.
For grid-following inverters, the transmission system state parameters
(e.g., voltage angle) are tracked on the order of milliseconds, meaning
that the inverters can react almost instantaneously to transmission
system conditions. Consequently, non-synchronous generating facilities
are sensitive to even the smallest voltage and frequency changes. If
non-synchronous generating facilities are not properly configured or
programmed to respond to transmission system frequency and voltage
fluctuations, they may fail to ride through a system disturbance (e.g.,
a normally cleared transmission fault) by tripping or entering
momentary cessation mode, as observed in several disturbances described
below. Because non-synchronous generating facilities often employ
similar logic with respect to their response to transmission system
disturbances and non-synchronous generating facility operators often do
not set and coordinate their inverters and plant controllers \427\ to
ride through variations in system voltages during fault conditions,
they are at greater risk of being lost en masse in response to a single
fault on transmission or sub-transmission systems.\428\ In areas of the
transmission system where there is a high saturation of non-synchronous
generating facilities, the en masse response could have an impact
greater than the most severe single contingency identified by
transmission providers.
---------------------------------------------------------------------------

    \426\ Dinesh Pattabiraman et al., Comparison of Grid Following
and Grid Forming Control for a High Inverter Penetration Power
System, 2018 IEEE Power & Energy Society General Meeting (PESGM), at
1, PESGM 8586162 (citing Thomas Ackermann et al., Paving the Way: A
Future Without Inertia Is Closer Than You Think, IEEE Power & Energy
Mag., November/December 2017, at 61).
    \427\ The controller governs the plant's performance to achieve
the desired aggregate real and reactive power production and
performance characteristics. See Mills-Price, M., and Hao, K., The
Importance of Coordinated Control Systems in Solar Generation Plants
(May 2018), https://cms-cdn.selinc.com/assets/Literature/Publications/Technical%20Papers/6658_ImportanceCoordinated_KH_20140729_Web3.pdf?v=20190325-150209.
    \428\ See, e.g., NERC, San Fernando Disturbance, at vi (Nov.
2020), https://www.nerc.com/pa/rrm/ea/Documents/San_Fernando_Disturbance_Report.pdf (San Fernando Disturbance
Report) (``This event, as with past events, involved a significant
number of solar PV reducing power output (either due to momentary
cessation or inverter tripping) as a result of normally-cleared
[bulk-power system] faults. The widespread nature of power reduction
across many facilities poses risks to [bulk-power system]
performance and reliability.'').
---------------------------------------------------------------------------

iii. Documented Non-Synchronous Generation Disturbance Events
    310. As described below, disturbances both on the bulk power system
and on distribution systems have resulted in unexpected loss of solar
PV non-synchronous generating facilities

following normally cleared transmission line faults. NERC and other
relevant entities have analyzed these disturbance events to determine
the causes.
    311. The first documented large-scale reliability event occurred in
August 2016 during the Blue Cut Fire Event in California. Until this
event, the likelihood for non-synchronous generating facilities to trip
or momentarily cease during faults on the bulk-power system was
unclear.\429\ A NERC/Western Electricity Coordinating Council (WECC)
joint task force examined the event and determined that a single 500 kV
line-to-line fault, which was cleared normally by relay protection,
caused a wide area loss of 1,200 MW of solar PV non-synchronous
generating facilities.\430\ The task force report explained that the
loss of solar PV generation during the event was primarily due to
inverter settings susceptible to unexpected tripping and unanticipated
momentary cessation of the non-synchronous generating facilities.\431\
The report indicated that planning studies did not predict that the
generating facilities would not ride through the disturbance and would
fail to provide power during the event. Once aware of the potential for
non-synchronous generating facilities to trip or enter momentary
cessation in response to faults, Southern California Edison Company and
CAISO reviewed the Supervisory Control and Data Acquisition (SCADA)
data and discovered that this was not an isolated incident.\432\
---------------------------------------------------------------------------

    \429\ See, e.g., NERC, Potential Bulk System Reliability Impacts
of Distributed Resources, at 24 (Aug. 2011), https://www.nerc.com/files/IVGTF_TF-1-8_Reliability-Impact-Distributed-Resources_Final-Draft_2011%20(2).pdf (noting NERC's awareness of the practice of
utilities in North America to set up distributed generation to trip
during off[hyphen]normal frequency and voltage conditions).
    \430\ NERC, 1,200 MW Fault Induced Solar Photovoltaic Resource
Interruption Disturbance Report, at 1 (June 2017), https://www.nerc.com/pa/rrm/ea/1200_MW_Fault_Induced_Solar_Photovoltaic_Resource_/1200_MW_Fault_Induced_Solar_Photovoltaic_Resource_Interruption_Final.pdf (Blue Cut Fire Event Report).
    \431\ Id. at 15-17. Momentary cessation occurs when inverters
stop injecting current into the transmission system during high or
low voltage/frequency conditions that are outside the continuous
operating range. Inverters stop producing power and stop supporting
voltage and frequency, effectively shutting themselves down
temporarily (typically for up to five minutes). See NERC, BPS-
Connected Inverter-Based Resource Performance, at 11-16 (Sept.
2018), https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Inverter-Based_Resource_Performance_Guideline.pdf (NERC IBR
Performance Guideline).
    \432\ Southern California Edison Company and CAISO identified
seven other instances of solar inverter-based resources either
tripping or entering momentary cessation. See Blue Cut Fire Event
Report at 3.
---------------------------------------------------------------------------

    312. Subsequently, there have been other documented instances of
momentary cessation of non-synchronous generating facilities: the
Canyon 2 Fire Event in 2017; \433\ the Angeles Forest and Palmdale
Roost Events in 2018; \434\ the San Fernando Disturbance in 2020; \435\
and multiple events in both ERCOT and CAISO during 2021.\436\ Because
present-day SCADA systems are not able to capture the full extent of
all disturbance events, some smaller-scale events are likely to remain
undetected.\437\
---------------------------------------------------------------------------

    \433\ NERC, 900 MW Fault Induced Solar Photovoltaic Resource
Interruption Disturbance Report, at 1 (Feb. 2018) (Canyon 2 Fire
Event Report).
    \434\ NERC, April and May 2018 Fault Induced Solar Photovoltaic
Resource Interruption Disturbances Report (Jan. 2019) (Angeles
Forest and Palmdale Roost Events Report).
    \435\ San Fernando Disturbance Report at vi.
    \436\ See NERC, Odessa Disturbance (Sept. 2021) https://www.nerc.com/pa/rrm/ea/Documents/Odessa_Disturbance_Report.pdf
(Odessa Disturbance Report); see also NERC and CAISO, Multiple Solar
PV Disturbances in CAISO (Apr. 2022), https://www.nerc.com/pa/rrm/ea/Documents/NERC_2021_California_Solar_PV_Disturbances_Report.pdf
(NERC/CAISO Joint Report).
    \437\ The present-day SCADA recording resolution is unable to
capture events that occur at less than the scan rate of one to four
seconds. See NERC, Reliability Guideline: Improvements to
Interconnection Requirements for BPS-Connected Inverter-Based
Resources, at 56 (Sept. 2019), https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Reliability_Guideline_IBR_Interconnection_Requirements_Improvements.pdf (NERC IBR Interconnection Requirements Guideline).
---------------------------------------------------------------------------

iv. NERC Actions To Address Non-Synchronous Generating Facility Impacts
on the Bulk-Power System
    313. Since the large-scale reliability issues related to non-
synchronous generating facilities during the Blue Cut Fire Event, NERC
has: (1) published multiple disturbance reports documenting the events
described above; \438\ (2) issued two NERC Alerts; \439\ (3) issued two
technical reports; \440\ (4) issued two reliability guidelines
regarding non-synchronous generating facility data collection and
performance; \441\ and (5) published two white papers about the need to
modify Reliability Standards to address this risk.\442\ Together, these
documents indicate that transmission system planning and operations
entities do not have adequate or accurate information about the actual
behavior of non-synchronous generating facilities within their areas
under all operating conditions, and further that these same entities
continue to experience issues that NERC-issued alerts were intended to
address.\443\
---------------------------------------------------------------------------

    \438\ See generally Blue Cut Fire Event Report; Canyon 2 Fire
Event Report; Angeles Forest and Palmdale Roost Events Report; San
Fernando Disturbance Report; Odessa Disturbance Report; and NERC/
CAISO Joint Report.
    \439\ NERC, Industry Recommendation Loss of Solar Resources
during Transmission Disturbances due to Inverter Settings (June
2017) (June 2017 NERC Alert); NERC, Industry Recommendation Loss of
Solar Resources During Transmission Disturbances due to Inverter
Settings--II (May 2018) (May 2018 NERC Alert).
    \440\ NERC, Technical Report (May 2020) (IRPTF Modeling Report);
NERC, WECC Base Case Review: Inverter-Based Resources (Aug. 2020).
    \441\ See NERC IBR Performance Guideline; NERC IBR
Interconnection Requirements Guideline.
    \442\ NERC, IRPTF Review of NERC Reliability Standards (Mar.
2020)https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Review_of_NERC_Reliability_Standards_White_Paper.pdf; NERC, Odessa
Disturbance Follow-Up (Oct. 2021), https://www.nerc.com/comm/RSTC_Reliability_Guidelines/White_Paper_Odessa_Disturbance_Follow-Up.pdf.
    \443\ See, e.g., San Fernando Disturbance Report at vi (``Many
of the issues identified in this disturbance appear systemic and are
not being widely addressed by the solar PV fleet.''); NERC/CAISO
Joint Report at 30 (``BPS reliability is a critical factor during
the interconnection process and presently plants are being
interconnected in an unreliable manner based on studies that
inadequately identify possible reliability issues prior to
commercial operation''); Odessa Disturbance Report at 29 (``While
the IRPWG reliability guidelines are some of the most downloaded
guidelines produced and most widely used across the industry, it is
clear that industry is not adopting the recommendations contained
within NERC reliability guidelines.'').
---------------------------------------------------------------------------

    314. NERC also formed the Inverter-Based Resources Performance Task
Force (IRPTF) \444\ in response to the findings and recommendations of
the Blue Cut Fire Event Report, to explore the performance
characteristics of bulk-power system connected non-synchronous
generating facilities. Among other activities, the IRPTF has published
a variety of whitepapers and reliability guidelines.\445\
---------------------------------------------------------------------------

    \444\ The IRPTF became the IBR Performance Working Group in
October 2020 and then the IBR Performance Subcommittee in March
2022.
    \445\ NERC, IRPTF White Papers, Technical Reports, and
Assessments, https://www.nerc.com/comm/PC/Pages/Inverter-Based-Resource-Performance-Task-Force.aspx (providing links to all IRPTF
resources).
---------------------------------------------------------------------------

    315. In September 2019, NERC issued a Reliability Guideline that
recommends improvements to interconnection requirements for non-
synchronous generating facilities connected to the bulk-power
system.\446\ In that Guideline, NERC recommends that transmission
owners improve their interconnection requirements for non-synchronous
generating facilities that are connected to the bulk-power system.
Specifically, NERC recommends that transmission owners ``require that
newly interconnecting [non-synchronous generating facilities]
continuously inject

current within the `[n]o [t]rip [z]one' of the currently effective
version of Reliability Standard PRC-024'' to address issues with
momentary cessation.\447\ NERC states that non-synchronous generating
facilities should be designed and configured to only use momentary
cessation outside the ``no trip zone'' and only to ``mitigate potential
tripping conditions based on interconnection studies.'' \448\
---------------------------------------------------------------------------

    \446\ NERC IBR Interconnection Requirements Guideline at 1.
    \447\ Id. The currently effective version of Reliability
Standard PRC-24 establishes the ``no trip zone'' for frequency and
voltage ride-through curves.
    \448\ Id. at 9.
---------------------------------------------------------------------------

v. Individual Transmission Providers' Filings
    316. MISO and CAISO recently revised their pro forma generator
interconnection agreements to account for momentary cessation of non-
synchronous generating facilities. The revisions proposed by CAISO (and
accepted by the Commission) clarify that momentary cessation of
inverters during transient transmission line faults violates the
existing requirement in CAISO's pro forma generator interconnection
agreement to remain online unless transient high voltage conditions
rise to 1.20 per unit or more.\449\ The CAISO revisions also clarify
that asynchronous \450\ generating facility inverters may not trip or
cease to inject current for momentary loss of synchrony within the ``no
trip zone'' specified in Reliability Standard PRC-024-2.\451\ Finally,
the revisions require that when generating facilities trip or cease to
inject current, they attempt to resynchronize promptly and
consistently, going from no output to full output in one second or
less.\452\
---------------------------------------------------------------------------

    \449\ Cal. Indep. Sys. Operator Corp., 168 FERC ] 61,003, at P 5
(2019).
    \450\ While inverter-based resources are often technically
``non'' synchronous, CAISO uses the term ``asynchronous'' generally
to apply to any resource that does not generate at 60 Hz.
    \451\ Cal. Indep. Sys. Operator Corp., 168 FERC ] 61,003 at P 6.
    \452\ Id. P 7, n.11 (citing CAISO, CAISO Tariff, app. EE, app. H
(3.0.0), proposed section A(vi).
---------------------------------------------------------------------------

    317. On October 5, 2020, the Commission accepted MISO's proposed
revisions to its pro forma generator interconnection agreement to adopt
recommendations from the NERC Guideline with regard to momentary
cessation, phase jump immunity, monitoring, and protection
settings.\453\ As relevant here, MISO added a new subsection to
Appendix G to its pro forma LGIA that states ``[m]omentary cessation
(ceasing to inject current into the transmission system during a fault
without mechanical isolation) is prohibited in [NERC] reliability
standard PRC-024 no trip zone.'' \454\
---------------------------------------------------------------------------

    \453\ Midcontinent Indep. Sys. Operator, Inc., 173 FERC ] 61,014
(2020).
    \454\ Id. P 4.
---------------------------------------------------------------------------

b. Need for Reform
i. Modeling Requirements
    318. We preliminarily find that the pro forma LGIP and pro forma
SGIP may be unduly discriminatory or preferential to the extent that
they do not require non-synchronous generating facilities to provide
accurate and validated models to transmission providers during the
generator interconnection process. Specifically, while Attachment A to
Appendix 1 of the pro forma LGIP and Attachment 2 to the pro forma SGIP
require all generating facilities to submit certain types of
information, the information required is only sufficient to accurately
model the behavior of synchronous generating facilities. In contrast,
given the electrical characteristics of the inverters used by non-
synchronous generating facilities, additional information is required
to achieve a comparable level of model fidelity.
    319. Additionally, we are concerned that, without a reform to
require interconnection customers developing non-synchronous generating
facilities to provide sufficiently accurate and validated models,
interconnection studies may not identify the appropriate
interconnection facilities and network upgrades needed for that
interconnection request. If the interconnection studies are not able to
identify the appropriate interconnection facilities and network
upgrades, then the interconnection costs assigned to that
interconnection customer may be skewed, resulting in unjust and
unreasonable rates for interconnection service.
ii. Ride-Through Requirements
    320. We preliminarily find that the pro forma LGIA and pro forma
SGIA ride-through provisions may result in undue discrimination and
preferential treatment. While synchronous and non-synchronous
generating facilities are different in many respects, both types of
facilities are able to ``ride through'' system events and remain online
and continue to provide real and reactive power following a
disturbance.\455\ Moreover, given the increasing prevalence of non-
synchronous generating facilities, it is also clear that the loss of
real and reactive power from such generating facilities following a
system disturbance can have significant reliability impacts just like
the loss of synchronous generating facilities.\456\ Therefore, with
respect to the issue of ride-through, both synchronous and non-
synchronous generating facilities can be considered similarly situated.
---------------------------------------------------------------------------

    \455\ See NERC/CAISO Joint Report at 9 (``Multiple solar PV
resources that exhibited momentary cessation . . . [have inverters
that are no longer in production] . . . [N]ew inverters are able to
provide current injection during low voltage ride-through
events.'').
    \456\ See supra PP 309-312.
---------------------------------------------------------------------------

    321. Nevertheless, the existing pro forma LGIA and pro forma SGIA
currently impose differing ride-through requirements because these
provisions fail to account for a non-synchronous generating facilities'
ability to engage in momentary cessation. As discussed above, the Blue
Cut Fire and other disturbance events revealed that some non-
synchronous generating facilities remained physically connected to the
transmission system but, as designed or programmed, stopped or reduced
their injection of real or reactive power onto the transmission system
and entered into momentary cessation. Such performance by a non-
synchronous generating facility can have the same impact on system
reliability as would a similarly sized, synchronous generating facility
prematurely tripping offline in response to a disturbance; however,
this practice of momentary cessation is not expressly prohibited by the
existing ride-through requirements because the generating facility
still remains ``connected to and synchronized with the Transmission
System'' as required by the pro forma LGIA and SGIA.\457\
---------------------------------------------------------------------------

    \457\ Pro forma LGIA art. 9.7.3; pro forma SGIA art. 1.5.7.
---------------------------------------------------------------------------

    322. In establishing the current pro forma LGIA and pro forma SGIA,
the Commission did not specifically consider the issue of momentary
cessation. When Order No. 2003 was promulgated, non-synchronous
generating facilities represented a small proportion of the nation's
installed generating capacity.\458\ As a result, the momentary
cessation of non-synchronous generating facilities was not a mode of
operation that the Commission expressly addressed when it added article
9.7.3 to the pro forma LGIA and adopted the definition of ride-through
in Order No. 2003.\459\
---------------------------------------------------------------------------

    \458\ See, e.g., EIA March Review at 176-177.
    \459\ Order No. 2003, 104 FERC ] 61,103 at PP 562, 566.
---------------------------------------------------------------------------

    323. While the Commission subsequently implemented separate low-
voltage ride-through requirements for wind generating facilities in
Order Nos. 661 and 661-A, that requirement also did not address the
possibility of momentary cessation. In Order No. 661, the Commission
adopted a low voltage

ride-through standard for wind generating facilities but explained that
wind generating facilities would only be required to satisfy that ride-
through requirement if the system impact study demonstrates that such
capability is required to ensure safety or reliability.\460\ However,
in Order No. 661-A, the Commission granted rehearing and required all
wind generating facilities to comply with the low-voltage ride-through
provision without the case-by-case analysis.\461\ Therefore, pursuant
to Order No. 661-A, all wind generating facilities ``shall be able to
remain online'' during voltage disturbances up to certain time periods
and associated voltage levels.\462\ This requirement to ``remain
online'' does not appear to contemplate the possibility that a facility
could remain physically connected to the transmission system but stop
injecting real or reactive power.
---------------------------------------------------------------------------

    \460\ Order No. 661, 111 FERC ] 61,353 at P 26.
    \461\ Order No. 661-A, 113 FERC ] 61,254 at P 31.
    \462\ Id. at app. B (``A wind generating plant shall be able to
remain online during voltage disturbances up to the time periods and
associated voltage levels set forth in the standard below.'').
---------------------------------------------------------------------------

    324. More recently, in Order No. 828, the Commission added article
1.5.7 to the pro forma SGIA to require small generating facilities to
ensure the capability to ride through system disturbances comparable to
large generating facilities.\463\ However, the Commission again did not
specifically consider the issue of momentary cessation. As a result,
neither article 9.7.3 of the pro forma LGIA nor article 1.5.7 of the
pro forma SGIA expressly address whether the momentary cessation of
non-synchronous generating facilities is permitted during system
disturbances.
---------------------------------------------------------------------------

    \463\ Order No. 828, 156 FERC ] 61,062 at P 11.
---------------------------------------------------------------------------

    325. Given advances in inverter technology, we are concerned that
the lack of performance requirements regarding the use of momentary
cessation by non-synchronous generating facilities may not be
supportable on either a technical basis (as this is largely a control
settings issue) or on a cost basis (as implementing the appropriate
inverter settings may not be costly).\464\ Accordingly, we
preliminarily find that the pro forma LGIA and pro forma SGIA ride-
through provisions may be unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \464\ See, e.g., Ran Fu, et al., Nat'l Renewable Energy Lab'y,
U.S. Solar Photovoltaic System Cost Benchmark: Q1 2018, at viii
(Nov. 2018), https://www.nrel.gov/docs/fy19osti/72399.pdf. See also
Cal. Indep. Sys. Operator Corp., 168 FERC ] 61,003, at P 17.
---------------------------------------------------------------------------

iii. Applicability of Ride-Through Requirements
    326. We preliminarily find that the pro forma LGIA may also result
in undue discrimination or preferential treatment due to a gap in the
applicability of ride-through requirements to different generating
facilities. While article 1.5.7 of the pro forma SGIA requires newly
interconnecting small generating facilities to ride through abnormal
frequency and voltage events and not disconnect during such events, the
comparable article 9.7.3 of the pro forma LGIA does not explicitly
require newly interconnecting large generating facilities to ride
through such disturbance events, instead referring to requirements of
``the Applicable Reliability Council'' to ensure ride-through
capability. By referencing the requirements of the ``Applicable
Reliability Council'' rather than explicitly stating the ride-through
requirements (as in article 1.5.7 of the pro forma SGIA), article 9.7.3
of the pro forma LGIA may create a gap in applicability because it
would only apply to those generating facilities that are subject to the
reliability standards, i.e., entities with facilities that meet the
definition of ``bulk electric system'' facilities and are registered
with NERC.\465\ While most generating facilities seeking to
interconnect to the transmission system are subject to the pro forma
LGIP and pro forma LGIA (i.e, generating facilities above 20 MW) are
already subject to the reliability standards, some are not.
Specifically, generating facilities are not required to comply with
reliability standards unless they have a gross individual nameplate
rating greater than 20 MVA or gross plant/facility aggregate nameplate
rating of greater than 75 MVA.\466\ As a result, we are concerned that
there does not appear to be any provision of the pro forma LGIA that
explicitly requires generating facilities with a capacity above 20 MW
but with a gross plant/facility aggregate nameplate rating of 75 MVA or
less to ride through frequency or voltage disturbances. Similarly,
generating facilities that do not explicitly possess an automatic
voltage regulator, such as many non-synchronous generating facilities,
are not subject to the provisions of article <IP_ADDRESS> of the pro forma
LGIA, which are applicable only to generating facilities with speed
governors and voltage regulators.
---------------------------------------------------------------------------

    \465\ NERC's Commission-approved bulk electric system definition
defines the scope of the Reliability Standards and the entities
subject to NERC compliance. Revisions to Electric Reliability
Organization Definition of Bulk Electric System and Rules of
Procedure, Order No. 773, 78 FR 804 (Jan. 4, 2013), 141 FERC ]
61,236 (2012). NERC's bulk electric system definition includes
transmission elements operated at 100 kV and above but does not
include facilities used in the local distribution of electric
energy. The bulk electric system definition also includes dispersed
power producing resources (i.e., non-synchronous generation) that
aggregate to a total capacity greater than 75 MVA. NERC, Glossary of
Terms Used in NERC Reliability Standards (Oct. 8, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
    \466\ See Order No. 773, 141 FERC ] 61,236 at PP 12, 38; see
also NERC Registry Criteria, section I, at 4.
---------------------------------------------------------------------------

    327. There does not appear to be any clear basis for these
distinctions, nor has the Commission previously addressed this
potential gap. As discussed above, all generating facilities newly
interconnecting under the pro forma LGIA are technically capable of
riding through such disturbances.\467\ Given these facts, there does
not appear to be any reason that generating facilities connecting under
the pro forma LGIA that are subject to the reliability standards should
be required to provide a higher level of performance than those that
are not. Accordingly, we preliminarily find that the pro forma LGIA
ride-through provisions may be unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \467\ See supra note 464.
---------------------------------------------------------------------------

c. Proposal
i. Modeling Requirements
    328. We propose to revise the pro forma LGIP and pro forma SGIP to
ensure that all interconnection customers requesting to interconnect a
non-synchronous generating facility must provide the transmission
provider with the models needed for accurate interconnection studies,
as discussed below. This reform is intended to promote a consistent
approach among all generating facilities to reliability, such that all
interconnection customers are required to submit information sufficient
to accurately model the behavior of their proposed generating facility.
Pursuant to this proposal, interconnection customers requesting to
interconnect a non-synchronous generating facility would be required to
provide models that contain the details necessary to accurately model
the performance of the generating facility in response to system
disturbances in accordance with the control system settings that would
be used by the interconnection customer during the commissioning and
operation of the generating facility.
    329. Specifically, we propose to revise Attachment A to Appendix 1
of the pro forma LGIP, and Attachment 2 of the

pro forma SGIP to require each interconnection customer requesting to
interconnect a non-synchronous generating facility to submit to the
transmission provider: (1) a validated user-defined root mean square
(RMS) positive sequence dynamics model; (2) an appropriately
parameterized, generic library RMS positive sequence dynamics model,
including a model block diagram of the inverter control system and
plant control system, that corresponds to a model listed in a new table
of acceptable models or a model otherwise approved by WECC; and (3) a
validated EMT model, if the transmission provider performs an EMT study
as part of the interconnection study process.
    330. First, regarding the validated user-defined model, we propose
to define a ``user-defined model'' as any set of programming code
created by equipment manufacturers or developers that captures the
latest features of controllers that are mainly software based and
represents the entities' control strategies but does not necessarily
correspond to any particular generic library model. In order for this
model to be ``validated,'' it must be confirmed that the equipment
behavior is consistent with the model behavior. This can involve, for
example, an attestation from the interconnection customer that the
model accurately represents the entire generating facility,
attestations from each equipment manufacturer that the user defined
model accurately represents the component of the generating facilities,
or test data.
    331. Second, regarding the table of acceptable generic library
models, this table is based on the current WECC list of approved
dynamic models for renewable energy generating facilities.\468\ WECC's
list of approved dynamic models has also been integrated into NERC
Guidelines.\469\ These models represent the current state of the art
with regard to dynamic modeling requirements for non-synchronous
generating facilities.
---------------------------------------------------------------------------

    \468\ See WECC, WECC Approved Dynamic Model Library (effective
Jan. 28, 2022), https://www.wecc.org/Reliability/Approved%20Dynamic%20Models%20January%202022.pdf.
    \469\ NERC IBR Interconnection Requirements Guideline at 27
(``[T]he [transmission owner] should be clear in the types of models
that are expected to be provided for the interconnection process.
These models should, at a minimum, align with the list of acceptable
models used for interconnection-wide modeling developed by NERC and
the MOD-032 Designees.'') (citing WECC Approved Dynamic Model
Library).
---------------------------------------------------------------------------

    332. We believe that these models represent the full spectrum of
modeling data that transmission providers need to perform accurate
interconnection studies for non-synchronous generating facilities. We
recognize that the modeling data we propose to require from non-
synchronous generating facilities may be more voluminous than that
required of synchronous generating facilities; however, this data
submission requirement is intended to result in a comparable level of
modeling accuracy among all generating facilities.
    333. An interconnection customer's failure to provide the above
information within the deadlines established in the pro forma LGIP and
pro forma SGIP would make the interconnection request incomplete and
will be considered invalid in accordance with section 3.4.3 of the pro
forma LGIP and section 1.3 of the pro forma SGIP. Pursuant to those
provisions, if the interconnection customer does not cure the
deficiency within the 10-day cure period, the interconnection request
will be considered withdrawn pursuant to section 3.7 of the pro forma
LGIP and section 1.3 of the pro forma SGIP.
    334. We also propose to modify subsection 4.4.4 of the pro forma
LGIP and section 1.4 of the pro forma SGIP to require that any proposed
modification of the interconnection request be accompanied by updated
models of the proposed generating facility. This will ensure that the
transmission provider will be able to accurately model the impact of
the interconnection request throughout the interconnection process.
    335. We seek comment on whether these proposed reforms are
necessary and/or sufficient to ensure that interconnection customers
proposing non-synchronous generating facilities submit models during
the generator interconnection process that accurately reflect the
behavior of their proposed generating facility. Further, we seek
comment on whether the inclusion of the table based on NERC Guidelines
that cite WECC-approved models is appropriate. If not, we seek comment
on how the Commission could require interconnection customers to submit
models that are widely known in industry to be accurate without listing
specific models.
ii. Ride-Through Requirements
    336. We propose to require newly interconnecting non-synchronous
generating facilities to continue current injection inside the ``no
trip zone'' of the frequency and voltage ride-through curves of
Reliability Standard PRC-024-3 or its successor standards, in
accordance with NERC's recommendation in the NERC IBR Guideline.\470\
Specifically, we propose to revise existing article 9.7.3 of the pro
forma LGIA to require all newly interconnecting large generating
facilities to ride through abnormal frequency and voltage conditions.
The term ``ride-through'' is defined in article 9.7.3 of the pro forma
LGIA as the ability of the large generating facility to stay connected
to and synchronized with the transmission system during system
disturbances within a range of under-frequency and over-frequency
conditions. We propose to expand the ride-through definition to include
the ability of the large generating facility to stay connected to and
synchronized with the transmission system during system disturbances
within under-voltage and over-voltage conditions as well.
---------------------------------------------------------------------------

    \470\ NERC IBR Interconnection Requirements Guideline at 9.
---------------------------------------------------------------------------

    337. In addition, we propose to revise article 9.7.3 of the pro
forma LGIA and article 1.5.7 of the pro forma SGIA to require that any
newly interconnecting non-synchronous generating facility must have the
ability, during abnormal frequency conditions and voltage conditions
within the ``no trip zone'' defined by Reliability Standard PRC-024-3
or its successor standards, to maintain power production at pre-
disturbance levels unless providing primary frequency response or fast
frequency response, and must have the ability to provide dynamic
reactive power to maintain system voltage in accordance with the
generating facility's voltage schedule. We find such a limited
exception to be appropriate given Order No. 842, which requires all
newly interconnecting generating facilities to provide primary
frequency response during frequency deviations outside of the dead band
parameter, pursuant to article 9.6.4 of the pro forma LGIA and article
1.8.4 of the pro forma SGIA.
    338. We seek comment on whether adherence to these proposed
requirements would be readily achievable through changes to control
settings and whether such changes to control settings could be made at
a relatively minor cost.

iii. Applicability of Ride-Through Requirements
    339. We believe that adding clarity to the expectations for all
generating facilities to provide ride-through capability through
modifications to the pro forma LGIA would ensure that all future
interconnection customers are subject to clear and consistent frequency
and voltage ride-through requirements. At present, the absence of a
clear requirement for all generating facilities to maintain ride-
through capability may unfairly place the responsibility for
maintaining system reliability on the subset of generating facilities
that ride through the disturbance. Furthermore, we have identified no
technical or economic basis to require small and large generating
facilities to follow different voltage and frequency ride-through
requirements.\471\
---------------------------------------------------------------------------

    \471\ Order No. 828, 156 FERC ] 61,062 at P 21.
---------------------------------------------------------------------------

    340. Accordingly, we propose to revise article 9.7.3 of the pro
forma LGIA to require that all newly interconnecting large generating
facilities must provide ride-through capability consistent with any
standards and guidelines that are applied to other generating
facilities in the balancing authority area on a comparable basis. This
proposed reform is intended to address the existing gap in the
applicability of ride-through requirements for large generating
facilities with a capacity above 20 MW and with a gross plant/facility
aggregate nameplate rating 75 MVA or less. In addition, the proposed
reform is consistent with existing language in article 1.5.7 of the pro
forma SGIA that requires newly interconnecting small generating
facilities to ride through abnormal frequency and voltage events and
not disconnect during such events.
    341. In addition to the substantive changes discussed above, we
propose to replace the term ``Applicable Reliability Council'' with
``Electric Reliability Organization,'' and replace the term ``control
area'' with ``Balancing Authority Area'' throughout the pro forma LGIP
and pro forma LGIA. These proposed replacements reflect updated
terminology.\472\
---------------------------------------------------------------------------

    \472\ See NERC, Glossary of Terms Used in NERC Reliability
Standards (Oct. 8, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------

III. Proposed Compliance Procedures

    342. We propose to require each transmission provider to submit a
compliance filing within 180 days of the effective date of the final
rule in this proceeding revising its LGIP, LGIA, SGIP, and SGIA, as
necessary, to demonstrate that it meets the requirements set forth in
any final rule issued in this proceeding. The Commission also proposes
to permit appropriate entities to seek ``regional reliability
variation'' or ``independent entity variations'' from the proposed
revisions to the pro forma.\473\ Some transmission providers may have
provisions in their existing LGIPs, LGIAs, SGIPs, and SGIAs subject to
the Commission's jurisdiction that the Commission has previously deemed
to be consistent with or superior to the pro forma LGIP, pro forma
LGIA, pro forma SGIP, and/or pro forma SGIA or permissible under the
independent entity variation standard or regional reliability standard.
Where these provisions would be modified by the final rule,
transmission providers must either comply with the final rule or
demonstrate that these previously-approved variations continue to be
consistent with or superior to the pro forma as modified by the final
rule or continue to be permissible under the independent entity
variation standard or regional reliability standard.\474\
---------------------------------------------------------------------------

    \473\ See, e.g., Order No. 2003, 104 FERC ] 61,103 at PP 822-
827; Order No. 2006, 111 FERC ] 61,220 at PP 546-550; see also May
Joint Task Force Tr. 41:3-7, 42:23-43:2 (Gladys Brown Dutrieuille)
(expressing support for regional flexibility but also for FERC
``encourag[ing] interconnection efficiencies throughout the country
by promoting best-in-class processes, such as variations in ways to
cluster projects'').
    \474\ See May Joint Task Force Tr. 175:13-17 (Jason Stanek) (``I
think we heard here today that regional flexibility remains
important, but so does having some at least minimal national
baseline because many of these generators are not just building in
PJM or ISO-New England, but across the country.''); id. 22:22-25
(Riley Allen). (``[U]ltimately, there needs to be some room for
flexibility among the regions, but I think there's some
opportunities for more foundational aspects of reform to be common
across regions as well.'').
---------------------------------------------------------------------------

    343. The Commission will assess whether each compliance filing
satisfies the proposed requirements stated above and issue additional
orders as necessary to ensure that each public utility transmission
provider meets the requirements of the subsequent final rule.
    344. We propose that transmission providers that are not public
utilities will have to adopt the requirements of this Proposed Rule as
a condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No. 888.\475\
---------------------------------------------------------------------------

    \475\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission on Servs. by Pub. Utils.; Recovery of
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888,
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036, at 31,760-
763 (1996) (cross-referenced at 75 FERC ] 61,080), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048 (cross-referenced at
78 FERC ] 61,220), order on reh'g, Order No. 888-B, 81 FERC ] 61,248
(1997), order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998),
aff'd in relevant part sub nom. Transmission Access Policy Study
Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New
York v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------

IV. Information Collection Statement

    345. The information collection requirements contained in this NOPR
are subject to review by the Office of Management and Budget (OMB)
under section 3507(d) of the Paperwork Reduction Act of 1995.\476\
OMB's regulations require approval of certain information collection
requirements imposed by agency rules.\477\ Upon approval of a
collection of information, OMB will assign an OMB control number and an
expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to these collections
of information unless the collections of information display a valid
OMB control number.
---------------------------------------------------------------------------

    \476\ 44 U.S.C. 3507(d).
    \477\ 5 CFR 1320.11 (2021).
---------------------------------------------------------------------------

    346. The reforms proposed in this NOPR would revise the
Commission's standard interconnection procedures and agreement (i.e.,
the pro forma LGIP and pro forma LGIA) and the standard small generator
interconnection procedures and agreement (i.e., the pro forma SGIP and
pro forma SGIA) that every public utility transmission provider is
required to include in their non-discriminatory open access
transmission tariff under Sec.  35.28 of the Commission's
regulations.\478\ This NOPR proposes to require each transmission
provider to amend the standard interconnection procedures and agreement
and the standard small generator interconnection procedures and
agreement in its open access transmission tariff to implement the
reforms proposed in this NOPR, which are intended to ensure that the
generator interconnection process is just and reasonable and not unduly
discriminatory or preferential. We will submit the proposed reporting
requirements to OMB for its review and approval under section 3507(d)
of the Paperwork Reduction Act.\479\ The proposed revisions included in
this NOPR would affect the following collections of information: FERC-
516, Electric Rate Schedules and Tariff Filings, and FERC-516A,
Standardization of Small Generator Interconnection Agreements and
Procedures.
---------------------------------------------------------------------------

    \478\ 18 CFR 35.28(f)(1) (2021).
    \479\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    347. Interested persons may obtain information on the reporting

requirements by contacting Ellen Brown, Office of the Executive
Director, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, via email ([email protected]) or telephone
(202) 502-8663.
    348. We solicit comments on the Commission's need for this
information; whether the information will have practical utility; the
accuracy of the burden and cost estimates; ways to enhance the quality,
utility, and clarity of the information to be collected or retained;
and any suggested methods for minimizing respondents' burden, including
the use of automated information techniques.
    349. Please send comments concerning the collections of information
and the associated burden estimates to the Office of Information and
Regulatory Affairs, Office of Management and Budget, through
www.reginfo.gov/public/do/PRAMain. Attention: Federal Energy Regulatory
Commission Desk Officer. Please identify the OMB Control Numbers 1902-
0096 (FERC-516) and 1902-0203 (FERC-516A) in the subject line of your
comments. Comments should be sent within 60 days of publication of this
notice in the Federal Register.
    350. Please submit a copy of your comments on the information
collections to the Commission via the eFiling link on the Commission's
website at http://www.ferc.gov. Comments on the information collection
that are sent to FERC should refer to Docket No. RM22-14-000.
    351. Title: Electric Rate Schedules and Tariff Filings (FERC-516)
and Standardization of Small Generator Interconnection Agreements and
Procedures (FERC-516A).
    352. Action: Proposed revisions of collections of information.
    353. OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0203 (FERC-
516A).
    354. Respondents: Public utility transmission providers, including
RTOs/ISOs.
    355. Frequency of Information Collection: One time during Year 1.
Multiple times during subsequent years.
    356. Necessity of Information: We propose the reforms in this NOPR
to address interconnection queue backlogs, improve certainty, prevent
undue discrimination for new technologies, and ensure that the costs of
network upgrades are allocated in a manner that is roughly commensurate
with benefits. The reforms are intended to ensure that the generator
interconnection process is just and reasonable and not unduly
discriminatory or preferential.
    357. Internal Review: We have reviewed the proposed reforms that
impose information collection burdens and have determined that such
reforms are necessary. These proposed reforms conform to the
Commission's need for efficient information collection, communication,
and management within the energy industry. We have specific, objective
support for the burden estimates associated with the proposed
information collection requirements.
    358. Public Reporting Burden: Our estimates are based on the number
of transmission providers that submitted compliance filings in response
to Order No. 845, which is the Commission's most recent interconnection
rulemaking that required transmission providers to revise their
interconnection procedures and agreements. As such, we estimate that 45
transmission providers, including the RTOs/ISOs, will be subject to
this rulemaking. The burden \480\ and cost estimates below are based on
(1) the initial need for transmission providers to file revised
versions of the standard interconnection procedures and agreements in
Year 1, and (2) ongoing information collection activities in connection
with reporting and disclosure requirements in subsequent years. With
regards to ongoing information collection activities, the NOPR proposes
to add annual and quarterly information collection activities regarding
the provision of public interconnection information, compilation and
posting of metrics related to completion of cluster studies,
compilation and posting of metrics related to penalties for late
interconnection studies following the elimination of the reasonable
efforts standard, and reporting related to the consideration of
alternative technologies in interconnection requests. The NOPR also
proposes an information collection requirement in which transmission
providers will provide affected system operators with data monthly, or
more frequently as needed, during the affected system study process.
For other proposed reforms, we estimate no ongoing information
collection burden because there is either no information collection
aspect of the reform or the proposed requirements would merely supplant
existing ones. We estimate that the reforms proposed in this NOPR would
affect the burden and cost of FERC-516 and FERC-516A as follows.
---------------------------------------------------------------------------

    \480\ ``Burden'' is the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. For
further explanation of what is included in the information
collection burden, refer to 5 CFR 1320.3.
    \481\ Commission staff estimates that respondents' hourly wages
plus benefits are comparable to those of FERC employees. Therefore,
the hourly cost used in this analysis is $87.00 ($180,703 per year).
    \482\ The ongoing burden estimated here reflects the estimated
yearly average of the requirement to provide affected system
operators with data monthly during the affected system study
process.

                                                 Proposed Changes Due to NOPR in Docket No. RM22-14-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Annual number of                             Average burden (hr.) &    Total annual burden
        Proposed requirements             Number of           responses per           Total number of      cost ($) per response   hours & total annual
                                         respondents            respondent         responses  (rounded)            \481\            cost ($)  (rounded)
                                                    (1)  (2)....................  (1) * (2) = (3).......  (4)...................  (3) * (4) = (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        FERC-516:
--------------------------------------------------------------------------------------------------------------------------------------------------------
Informational Interconnection Study.           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Public Interconnection Information..           45 (TPs)  Year 1: 1 Ongoing: 2...  Year 1: 45 Ongoing: 90  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 4 hr; $348.    $15,660 Ongoing: 360
                                                                                hr; $31,320.
Cluster Study.......................           45 (TPs)  Year 1: 1 Ongoing: 4...  Year 1: 45 Ongoing:     Year 1: 80 hr; $6,960   Year 1: 3600 hr;
                                                                                180.                    Ongoing: 4 hr; $348.    $313,200 Ongoing: 720
                                                                                hr; $62,640.
Allocation of Cluster Study Costs...           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Allocation of Cluster Network                  45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 Upgrades.                                                                                Ongoing: 0.             $15,660 Ongoing: 0.

Shared Network Upgrades.............           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
                                                                                Ongoing: 0.             $313,200 Ongoing: 0.
Increased Study Deposits and LGIA              45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 Deposit.                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Demonstration of Site Control.......           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
                                                                                Ongoing: 0.             $313,200 Ongoing: 0.
Commercial Readiness................           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Withdrawal Penalties................           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Transition Process..................           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
                                                                                Ongoing: 0.             $313,200 Ongoing: 0.
Elimination of Reasonable Efforts              45 (TPs)  Year 1: 1 Ongoing: 4...  Year 1: 45 Ongoing:     Year 1: 80 hr; $6,960   Year 1: 3600 hr;
 Standard.                                                                         180.                    Ongoing: 4 hr; $348.    $313,200 Ongoing: 720
                                                                                hr; $62,640.
Affected Systems Study Process......           45 (TPs)  Year 1: 5 Ongoing: 5     Year 1: 225 Ongoing:    Year 1: 80 hr; $6,960   Year 1: 18,000 hr;
                                                          \482\.                   225.                    Ongoing: 80 hr; $6960.  $1,566,000 Ongoing:
                                                                                18,000 hr;
                                                                                $1,566,000.
Affected Systems Pro Forma                     45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 Agreements.                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Affected Systems Modeling and Study            45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 Assumptions.                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Optional Resource Solicitation Study           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Co-Located Generation Sites Behind             45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 One Point of Interconnection with                                                                         Ongoing: 0.             $15,660 Ongoing: 0.
 Shared Interconnection Requests.
Revisions to Material Modification             45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
 to Require Consideration of                                                                               Ongoing: 0.             $313,200 Ongoing: 0.
 Generating Facility Additions.
Availability of Surplus                        45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 Interconnection Service.                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Operating Assumptions for                      45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
 Interconnection Studies.                                                                                Ongoing: 0.             $313,200 Ongoing: 0.
Consideration of Alternative                   45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
 Transmission Technologies in                                                                              Ongoing: 0.             $313,200 Ongoing: 0.
 Interconnection Studies Upon
 Request of Interconnection Customer.
Annual Informational Report.........           45 (TPs)  Year 1: 1 Ongoing: 1...  Year 1: 45 Ongoing: 45  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 4 hr; $348.    $15,660 Ongoing: 180
                                                                                hr; $15,660.
Modeling Requirements...............           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Ride Through........................           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
Applicability of Ride Through.......           45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
                                     -------------------------------------------------------------------------------------------------------------------
    Total for FERC-516..............  Year 1: 1305 Ongoing: 720
                                      Year 1: 49,680 hr; $4,322,160 Ongoing:
                                      19,980 hr; $1,738,260.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       FERC-516A:
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consideration of Alternative                   45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 80 hr; $6,960   Year 1: 3600 hr;
 Transmission Technologies in                                                                              Ongoing: 0.             $313,200 Ongoing: 0.
 Interconnection Studies Upon
 Request of Interconnection Customer.
Modeling Requirements: Transmission            45 (TPs)  Year 1: 1 Ongoing: 0...  Year 1: 45 Ongoing: 0.  Year 1: 4 hr; $348      Year 1: 180 hr;
 Providers.                                                                                Ongoing: 0.             $15,660 Ongoing: 0.
                                     -------------------------------------------------------------------------------------------------------------------
    Total for FERC-516A.............  Year 1: 90 Ongoing: 0
                                      Year 1: 3780 hr; $328,860 Ongoing: 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
        Grand Total (FERC-516 plus    Year 1: 1395 Ongoing: 0
         FERC-516A, including all
         respondents).
                                      Year 1: 53,460 hr; $4,651,020 Ongoing:
                                      19,980 hr; $1,738,260.
--------------------------------------------------------------------------------------------------------------------------------------------------------

        Grand Total Average Per
         Entity Cost (45 TPs).
                                      Year 1: $103,356 Ongoing: $38,628.
--------------------------------------------------------------------------------------------------------------------------------------------------------

V. Environmental Analysis

    359. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\483\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this NOPR under Sec.  380.4(a)(15) of
the Commission's regulations, which provides a categorical exemption
for approval of actions under sections 205 and 206 of the FPA relating
to the filing of schedules containing all rates and charges for the
transmission or sale of electric energy subject to the Commission's
jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classification, and
services.\484\
---------------------------------------------------------------------------

    \483\ Reguls. Implementing Nat'l Envt'l Pol'y Act of 1969, Order
No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ] 30,783
(1987) (cross-referenced at 41 FERC ] 61,284).
    \484\ 18 CFR 380.4(a)(15) (2021).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    360. The Regulatory Flexibility Act of 1980 \485\ generally
requires a description and analysis of proposed and final rules that
will have significant economic impact on a substantial number of small
entities. The Small Business Administration (SBA) sets the threshold
for what constitutes a small business. Under SBA's size standards,\486\
the RTOs/ISOs all fall under the category of Electric Bulk Power
Transmission and Control (NAICS code 221121), with a size threshold of
500 employees (including the entity and its associates).\487\ The six
RTOs/ISOs (SPP, MISO, PJM, ISO-NE, NYISO, and CAISO) each employ more
than 500 employees and are not considered small.
---------------------------------------------------------------------------

    \485\ 5 U.S.C. 601-612.
    \486\ 13 CFR 121.201.
    \487\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3) (citing to Section 3 of the Small Business Act, 15 U.S.C.
632).
---------------------------------------------------------------------------

    361. We estimate that 39 additional transmission providers (after
removing RTO/ISOs) are affected by the reforms proposed in this NOPR.
We estimate that 12 of the 39 transmission providers, approximately
31%, are small entities.
    362. We estimate that one-time costs (in Year 1) associated with
the reforms proposed in this NOPR for one transmission provider (as
shown in the table above) would be $103,356. Following Year 1, we
estimate that the annual ongoing costs for one transmission provider
would be $38,628.
    363. According to SBA guidance, the determination of significance
of impact ``should be seen as relative to the size of the business, the
size of the competitor's business, and the impact the regulation has on
larger competitors.'' \488\ We do not consider the estimated cost to be
a significant economic impact. As a result, we certify that the reforms
proposed in this NOPR would not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------

    \488\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, at 18
(Aug 2017), https://cdn.advocacy.sba.gov/wp-content/uploads/2019/06/21110349/How-to-Comply-with-the-RFA.pdf.
---------------------------------------------------------------------------

VII. Comment Procedures

    364. We invite interested persons to submit comments on the matters
and issues proposed in this NOPR to be adopted, including any related
matters or alternative proposals that commenters may wish to discuss.
Comments are due October 13, 2022. Also, reply comments are due
November 14, 2022. Comments must refer to Docket No. RM22-14-000, and
must include the commenter's name, the organization they represent, if
applicable, and their address.
    365. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's web site at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should 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.
    366. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE,
Washington, DC 20426.
    367. 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 NOPR are not
required to serve copies of their comments on other commenters.

VIII. Document Availability

    368. 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 (http://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).
    369. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.

    370. 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 protected], or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
[email protected].
---------------------------------------------------------------------------

    \489\ We do not include data from SPP in the table. SPP's normal
interconnection queue processing has been modified to address its
large queue backlog and transition to a new interconnection study
process, thus its data is not clearly comparable to the other
regions.

---------------------------------------------------------------------------
By direction of the Commission.

    Commissioner Danly is concurring with a separate statement
attached.

    Commissioner Christie is concurring with a separate statement
attached.
    Issued: June 16, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.

    Note:  The following appendices will not be published in the
Code of Federal Regulations.

Appendix A: Interconnection Study Metrics

                                               Table 1--RTOs/ISOs Interconnection Study Metrics 2021 \489\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Studies completed   Current delayed
          Transmission provider                           Link                Completed studies    past deadline         studies          Withdrawals
--------------------------------------------------------------------------------------------------------------------------------------------------------
CAISO....................................  http://oasis.caiso.com/mrioasis/                 179                116                  0                 88
                                            logon.do.
ISO-NE...................................  https://www.oasis.oati.com/isne/.                 44                 31                 19                 25
MISO.....................................  https://cdn.misoenergy.org/                      778                754                385                204
                                            MISO%20Generator%20Interconnecti
                                            on%%20Metrics444684.pdf.
NYISO....................................  https://www.nyiso.com/                            16                 13                 48                 46
                                            interconnections.
PJM......................................  https://www.pjm.com/-/media/                   1,213                149              1,281                297
                                            planning/services-requests/
                                            interconnection-study-
                                            statistics.ashx.
--------------------------------------------------------------------------------------------------------------------------------------------------------

                         Table 2--Non-RTOs/ISOs Interconnection Study Metrics 2021 \490\
----------------------------------------------------------------------------------------------------------------
                                                                                Current
     Transmission provider            Link           Completed    Completed past      delayed       Withdrawals
                                                      studies        deadline         studies
----------------------------------------------------------------------------------------------------------------
Alabama Power Company           https://                     157  ..............  ..............              61
 (Southern Company).             www.oasis.oati.
                                 com/SOCO/
                                 index.html.
Arizona Public Service........  https://                      22              20             198              18
                                 www.oasis.oati.
                                 com/azps/.
Avista Corp...................  https://                      20              19              35               3
                                 www.oasis.oati.
                                 com/avat/.
Black Hills Colorado..........  https://                       3  ..............               2               2
                                 www.blackhillsc
                                 orp.com/
                                 utilities-
                                 businesses/
                                 transmission/
                                 electric-
                                 transmission-
                                 services.
Black Hills Power.............  https://                       1  ..............  ..............  ..............
                                 www.blackhillsc
                                 orp.com/
                                 utilities-
                                 businesses/
                                 transmission/
                                 electric-
                                 transmission-
                                 services.
Dominion Energy South Carolina  https://                       3               3              70               4