facility is accurate throughout the interconnection study process will
allow the interconnection customer to understand the actual, potential
impact on their interconnection request of changing these project
components as they are considering such technological advancements.
---------------------------------------------------------------------------

    \3171\ ENGIE Initial Comments at 13-14.
---------------------------------------------------------------------------

    1669. Similarly, we disagree with commenters that argue that
accurate models for non-synchronous generating facilities may not be
available early in the interconnection study process and may need to be
updated during that process.\3172\ We find that the reforms we adopt
herein are consistent with the principles behind other requirements in
the pro forma LGIP and pro forma SGIP, namely those that set forth
requirements for an interconnection request, including requirements
that requests be viable and well-defined.\3173\ The requirement to
submit accurate models also reduces the chance that a transmission
provider would need to perform additional studies, in this case if an
interconnection customer submits models that are inaccurate and those
inaccuracies are not discovered until late in the interconnection
process. In that instance, i.e., if model validation occurs at a point
further into the interconnection process, inaccurate models that are
used in interconnection studies could create errors in the studies,
potentially leading to restudies and subsequent delays which would
frustrate the efficiency gained by moving to a first-ready, first-
served cluster study process. Further, we find that the definition of a
validated model (i.e., confirmation that the equipment behavior is
consistent with the modeled behavior) is sufficiently flexible to
enable interconnection customers to provide such a model with their
interconnection requests.\3174\ Moreover, the option for the
interconnection customer to submit an attestation that the models
accurately reflect the expected behavior of a proposed generating
facility would be based in the interconnection customer's best
understanding at the time of the interconnection request, providing
further flexibility if the interconnection customer chooses to change
the equipment or control systems of the proposed generating facility,
which is permitted as part of the interconnection process.
---------------------------------------------------------------------------

    \3172\ Alliant Energy Initial Comments at 10-11; Clean Energy
Associations Initial Comments at 66; EPRI Initial Comments at 17-18;
NextEra Initial Comments at 40; [Oslash]rsted Initial Comments at
17; Pine Gate Initial Comments at 61; PPL Initial Comments at 25;
Public Interest Organizations Reply Comments at 13; SEIA Initial
Comments at 42.
    \3173\ Pro forma LGIP section 3.4.1; pro forma SGIP section 1.3.
    \3174\ Pro forma LGIP Attachment A to Appendix 1.
---------------------------------------------------------------------------

    1670. In addition, we do not believe, as suggested by
commenters,\3175\ that there is a need to require transmission
providers to make available additional information and system data in
order for an interconnection customer to develop an RMS model. Although
measured transmission system information is an input into the RMS
model, the purpose of the model is to represent the behavior of the
facility itself, and the interconnection customer should be able to use
likely transmission system configurations to parameterize and validate
the RMS model. To the extent that the interconnection customer believes
that actual transmission data is required to tune the model block
diagram, the scoping meeting provides a venue for such discussions. The
provisions set forth in new pro forma LGIP section 3.4.6 further detail
scoping meetings, which occur during the customer engagement window.
---------------------------------------------------------------------------

    \3175\ SEIA Initial Comments at 42; Tesla Initial Comments at
11.
---------------------------------------------------------------------------

    1671. We decline to adopt requirements that constrain the
discretion of transmission providers to use either user-defined RMS
models or generic library RMS models, as suggested by commenters.\3176\
We find that the transmission provider is in the best position to
determine the power flow modeling method that is best suited to
ensuring the reliability of its system.
---------------------------------------------------------------------------

    \3176\ Clean Energy Associations Initial Comments at 65-66;
Eversource Initial Comments at 39; ISO-NE Initial Comments at 42-43;
MISO Initial Comments at 125; SEIA Initial Comments at 43; Tesla
Initial Comments at 11.
---------------------------------------------------------------------------

    1672. We decline to modify the NOPR proposal to allow the
transmission provider to require either a user-defined RMS model or a
generic library RMS model, as suggested by Clean Energy Associations,
rather than requiring the interconnection customer to submit both, as
adopted in this final rule.\3177\ We believe that requiring the
interconnection customer to submit both models is of value in providing
the transmission provider discretion to choose which model most
accurately represents a given generating facility's behavior. Providing
these models does not represent an unreasonable burden on the
interconnection customer, as the process of developing and
parameterizing an RMS model is significantly simpler than doing so for
an EMT model.
---------------------------------------------------------------------------

    \3177\ Clean Energy Associations Initial Comments at 65-66.
---------------------------------------------------------------------------

    1673. We decline to require the user-defined RMS model to be
compatible with the transmission provider's software and meet the
transmission provider's MOD-032-1 requirements at the time the
interconnection request is submitted, as requested by MISO.\3178\ While
the user-defined RMS model will have to meet these requirements prior
to the cluster study for generating facilities seeking to interconnect
pursuant to the pro forma LGIP and optional feasibility study or system
impact study for generating facilities seeking to interconnect pursuant
to the pro forma SGIP, the scoping meeting is the appropriate time to
provide and discuss this information in order to correct the model if
it is incompatible with the transmission provider's software or
otherwise causes the transmission system model to be unable to
solve.\3179\
---------------------------------------------------------------------------

    \3178\ MISO Initial Comments at 125.
    \3179\ The scoping meeting is a meeting between representatives
of the interconnection customer and transmission provider ``to
exchange information including any transmission data and earlier
study evaluations that would be reasonably expected to affect such
interconnection options,'' and ``to analyze such information.''
Appendix C, pro forma LGIP section 1.
---------------------------------------------------------------------------

    1674. We decline to require NERC to improve the degree to which
power flow software vendors allow accurate modeling of IBR technology,
as requested by Longroad Energy.\3180\ While we agree that improved
accuracy of IBR modeling is beneficial, this rulemaking is focused on
entities that execute, or request the unexecuted filing of, LGIAs and
SGIAs, and placing obligations on NERC or vendors is outside the scope
of this proceeding. Equipment providers can develop and submit
validated generic models to the software vendors' model libraries or
the WECC model validation process to be included in the WECC table of
approved models, if they desire to do so.
---------------------------------------------------------------------------

    \3180\ Longroad Energy Reply Comments at 20.
---------------------------------------------------------------------------

    1675. In response to commenters that argue that the Commission
should provide further direction regarding model validation
requirements for non-synchronous generating facilities,\3181\ we note
that Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2
of the pro forma SGIP, as adopted in this final rule, provide that, for
a model to be ``validated,'' the interconnection customer must provide
evidence that the equipment behavior is consistent with the model
behavior. In addition, Attachment A to Appendix 1 of the pro forma LGIP
and Attachment 2 of the pro

forma SGIP provide that 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
relevant component of the generating facility, or test data. We find
that this definition of a ``validated'' model and examples of an
attestation in the proposal are sufficient and provide flexibility to
allow interconnection customers to provide such a model with their
interconnection requests. Therefore, we decline to adopt alternative
proposals for model validation put forth by commenters.
---------------------------------------------------------------------------

    \3181\ EPRI Initial Comments at 14-15; Clean Energy Associations
Initial Comments at 66-67; NERC Initial Comments at 18-20;
[Oslash]rsted Initial Comments at 16, 18; SDG&E Reply Comments at 3;
Tesla Initial Comments at 10.
---------------------------------------------------------------------------

    1676. We decline to adopt alternatives and revisions to the table
of acceptable generic library models based on the current WECC list of
approved dynamic models for renewable energy generating facilities, as
suggested by R Street and EPRI.\3182\ We find that the table, as
adopted, is appropriate because it represents the full spectrum of
modeling data that transmission providers need to perform accurate
interconnection studies for non-synchronous generating facilities.
Nevertheless, we recognize that the list of models approved by WECC is
subject to change and note that the table provides that ``a model
otherwise approved by [WECC],'' \3183\ and not reflected in the table,
would also meet the model requirements.
---------------------------------------------------------------------------

    \3182\ EPRI Initial Comments at 20; R Street Initial Comments at
17.
    \3183\ Pro forma LGIP, app. 1, attach. A; Pro forma SGIP,
attach. 2.
---------------------------------------------------------------------------

    1677. In response to commenters that oppose a requirement for a
validated EMT model,\3184\ we note that these concerns mischaracterize
the NOPR proposal as mandating EMT models on a national basis. Rather,
Attachment A to Appendix 1 of the pro forma LGIP and Attachment 2 of
the pro forma SGIP, as adopted, requires that, in circumstances where
the transmission provider performs an EMT study as part of its
interconnection study process, the interconnection customer must
provide an EMT model. We find that the transmission provider is in the
best position to determine whether an EMT study is necessary to ensure
system reliability because the transmission provider has the in-depth
knowledge of its transmission system required to recognize where and
when regular dynamic modeling is inadequate to capture the true
behavior of generating facilities.
---------------------------------------------------------------------------

    \3184\ AES Initial Comments at 26; Bonneville Initial Comments
at 24; Invenergy Initial Comments at 57-58; Longroad Energy Reply
Comments at 21; SEIA Initial Comments at 41-42.
---------------------------------------------------------------------------

    1678. Similarly, we decline to adopt EPRI's request to require EMT
models regardless of whether the transmission provider performs an EMT
study.\3185\ Developing an EMT model may place an unreasonable
administrative burden on an interconnection customer in situations
where such a model is not used by the transmission provider. We also
decline to adopt EPRI's request to allow use of an industry-accepted,
generic EMT model instead of a validated EMT model, as the record does
not indicate that any such industry-accepted, generic models currently
exist.\3186\
---------------------------------------------------------------------------

    \3185\ EPRI Initial Comments at 19.
    \3186\ Id. at 15.
---------------------------------------------------------------------------

    1679. We decline Clean Energy Associations' request that the
Commission require submission of an EMT model one year before the
scheduled commercial operation date of the non-synchronous generating
facility if the transmission provider performs an EMT study as part of
the interconnection study process.\3187\ As noted above, we find that
the proposal for models to be submitted with the interconnection
request is consistent with the principles behind other requirements in
the pro forma LGIP and pro forma SGIP and that transmission providers
need these models to perform interconnection studies and ensure that
prospective generating facilities do not create reliability risks to
the transmission system. In response to Clean Energy Associations'
request that the Commission require the transmission provider and its
consultants to protect the EMT models and other information with the
highest degree of confidentiality,\3188\ we note that the pro forma
generator interconnection procedures and agreements include provisions
for the treatment of confidential information.\3189\
---------------------------------------------------------------------------

    \3187\ Clean Energy Associations Initial Comments at 68-69.
    \3188\ Id. at 70.
    \3189\ See pro forma LGIP section 13.1; pro forma SGIP section
4.5; pro forma LGIA art. 22; pro forma SGIA art. 9.
---------------------------------------------------------------------------

    1680. In response to Invenergy's request for clarification
regarding whether a generic EMT model may be provided if a validated
EMT model is unavailable at the time of submission of an
interconnection request,\3190\ we note that there is currently no
industry-accepted generic EMT model; therefore, a validated EMT model
is required. In response to Invenergy's request for clarification
regarding whether the interconnection customer may submit this
information by the time of a cluster restudy if a validated EMT model
is determined to be necessary, we clarify that a validated EMT model,
if required by the transmission provider, must be submitted with the
interconnection request to proceed in the interconnection study
process. As validation can consist of, for example an attestation from
the interconnection customer that the model accurately represents the
entire generating facility, based on the interconnection customer's
understanding at the time of submission, we believe an interconnection
customer should be able to provide a validated EMT model at the time of
the interconnection request.
---------------------------------------------------------------------------

    \3190\ Invenergy Initial Comments at 58.
---------------------------------------------------------------------------

    1681. In response to APS' request for clarification on the number
of times an interconnection customer is allowed to provide inaccurate
data and cure deficiencies before an interconnection request is deemed
withdrawn,\3191\ we note that section 3.4.4 of the pro forma LGIP and
section 1.3 of the pro forma SGIP provide the timeline for when a
transmission provider must notify an interconnection customer that its
interconnection request is deficient, and at that point, the
interconnection customer has 10 business days to provide the additional
requested information. We clarify that an interconnection customer has
until the end of the 10 business-day period to cure deficiencies in its
interconnection request. In the case of the pro forma LGIP, the
interconnection customer may submit this information early in the
cluster request window to ensure that there is sufficient time to
address any issues with the interconnection request and the required
models.
---------------------------------------------------------------------------

    \3191\ APS Initial Comments at 24.
---------------------------------------------------------------------------

    1682. In response to ClearPath's question regarding whether a
change in equipment that necessitates submitting updated models is
considered a material modification,\3192\ we highlight that section 4.4
of the pro forma LGIP and section 1.4 of the pro forma SGIP set forth
procedures for modifications to an interconnection request, including
the evaluation of technical changes to a request. Further, we note that
section 4.6 of the pro forma LGIP contains the transmission provider's
technological change procedure, which was designed to allow
transmission providers to evaluate whether equipment changes to an
interconnection request should trigger the material modification
provisions. A change in equipment may also qualify under the
transmission

provider's definition of permissible technological advancements in
section 1 of the pro forma LGIP. This definition includes advancements
that the interconnection process can accommodate without triggering the
material modification provision of the pro forma LGIP.
---------------------------------------------------------------------------

    \3192\ ClearPath Initial Comments at 10.
---------------------------------------------------------------------------

    1683. In response to Consumers Energy's recommendation that there
should be consistency between NERC Reliability Standards and data
collection efforts and the Commission's rulemaking,\3193\ we are not
persuaded that there is a conflict or duplication between this final
rule and NERC's Reliability Standards and interconnection data
collection efforts. NERC Reliability Standards apply only to entities
that are registered with NERC. Many smaller non-synchronous generating
facilities are currently excluded from NERC registration but
interconnect under the pro forma SGIP and pro forma LGIP and execute,
or request the unexecuted filing of, the pro forma SGIA or pro forma
LGIA.\3194\ The revisions to the pro forma interconnection procedures
and pro forma interconnection agreements require all new
interconnection customers that interconnect under the pro forma
interconnection procedures and pro forma interconnection agreements to
adhere to the new modeling requirements, regardless of whether the new
interconnection customers must abide by the NERC Reliability Standards.
We also note that NERC supports the proposed reforms.\3195\
---------------------------------------------------------------------------

    \3193\ Consumers Energy Initial Comments at 9.
    \3194\ NERC Initial Comments at 13-14.
    \3195\ Id. at 8-9, 18-20.
---------------------------------------------------------------------------

b. Ride Through Requirements
i. Need for Reform and NOPR Proposal
    1684. In the NOPR, the Commission preliminarily found that the pro
forma LGIA and pro forma SGIA ride through provisions could result in
undue discrimination and preferential treatment.\3196\ The Commission
stated that, although synchronous and non-synchronous generating
facilities are able to ``ride through'' system events and remain online
and continue to provide real and reactive power following a
disturbance, the existing pro forma LGIA and pro forma SGIA impose
differing ride through requirements because they fail to account for a
non-synchronous generating facility's ability to engage in momentary
cessation.\3197\ The Commission expressed concern that, given advances
in inverter technology, the lack of performance requirements regarding
the use of momentary cessation by non-synchronous generating facilities
may not be supportable on either a technical or cost basis.\3198\
---------------------------------------------------------------------------

    \3196\ NOPR, 179 FERC ] 61,194 at P 320.
    \3197\ Id. PP 320-321.
    \3198\ Id. P 325.
---------------------------------------------------------------------------

    1685. The Commission proposed 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 NERC Reliability Standard PRC-024-3 or its successor
standards.\3199\ The Commission explained that the pro forma LGIA
defined the term ``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 Commission proposed to
expand this 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.
---------------------------------------------------------------------------

    \3199\ Id. P 336. The ``no trip zone'' is defined as a set of
voltage and frequency no trip boundaries within which applicable
protection and controls may not be set to cause the generating
facility to trip or cease current injection. See PRC-024-3--
Frequency and Voltage Protection Settings for Generating Resources,
https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-024-3.pdf.
---------------------------------------------------------------------------

    1686. In addition, the Commission proposed to require any newly
interconnecting non-synchronous generating facility to have the
ability, during abnormal frequency conditions and voltage conditions
within the ``no trip zone'' defined by NERC 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 to have the ability to provide dynamic reactive
power to maintain system voltage in accordance with the generating
facility's voltage schedule.\3200\ The Commission sought 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.\3201\
---------------------------------------------------------------------------

    \3200\ NOPR, 179 FERC ] 61,194 at P 337.
    \3201\ Id. P 338.
---------------------------------------------------------------------------

ii. Comments
(a) Comments in Support
    1687. Many commenters generally support the goal of the NOPR
proposal.\3202\ CAISO asserts that the proposed reforms are essential
for transmission providers to maintain reliability as non-synchronous
generating facilities proliferate, and it urges the Commission to
impose the proposed requirements on all interconnection customers that
have not yet executed LGIAs as well as all prospective interconnection
customers.\3203\ CAISO argues that interconnection customers that have
already procured certain inverters that cannot meet the requirements
can request non-conforming LGIAs, or request that their LGIAs be filed
unexecuted, but it notes that it recently implemented similar
requirements, and interconnection customers have been able to procure
the inverters and technology necessary to meet the requirements.
---------------------------------------------------------------------------

    \3202\ AEP Initial Comments at 54; AES Initial Comments at 27;
Ameren Initial Comments at 34; APPA-LPPC Initial Comments at 33;
CAISO Initial Comments at 39-40; Consumers Energy Initial Comments
at 9; NERC Initial Comments at 4, 23; Eversource Initial Comments at
38; Illinois Commission Initial Comments at 16; MISO TOs Initial
Comments at 32-33; NARUC Initial Comments at 42; National Grid
Initial Comments at 43-44; North Carolina Commission and Staff
Initial Comments at 26-27; NRECA Initial Comments at 48; NYISO
Initial Comments at 54; Ohio Commission Consumer Advocate Initial
Comments at 17; PacifiCorp Initial Comments at 45; Pine Gate Initial
Comments at 59; SPP Initial Comments at 28; U.S. Chamber of Commerce
Initial Comments at 13.
    \3203\ CAISO Initial Comments at 39-40.
---------------------------------------------------------------------------

(b) Comments in Opposition
    1688. Pine Gate asserts that the Commission should not incorporate
requirements into the pro forma LGIP and pro forma SGIP that are
already being addressed by NERC through the standards development
process, which will add new requirements related to the vast majority
of the modeling and performance issues identified in the NOPR.\3204\ In
addition, Pine Gate notes that the pro forma LGIA and pro forma SGIA
already require interconnection customers to remain compliant with the
applicable reliability standards.\3205\
---------------------------------------------------------------------------

    \3204\ Pine Gate Initial Comments at 60.
    \3205\ Id. (citing pro forma LGIA art. 9.1).
---------------------------------------------------------------------------

(c) Comments on Specific Proposal
(1) IEEE Standards 2800 and 1547
    1689. NERC and MISO support modifying the pro forma LGIP to
incorporate elements of NERC Reliability Standards, NERC guidelines,
and IEEE standards.\3206\ Specifically, MISO supports adopting IEEE
Standard 2800-2022 by reference in the pro forma LGIA.\3207\ MISO
asserts that

implementing IEEE Standard 2800-2022 will ensure resource capabilities
protect against the types of events described in several recent NERC
disturbance reports. NERC notes that the IEEE standards are inherently
not mandatory unless a governing authority with jurisdiction adopts and
enforces them and include many recommended practices that could be
deemed informational.\3208\ Accordingly, NERC asserts that IEEE
Standard 2800-2022 operates similar to NERC reliability guidelines,
although IEEE Standard 2800-2022 is only available upon purchase.
---------------------------------------------------------------------------

    \3206\ NERC Initial Comments at 9; MISO Reply Comments at 26.
    \3207\ MISO Reply Comments at 25.
    \3208\ NERC Initial Comments at 3.
---------------------------------------------------------------------------

    1690. NERC recommends that the Commission explicitly integrate the
requirements and recommendations from IEEE Standard 2800-2022 into the
pro forma interconnection agreements.\3209\ Specifically, NERC contends
that the Commission should prioritize the disturbance ride through,
active power-frequency control, reactive power-voltage control, data
sharing, and modeling provisions of IEEE Standard 2800-2022. However,
NERC states that some transmission system conditions may require
inverter control modes, settings, or protections that will not conform
to IEEE Standard 2800-2022 region-wide expectations. NERC also argues
that transmission providers should be permitted to establish additional
performance requirements for specific locations and instances beyond
region-wide requirements established under pro forma provisions,
subject to transparency and public notice.
---------------------------------------------------------------------------

    \3209\ Id. at 6.
---------------------------------------------------------------------------

    1691. Some commenters request that the Commission amend its
proposal to reference IEEE Standard 2800 or successor standards for
large generating facilities and IEEE Standard 1547 for small generating
facilities.\3210\ EPRI asserts that these standards have been developed
through a rigorous process and provide for IBR performance that
supports system reliability while providing sufficient flexibility for
RTOs/ISOs and interconnection customers.\3211\ EPRI also notes that
inverter manufacturers have publicly stated that state-of-the-art
equipment already has the majority of the capabilities required by IEEE
Standard 2800.
---------------------------------------------------------------------------

    \3210\ Clean Energy Associations Initial Comments at 73; EPRI
Initial Comments at 5; SEIA Initial Comments at 43 (citing Generator
Interconnection Workshop Summary at 20).
    \3211\ EPRI Initial Comments at 5.
---------------------------------------------------------------------------

    1692. EPRI argues that the Commission should consider narrowly
specifying ride through requirements by reference to IEEE Standards
2800 and 1547; aligning all applicable definitions proposed in the NOPR
with those standards; and evaluating the alignment of additional
definitions or performance specifications with potential future
revisions of those standards.\3212\ EPRI asserts that failing to do so
could create undue technical barriers to IBRs, and that paraphrasing of
IEEE standards, rather than directly referencing the standards'
requirements, could lead to an inconsistent implementation of the final
rule in different regions with insufficient reliability benefits.\3213\
---------------------------------------------------------------------------

    \3212\ Id.
    \3213\ Id. at 5-6.
---------------------------------------------------------------------------

    1693. EPRI asserts that, if the Commission specifies its own ride
through performance requirements, an alternative but less preferred
approach would be to use the precise language and definitions as
published in IEEE Standards 2800 and 1547.\3214\
---------------------------------------------------------------------------

    \3214\ Id. at 6.
---------------------------------------------------------------------------

    1694. EPRI argues that the NOPR proposal does not seem entirely
aligned with the NERC IBR guidelines and is not as clear as the
applicable industry standards like IEEE Standard 2800-2022.\3215\ EPRI
also asserts that the Commission should consider what it characterizes
as significant improvements in IEEE Standard 2800 over the NERC
reliability guidelines. EPRI contends that the NERC IBR reliability
guidelines cited in the NOPR did not fully consider all technical and
stakeholder concerns considered by IEEE Standard 2800 and are therefore
in contravention of the IEEE Standard 2800-2022 consensus
requirements.\3216\
---------------------------------------------------------------------------

    \3215\ Id. at 9.
    \3216\ Id. at 3.
---------------------------------------------------------------------------

    1695. SEIA states that IBRs are currently capable of riding through
disturbances and that many developers have implemented controls to
ensure they do so following the release of the consensus-based IEEE
standards.\3217\ SEIA argues that incorporating IEEE Standard 2800 into
the pro forma LGIA would bring some certainty in generating facility
design because the reliability requirements for each generating
facility would be known at the time of the interconnection
request.\3218\
---------------------------------------------------------------------------

    \3217\ SEIA Initial Comments at 43.
    \3218\ Id. at 44.
---------------------------------------------------------------------------

(2) Feasibility of NOPR Proposal
    1696. Some commenters argue that the proposed requirement in the
NOPR ``to maintain power production at pre-disturbance levels unless
providing primary frequency response or fast frequency response'' is
not feasible.\3219\ Invenergy asserts that, in order to increase
reactive power output to maintain system voltage, a generator would
necessarily have to reduce real power output: therefore, Invenergy
requests that the NOPR proposal be revised to clarify this potential
inconsistency.\3220\ Clean Energy Associations and Public Interest
Organizations contend that a requirement to maintain active power
injection at pre-disturbance levels would lead to an undesirable
response from generating facilities during a grid disturbance that
could lead to voltage collapse, and the more helpful response would be
to shift some power output to prioritize reactive power.\3221\
---------------------------------------------------------------------------

    \3219\ CAISO Initial Comments at 40; Clean Energy Associations
Initial Comments at 71-72; NERC at 4; EPRI Initial Comments at 10;
Invenergy Initial Comments at 58; [Oslash]rsted Initial Comments at
19-20; Public Interest Organizations Reply Comments at 14; Southern
Initial Comments at 34.
    \3220\ Invenergy Initial Comments at 58.
    \3221\ Clean Energy Associations Initial Comments at 71-72;
Public Interest Organizations Reply Comments at 14.
---------------------------------------------------------------------------

    1697. Southern suggests adding a sentence to article 9.7.3 in the
pro forma LGIA to address circumstances under which the generating
facility is unable to maintain active power while delivering reactive
power.\3222\ Clean Energy Associations suggest that the Commission
replace the requirement to maintain active power production with
language from NERC Reliability Standard PRC-024-3, which requires
current injection and not active power injection to continue at pre-
disturbance levels.\3223\ Alternatively, Clean Energy Associations and
Invenergy suggest the proposed language could be made more workable by
only requiring a return to the pre-disturbance level of power
production following voltage recovery, subject to the energy
availability of the resource, which Clean Energy Associations explains
would allow a generator to correctly shift from active power to
reactive power during the voltage disturbance.\3224\
---------------------------------------------------------------------------

    \3222\ Southern Initial Comments at 34 (suggesting the addition
of the following sentence: ``If the plant cannot maintain active
power while delivering reactive power due to its current or apparent
power limitation, then the preference should be given to either
active or reactive power as specified by the Transmission
Provider.'').
    \3223\ Clean Energy Associations Initial Comments at 76.
    \3224\ Id. at 76-77; Invenergy Initial Comments at 58.
---------------------------------------------------------------------------

    1698. CAISO requests that the Commission not require that inverters
be able to provide real power during a transitory disturbance.\3225\
CAISO states that, unlike synchronous generating facilities, IBRs are
current limited and generally operate at their maximum output. CAISO
argues that maintaining

real power output at pre-disturbance levels would likely inhibit a non-
synchronous generating facility's ability to provide reactive power
during a disturbance, and to help ensure reliability CAISO recommends
removing the real power requirements and requiring non-synchronous
generating facilities to provide reactive power at pre-disturbance
levels. EPRI agrees that maintaining active power at the pre-
disturbance levels during and after the abnormal voltage period may not
be practical, given that voltage disturbances tend to be limited to a
region relatively close to the fault location, and is not aligned with
IEEE Standard 2800-2022 or other international requirements.\3226\ EPRI
and NERC recommend that IBR plant performance requirements should
address active and/or reactive current during an abnormal voltage
condition and requirements for the restoration of active power output
in the post-fault period.\3227\
---------------------------------------------------------------------------

    \3225\ CAISO Initial Comments at 40.
    \3226\ EPRI Initial Comments at 10.
    \3227\ Id. at 9-10; NERC Reply Comments at 4.
---------------------------------------------------------------------------

    1699. EPRI argues that the implementation of frequency and voltage
protection relay settings should not be exactly aligned with the NERC
Reliability Standard PRC-024 curves but rather be based on the actual
limits of equipment capability, with the objective to avoid potential
damages.\3228\
---------------------------------------------------------------------------

    \3228\ EPRI Initial Comments at 12.
---------------------------------------------------------------------------

    1700. [Oslash]rsted argues that it is not possible to maintain real
power production with depressed voltage that is still within the no
trip zone of NERC Reliability Standard PRC-024-3, and explains that
prioritizing reactive current during fault ride through mode (even
within the no trip zone) is instrumental to maintain reliability.\3229\
[Oslash]rsted recommends replacing the reference to good utility
practice in proposed article 9.7.3 of the pro forma LGIA and instead
rely on Order No. 842 and its definition of ``Bulk-Power System--
Primary Frequency Response.'' \3230\
---------------------------------------------------------------------------

    \3229\ [Oslash]rsted Initial Comments at 19-20.
    \3230\ Id. at 20 (referring to 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)).
---------------------------------------------------------------------------

    1701. NERC notes that conventional grid-following IBRs are current-
limited devices, and their active power output is voltage-dependent,
making maintaining 100% of pre-disturbance active power while providing
reactive power to support the bulk-power system during the fault period
not always feasible.\3231\ NERC recommends referring to ``controls that
maintain pre-disturbance active current (Ip)'' in addition to the
provision of reactive current (Iq) (i.e., reactive power support)
rather than referring to ``power.'' \3232\
---------------------------------------------------------------------------

    \3231\ NERC Reply Comments at 4.
    \3232\ Id.
---------------------------------------------------------------------------

(3) Applicability to All Types of Generating Facilities
    1702. Invenergy asserts that the NOPR proposal should go beyond the
pro forma LGIA's current requirements and apply evenly to all
generating facilities, not just non-synchronous generating
facilities.\3233\ Similarly, Clean Energy Associations assert that the
Commission currently only requires that relay settings not trip a
generating facility during a voltage or frequency excursion and that
there is no actual performance standard to ride through a disturbance
for synchronous generating facilities.\3234\ Clean Energy Associations
assert that, to prevent undue discrimination, the Commission should
either proceed with a similar effort to require ride through
performance from synchronous generating facilities; or allow ride
through performance exceptions for non-synchronous generating facility
trips caused by auxiliary equipment performance, which are a primary
cause of ride through failure for both synchronous and non-synchronous
generating facilities.
---------------------------------------------------------------------------

    \3233\ Invenergy Initial Comments at 58.
    \3234\ Clean Energy Associations Initial Comments at 77.
---------------------------------------------------------------------------

    1703. EPRI states that article 9.7.3 of the pro forma LGIA could
benefit from additional modifications that differentiate between the
ride through requirements for synchronous and non-synchronous large
generating facilities because the two technologies have inherently
different technical capabilities and operating principles.\3235\
---------------------------------------------------------------------------

    \3235\ EPRI Initial Comments at 11.
---------------------------------------------------------------------------

    1704. [Oslash]rsted urges the Commission to take note of the
differences between technologies regarding their ability to ride
through transmission system faults.\3236\ For example, [Oslash]rsted
states that it uses a plant controller for wind turbines that is frozen
in fault ride through mode and that controls aiding voltage recovery
are performed by individual turbines until voltage profile is back
within a normal operating band of 90-110% of rated voltage.
---------------------------------------------------------------------------

    \3236\ [Oslash]rsted Initial Comments at 16.
---------------------------------------------------------------------------

    [Oslash]rsted concludes that not all non-synchronous generating
facilities are subject to the types of operating and power production
concerns highlighted by the Commission in the NOPR.
(4) Proposed Revisions to the Pro Forma LGIA
    1705. [Oslash]rsted asserts that interconnection customers can only
``ensure'' ride through capability of the generating and
interconnection facilities per the definition in article 1 in the pro
forma LGIA. [Oslash]rsted contends that the Commission's use of the
term ``transmission system'' in article 9.7.3 of the pro forma LGIA is
unclear in this context, and thus [Oslash]rsted alleges that it will be
difficult to demonstrate compliance. Accordingly, [Oslash]rsted urges
the Commission to use the term ``generation and interconnection
facilities'' instead of ``transmission system'' in article 9.7.3 of the
pro forma LGIA.\3237\
---------------------------------------------------------------------------

    \3237\ Id. at 18-19.
---------------------------------------------------------------------------

    1706. [Oslash]rsted states that, in case of severe voltage dip,
IBRs may freeze in phase locked loop, essentially holding the
calculated angle of the external voltage at a certain value.\3238\
[Oslash]rsted argues that this makes IBR units not strictly
synchronized with the transmission system during this period.\3239\
Accordingly, [Oslash]rsted asks the Commission to remove the phrase
``stay synchronized'' from article 9.7.3 of the pro forma LGIA.
---------------------------------------------------------------------------

    \3238\ A ``phase locked loop'' is a circuit that synchronizes an
output signal with a reference or input signal in frequency as well
as phase. Roland E. Best, Phase-Locked Loops: Design, Simulation and
Applications, at 1 (6th ed. McGraw-Hill 2007).
    \3239\ [Oslash]rsted Initial Comments at 19.
---------------------------------------------------------------------------

(d) Requests for Clarification and Miscellaneous
    1707. NV Energy questions the ramifications of non-synchronous
generating facilities failing to maintain a composite power delivery at
continuous rated power output at the high side of the generator
substation at a power factor within the range of 0.95 leading to 0.95
lagging.\3240\ NV Energy suggests in this circumstance the non-
synchronous generating facilities make a payment for failing to
maintain the tariff-required composite power delivery. NV Energy notes
that there is a pending reactive power rulemaking and inquires whether
the industry should assume that payments for reactive power will be
addressed in that rulemaking.
---------------------------------------------------------------------------

    \3240\ NV Energy Initial Comments at 8.
---------------------------------------------------------------------------

    1708. Eversource requests that the Commission clarify that
transmission providers may include additional performance requirements
in the LGIA appendices for non-synchronous generating facilities that
are necessary to

ensure reliable interconnection in a given area, such as harmonics or
radio frequency interference.\3241\
---------------------------------------------------------------------------

    \3241\ Eversource Initial Comments at 38-39.
---------------------------------------------------------------------------

    1709. Invenergy asserts that the Commission should not rely
entirely on ride through and other burdens on interconnection customers
to address larger transmission system issues that should be addressed
through regional transmission planning processes.\3242\
---------------------------------------------------------------------------

    \3242\ Invenergy Initial Comments at 59.
---------------------------------------------------------------------------

    1710. EPRI states that addressing how to apply grandfathering to
existing facilities is an important consideration that should be
addressed through Commission/NERC requirements. EPRI suggests that the
Commission could add a procedure and criteria for a transmission
provider to waive the grandfathering rule and require retrofits of
existing facilities at the time of plant changes, or upgrades to meet
the specified performance and modelling requirements, or to meet
specific capability and performance standards such as IEEE Standard
2800-2022.\3243\
---------------------------------------------------------------------------

    \3243\ EPRI Initial Comments at 21-22.
---------------------------------------------------------------------------

iii. Commission Determination
    1711. We adopt, with modifications, the NOPR proposal to revise
article 9.7.3 of the pro forma LGIA and article 1.5.7 of the pro forma
SGIA to establish ride through requirements during abnormal frequency
conditions and voltage conditions within the ``no trip zone'' defined
by NERC Reliability Standard PRC-024-3 or successor mandatory ride
through reliability standards, as set forth in the modified pro forma
LGIA language discussed below. We modify the proposed requirements to
acknowledge the physical limitations of newly interconnecting non-
synchronous generating facilities. In the NOPR, the Commission stated
that compliance with the NOPR proposal would be largely a control
settings issue and may not be costly. We are persuaded by comments that
contend that compliance with the NOPR proposal would be infeasible for
certain types of inverters and non-synchronous generating facilities,
and thus make modifications to address these concerns.
    1712. Based on the record, we affirm the Commission's preliminary
finding in the NOPR that the pro forma LGIA and pro forma SGIA fail to
account for a non-synchronous generating facility's ability to engage
in momentary cessation. We note that the physical characteristics of
synchronous generating facilities result in such facilities continuing
to inject electric current during transmission system disturbances,
consistent with the existing requirements to remain ``connected to and
synchronized with the [t]ransmission [s]ystem'' as required by the pro
forma LGIA and pro forma SGIA. As a result of these requirements,
synchronous generating facilities continue to inject current during
such disturbances, such that services provided supporting transmission
system reliability are not disrupted during such events. However, the
existing pro forma LGIA and pro forma SGIA do not currently require
non-synchronous generating facilities to be capable of continuing to
inject current in a manner comparable to synchronous generating
facilities during system disturbances. As a result, non-synchronous
generating facilities often cease injecting current during transmission
system disturbances through ``momentary cessation.'' We agree with
commenters that such behavior by non-synchronous generating facilities
can pose significant risk to the reliability of the bulk-power system,
as documented in several reports and NERC-issued alerts.\3244\
---------------------------------------------------------------------------

    \3244\ NERC Initial Comments at 9, 11 (citing NOPR, 179 FERC ]
61,194 at P 313 n.433 (citing San Fernando Disturbance, at vi (Nov.
2020), https://www.nerc.com/pa/rrm/ea/Documents/San_Fernando_Disturbance_Report.pdf; 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, Odessa Disturbance (Sept. 2021) https://www.nerc.com/pa/rrm/ea/Documents/Odessa_Disturbance_Report.pdf)).
---------------------------------------------------------------------------

    1713. Moreover, without requirements for non-synchronous generating
facilities to remain connected to and synchronized with the
transmission system, and not to engage in momentary cessation,
interconnection studies may not be able to accurately model expected
behavior and identify the appropriate interconnection facilities and
network upgrades to accommodate the interconnection request, resulting
in an inaccurate assignment of interconnection costs. As a result, we
find that the lack of comparable requirements for non-synchronous
generating facilities to have the capability to remain ``connected to
and synchronized with the [t]ransmission [s]ystem'' in the pro forma
LGIA and pro forma SGIA results in rates that are unjust, unreasonable,
and unduly discriminatory or preferential.
    1714. While a number of commenters object to the specific
provisions proposed in the NOPR to resolve this issue, addressed
further below, no commenter disagrees that there is a lack of
requirements in the pro forma LGIA and pro forma SGIA regarding the use
of momentary cessation by non-synchronous generating facilities.
Moreover, no commenter disputes the technical ability of non-
synchronous generating facilities to continue to inject current during
transmission system disturbances.
    1715. Specifically, we require that during abnormal frequency
conditions and voltage conditions within the ``no trip zone'' defined
by NERC Reliability Standard PRC-024-3 or successor mandatory ride
through reliability standards, the non-synchronous generating facility
must ensure that, within any physical limitations of the generating
facility, its control and protection settings are configured or set to:
(1) continue active power production during disturbance and post
disturbance periods at pre-disturbance levels unless providing primary
frequency response or fast frequency response; \3245\ (2) minimize
reductions in active power and remain within dynamic voltage and
current limits, if reactive power priority mode is enabled, unless
providing primary frequency response or fast frequency response; (3)
not artificially limit dynamic reactive power capability during
disturbances; and (4) return to pre-disturbance active power levels
without artificial ramp rate limits if active power is reduced, unless
providing primary frequency response or fast frequency response.
---------------------------------------------------------------------------

    \3245\ Fast frequency response is defined as power injected to
(or absorbed from) the grid in response to changes in measured or
observed frequency during the arresting phase of a frequency
excursion event to improve the frequency nadir or initial rate-of-
change of frequency. See Fast Frequency Response Concepts and Bulk
Power System Reliability Needs, https://www.nerc.com/comm/PC/InverterBased%20Resource%20Performance%20Task%20Force%20IRPT/Fast_Frequency_Response_Concepts_and_BPS_Reliability_Needs_White_Paper.pdf at 7.
---------------------------------------------------------------------------

    1716. In comparison to the NOPR proposal, this language, as
adopted, provides non-synchronous generating facilities, within any
physical limitations of the generating facility, the ability to reduce
active power production in order to prioritize reactive power output in
support of transmission system voltage.\3246\ This language also
recognizes that such facilities may not be able to ride through
disturbances with the same performance as synchronous generating
facilities without costly equipment modification. However, this
language requires non-synchronous generating facilities, within any
physical limitations of the generating facility, to configure or set
their facilities to ride through disturbances and continue to support

system reliability. This language is consistent with suggestions by a
number of commenters that the final rule recognize that non-synchronous
generating facilities cannot provide both real and reactive power at
pre-disturbance levels during a disturbance,\3247\ allow for the
prioritization of reactive power,\3248\ and address restoration of
active power output in the post-fault period.\3249\
---------------------------------------------------------------------------

    \3246\ ``Active power'' as used here and ``real power'' as used
in the NOPR proposal refer to the same concept: power than can be
used by load in order to perform work.
    \3247\ CAISO Initial Comments at 40; Clean Energy Associations
Initial Comments at 71-72; NERC at 4; EPRI Initial Comments at 10;
Invenergy Initial Comments at 58; [Oslash]rsted Initial Comments at
19-20; Public Interest Organizations Reply Comments at 14; Southern
Initial Comments at 34.
    \3248\ Clean Energy Associations Initial Comments at 71-72;
Public Interest Organizations Reply Comments at 14; [Oslash]rsted
Initial Comments at 19-20.
    \3249\ EPRI Initial Comments at 9-10; NERC Reply Comments at 4;
Clean Energy Associations Initial Comments at 76-77; Invenergy
Initial Comments at 58.
---------------------------------------------------------------------------

    1717. The adopted language requires non-synchronous generating
facilities, within any physical limitations of the generating facility,
to configure or set their facilities to be able to ride through
disturbances and continuing to support system reliability.
Specifically, while grid-forming inverters are available, they are not
widely commercially deployed due to lack of experience, cost, or other
factors.\3250\ Given the existing technical capabilities of non-
synchronous generating facilities, we agree with commenters that the
NOPR proposal requiring active power to be maintained at pre-
disturbance levels during a system disturbance in all instances may not
be feasible, or preferrable from a reliability perspective. For
example, we agree there may be instances where the injection of
reactive power should be prioritized to maintain reliability during a
system disturbance, which may require non-synchronous generating
facilities to temporarily reduce their injection of active power.\3251\
As a result, we adopt a modified NOPR proposal to accommodate existing
technical capabilities and physical limitations of non-synchronous
generating facilities, by providing for reductions in active power to
prioritize reactive power while prohibiting non-synchronous generating
facilities from configuring or setting their control and protection
settings to effectively artificially limit such resources below their
actual capability.
---------------------------------------------------------------------------

    \3250\ A grid-forming inverter is an inverter that is capable of
synthesizing voltage and frequency without an external reference.
See, e.g., Abraham Ellis, Grid Forming Inverters: Requirements and
Practical Applications, at 4 (May 1, 2019) https://www.osti.gov/servlets/purl/1639991.
    \3251\ NERC Initial Comments at 23; CAISO Initial Comments at
40.
---------------------------------------------------------------------------

    1718. We also adopt the NOPR proposal to revise article 9.7.3 of
the pro forma LGIA to include in the definition of ``ride through'' 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. This revision ensures
that large generating facilities are capable of remaining connected to
and synchronized with the transmission system, consistent with the
other ride through requirements adopted here and similar requirements
in the pro forma SGIA.
    1719. Some commenters request that the Commission either
incorporate IEEE Standard 2800-2022 by reference, or explicitly
incorporate this standard's performance requirements into the pro forma
LGIA. Although we acknowledge the value of IEEE 2800-2022, we decline
to incorporate it by reference. IEEE 2800-2022 was developed for a
different purpose; it is a voluntary guideline that uses discretionary
terms (e.g., ``may,'' ``should,'' ``can,'' or ``upon agreement''). It
is unclear whether IEEE 2800-2022 would adequately address the problem
identified by the Commission because the Commission would have limited
authority to enforce these discretionary provisions.
    1720. Invenergy and Clean Energy Associations assert that the
Commission should impose similar ride through requirements on
synchronous generating facilities. Alternatively, Clean Energy
Associations assert that, to prevent undue discrimination, the
Commission should allow ride through performance exceptions for non-
synchronous generating facility trips caused by auxiliary equipment
performance, which are a primary cause of ride through failure for both
synchronous and non-synchronous generating facilities. We do not
believe that imposing similar ride through requirements on synchronous
generating facilities is necessary because the physical characteristics
of synchronous generating facilities result in such facilities
continuing to inject electric current during transmission system
disturbances, i.e., do not allow for momentary cessation.
    1721. We also decline to grant Clean Energy Associations'
alternative request because we find that a ride through exception for
non-synchronous generating facility trips caused by auxiliary equipment
performance is not needed. As NERC has noted, protection on auxiliary
equipment for non-synchronous resources, other than the generator-
connected unit auxiliary transformer, is already exempted from the
requirements of NERC Reliability Standard PRC-024-3 specifically
because protection for such auxiliary equipment does not cause a
resource to trip or cease injecting current.\3252\ We do not believe
that auxiliary equipment performance is considered a physical
limitation of a non-synchronous generating facility such that control
and protection settings can be configured or set to reduce active power
production during disturbances, and therefore no exception is needed.
---------------------------------------------------------------------------

    \3252\ Petition of the North American Reliability Corporation
for Approval of Proposed Reliability Standard PRC-024-3, Docket No.
RD20-7, at 12 (filed Mar. 20, 2020).
---------------------------------------------------------------------------

    1722. Pine Gate asserts that the Commission should not adopt
requirements to the pro forma LGIP and pro forma SGIP that are already
being addressed by NERC through the standards development process. We
disagree because adding such provisions to the pro forma LGIA and pro
forma SGIA will require all newly interconnecting generating facilities
to abide by such provisions regardless of whether such newly
interconnecting generating facilities are outside the bounds of NERC's
jurisdiction. As such, we find that this modified reform can
holistically address the identified issues alongside the NERC
standards.
    1723. NV Energy raises questions about the ramifications of non-
synchronous generating facilities failing to maintain reactive power
and whether the Commission is proposing any changes to reactive power
compensation. We clarify that the Commission is not proposing changes
to reactive power compensation in this proceeding.
    1724. Invenergy argues that the Commission should not rely entirely
on ride through requirements and other burdens on interconnection
customers to address larger transmission system issues that should be
addressed through regional transmission planning processes. The need to
establish interconnection requirements for generating facilities to
``remain connected to and synchronized with the [t]ransmission
[s]ystem'' during system disturbances is properly addressed in this
proceeding that deals with reforming the interconnection processes for
newly interconnecting generating facilities. Regarding Invenergy's
arguments that larger transmission system issues need to be addressed
in the regional transmission planning processes, we note that while
reforms to regional transmission planning are

outside the scope of this proceeding, the Commission is considering
addressing regional transmission planning and cost allocation in
another pending proceeding.\3253\
---------------------------------------------------------------------------

    \3253\ See Transmission Planning and Cost Allocation NOPR, 179
FERC ] 61,028 (2022).
---------------------------------------------------------------------------

    1725. EPRI argues that the grandfathering of existing non-
synchronous generating facilities is an important consideration that
should be addressed through Commission and NERC requirements and
suggests that the Commission could add a procedure and criteria for a
transmission provider to waive the grandfathering rule and require
retrofits of existing non-synchronous generating facilities at the time
of plant changes or require upgrades to meet the specified performance
and modeling requirements. We decline to add the requested procedure.
The final rule changes to the pro forma LGIA and pro forma SGIA adopted
herein apply prospectively to interconnection customers that execute,
or request the unexecuted filing of, an LGIA after the Commission-
approved effective date of the transmission provider's filing in
compliance with this final rule. Both the NOPR proposal and the adopted
language were intended to be achieved through changes to control
settings at minimal cost for current inverter technology; it did not
contemplate imposing potentially significant retrofit or equipment
costs on existing non-synchronous generating facilities.\3254\
---------------------------------------------------------------------------

    \3254\ NOPR, 179 FERC ] 61,194 at P 325.
---------------------------------------------------------------------------

    1726. [Oslash]rsted requests clarification on how the NOPR proposal
will affect a plant controller for wind turbines that is frozen in
fault ride through mode and control actions aiding voltage recovery are
performed by individual turbines until the voltage profile returns to
the normal operating band of 90-110% of rated voltage. We note that the
reforms, as adopted, apply to a non-synchronous generating facility as
a whole, rather than to any individual component within the facility.
As long as the non-synchronous generating facility as a whole meets the
ride through requirements, it does not matter which part of the
facility is controlling the generating facility's output.
    1727. [Oslash]rsted also notes that non-synchronous generating
facilities may freeze in phase locked loop during disturbances, making
them not strictly synchronized with the transmission system.
[Oslash]rsted asks the Commission to remove the phrase ``stay
synchronized'' from article 9.7.3 of the pro forma LGIA. We decline to
do so because the NOPR did not propose to revise this phrase and this
final rule establishes the specific ride through requirements for newly
interconnecting non-synchronous generating facilities.
    1728. [Oslash]rsted recommends that instead of references in this
clause to ``good utility practice,'' the Commission should instead rely
on Order No. 842 and its definition of ``Bulk-Power System--Primary
Frequency Response.'' This comment refers to language not subject to
the Commission's proposed revisions and is therefore outside the scope
of this rulemaking proceeding. We also note that ``Bulk-Power System--
Primary Frequency Response'' refers to the title of Order No. 842, and
not any definition within.
c. Applicability of Ride Through Requirements
i. Need for Reform and NOPR Proposal
    1729. In the NOPR, the Commission noted that generating facilities
interconnecting under the pro forma LGIA that are subject to
reliability standards are required to ride through frequency and
voltage disturbance events, while generating facilities that are not
already subject to reliability standards are not, despite the fact that
all generating facilities newly interconnecting under the pro forma
LGIA are technically capable of riding through disturbances.\3255\ The
Commission explained that there is an 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 of 75 MVA or less.\3256\ The Commission preliminarily
found that the pro forma LGIA requirements could result in unduly
discriminatory or preferential treatment due to this gap in the
applicability of ride through performance requirements to similarly
situated generating facilities.
---------------------------------------------------------------------------

    \3255\ NOPR, 179 FERC ] 61,194 at P 326.
    \3256\ Id. P 340.
---------------------------------------------------------------------------

    1730. The Commission proposed to revise the pro forma LGIA to
require that all newly interconnecting large generating facilities
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.\3257\ The Commission
noted that 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.
---------------------------------------------------------------------------

    \3257\ Id.
---------------------------------------------------------------------------

    1731. In addition to the substantive changes, the Commission
proposed 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. The Commission explained that these proposed
replacements reflect updated terminology.\3258\
---------------------------------------------------------------------------

    \3258\ Id. P 341.
---------------------------------------------------------------------------

ii. Comments
    1732. Several commenters support the NOPR proposal.\3259\ Enel
notes that the Commission's proposed definition of ``electric
reliability organization'' includes NERC, but it does not include the
applicable regional entity, which Enel asserts should be included
because the regional entity may have approved the regional reliability
standards.\3260\
---------------------------------------------------------------------------

    \3259\ Ameren Initial Comments at 34; APPA-LPPC Initial Comments
at 33; CAISO Initial Comments at 39-40.
    \3260\ Enel Initial Comments at 81.
---------------------------------------------------------------------------

iii. Commission Determination
    1733. We adopt the NOPR proposal to revise the pro forma LGIA to
require that all newly interconnecting large generating facilities
provide frequency and voltage 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.
Adopting this reform enables the Commission to address an 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.
    1734. Based on the record before us, we confirm the Commission's
preliminary finding in the NOPR that the pro forma LGIP is unduly
discriminatory or preferential insofar as generating facilities that
are not already subject to reliability standards are not required to
ride through frequency and voltage disturbance events, despite being
technically capable of doing so. We note that no commenter opposes this
reform.
    1735. We also adopt the NOPR proposal to replace the term
``applicable reliability council'' with ``electric reliability
organization,'' and the term ``control area'' with ``balancing
authority area,'' throughout the pro forma LGIP and pro forma LGIA. In
response to Enel's concerns, we note that, while regional reliability
standards may be developed by the applicable

regional entity, the Commission has found that regional reliability
standards are considered part of the electric reliability
organization's set of reliability standards and are therefore covered
under the proposed definition.\3261\
---------------------------------------------------------------------------

    \3261\ Order No. 672, 114 FERC ] 61,104, at P 296, order on
reh'g, Order No. 672-A, 114 FERC ] 61,328.
---------------------------------------------------------------------------

D. Issues Beyond the Scope of This Rulemaking

1. Comments
    1736. Multiple commenters ask the Commission to consider additional
information or interconnection reforms not specifically raised in the
NOPR. For example, some commenters address foundational issues such as
generator retirement and/or replacement processes; \3262\ the
application of generator interconnection standards to merchant
transmission and HVDC projects; \3263\ conducting a root-cause
investigation of interconnection queue delays to identify and address
key barriers to bringing new generating facilities online; \3264\
initiating a technical conference to identify additional reforms to
meet present and future challenges; \3265\ establishing a process to
provide access to transmission data to third-party businesses; \3266\
introduction of competition into the interconnection process or
construction of network upgrades; \3267\ the introduction of project
prioritization to allocate scarce interconnection access; \3268\
changes to operational practices to reduce network upgrade
requirements; \3269\ and issues particular to different regions or
transmission providers.\3270\
---------------------------------------------------------------------------

    \3262\ AEP Initial Comments at 43-44; Elevate Initial Comments
at 3-7, 8-11; Illinois Commission Initial Comments at 11; New York
State Department Reply Comments at 4.
    \3263\ Invenergy Initial Comments at 64-65.
    \3264\ Equinor Wind Reply Comments at 7.
    \3265\ Pine Gate Reply Comments at 5.
    \3266\ Tesla Initial Comments at 6, 8.
    \3267\ Enel Initial Comments at 5, 52-56; Shell Reply Comments
at 5-18.
    \3268\ Arizona Commission Initial Comments at 1; Colorado
Commission Initial Comments at 9.
    \3269\ Clean Energy Associations Initial Comments at 64.
    \3270\ Avangrid Initial Comments at 24-25; New York State
Department Initial Comments at 10; PJM Part 1 Reply Comments at 1;
Roy J Shanker Initial Comments at 2-7; Roy J Shanker Reply Comments
at 3-9; Southern Reply Comments at 8-9.
---------------------------------------------------------------------------

    1737. Other commenters seek changes to tariff language such as
additional reforms specific to small generating facilities and the
small generator interconnection process; \3271\ explicitly stating that
interconnection terms may be subject to remedial waiver upon
appropriate Commission action; \3272\ requiring detailed information be
made available concerning either transmission congestion on
transmission providers' systems or technical information associated
with a particular point of interconnection; \3273\ clarifications to
the interconnection service types (i.e., energy-only or network
resource); \3274\ replacing power flow studies with security
constrained economic dispatch analysis for energy-only service studies;
\3275\ the three-year suspension option in the pro forma LGIA; \3276\
and additional pro forma LGIA language on termination and breach.\3277\
---------------------------------------------------------------------------

    \3271\ Bonneville Initial Comments at 25; EPRI Initial Comments
at 24-38; Hydropower Commenters Initial Comments at 10-11; IREC
Initial Comments at 2-3; R Street Initial Comments at 9; and Xcel
Initial Comments at 19.
    \3272\ OSPA Reply Comments at 14.
    \3273\ CREA and NewSun Initial Comments at 21-22; [Oslash]rsted
Initial Comments at 5-6.
    \3274\ Enel Initial Comments at 27-28; North Dakota Commission
Initial Comments at 7; R Street Initial Comments at 7; Tri-State
Initial Comments at 26; Xcel Initial Comments at 16.
    \3275\ Enel Initial Comments at 73-75.
    \3276\ El Paso Electric Initial Comments at 4-5.
    \3277\ Tri-State Initial Comments at 34-35.
---------------------------------------------------------------------------

    1738. Several commenters focus on process-specific reforms, such as
automation of the interconnection queue process to ease delays; \3278\
aligning the interconnection queue and the project development
processes; \3279\ interconnection study issues such as staffing to
conduct studies and study criteria and scope; \3280\ additional
transparency from transmission providers on the interconnection study
process, such as online interconnection queue tracking and performance
metrics; \3281\ and whether to implement an independent transmission
monitor or allow third parties to conduct interconnection studies to
reduce interconnection queue backlogs.\3282\
---------------------------------------------------------------------------

    \3278\ CESA Initial Comments at 5; NextEra Initial Comments at
2.
    \3279\ Enel Initial Comments at 2-4.
    \3280\ Affected Interconnection Customers Initial Comments at
14-15; Clean Energy Associations Initial Comments at 27; CREA and
NewSun Initial Comments at 21-22; Cypress Creek Initial Comments at
3-8; New York State Department Initial Comments at 3.
    \3281\ Public Interest Organizations Initial Comments at 23-25.
    \3282\ Dominion Reply Comments at 22-24; EPSA Initial Comments
at 13-14; SDG&E Reply Comments at 2; Southern Reply Comments at 6-7;
ACORE Initial Comments at 5.
---------------------------------------------------------------------------

    1739. Some commenters focus on network upgrade cost issues, in
particular the participant funding model currently in place in certain
RTOs/ISOs; \3283\ minimum thresholds for identifying network upgrades;
\3284\ a self-build option for stand-alone facilities; \3285\ and the
``good faith'' standard applied to cost and timeline estimates for
network upgrades and related transmission facilities.\3286\
---------------------------------------------------------------------------

    \3283\ ACORE Initial Comments at 8; CREA and NewSun Initial
Comments at 93-104; NextEra Reply Comments at 3, 16; North Carolina
Commission and Staff Initial Comments at 2-16; OSPA Reply Comments
at 4-7; Public Interest Organizations Reply Comments at 13-14;
Senators Hickenlooper and King Initial Comments at 1-2.
    \3284\ Enel Initial Comments at 2-4.
    \3285\ CESA Initial Comments at 16-17; EEI Reply Comments at 14-
15; Interwest Initial Comments at 5.
    \3286\ Pattern Energy Initial Comments at 14-15.
---------------------------------------------------------------------------

    1740. Commenters raising resource-specific concerns address the
interconnection of qualifying facilities; \3287\ challenges specific to
the hydropower industry, including modifications to the readiness
standard and site control requirements; \3288\ steps to promote new
pumped storage projects; \3289\ using regional planning to develop
operating assumptions applied to the study of electric storage
resources; \3290\ and greater clarity on interconnection of battery
storage additions to existing and proposed generating facilities.\3291\
---------------------------------------------------------------------------

    \3287\ CREA and NewSun Initial Comments at 104-106; Uda Law Firm
Initial Comments at 1-9.
    \3288\ Hydropower Commenters Initial Comments at 7.
    \3289\ Id. at 27-28.
    \3290\ Interwest Reply comments at 15.
    \3291\ SEIA Reply Comments at 21-22.
---------------------------------------------------------------------------

    1741. Several commenters argue in favor of greater coordination
between generator interconnection and transmission planning \3292\ or
identify interconnection as a matter requiring interregional
planning.\3293\
---------------------------------------------------------------------------

    \3292\ ACORE Initial Comments at 2-4; ACEG Initial Comments at
1-4; CESA Initial Comments at 13-14; Clean Energy Associations
Initial Comments at 10-11; Consumer Protection Coalition Reply
Comments at 1-2; Cypress Creek Initial Comments at 10-11; EDF
Renewables Initial Comments at 12-13; ELCON Initial Comments at 11-
13; Enel Reply Comments at 2; ENGIE Reply Comments at 4; Google
Initial Comments at 6-7, 22; Invenergy Initial Comments at 62-63;
Interwest Reply Comments at 15; National Grid Initial Comments at
45-46; New York State Department Reply Comments at 2-4; NYTOs
Initial Comments at 23-24; OSPA Reply Comments at 15; Pattern Energy
Initial Comments at 6-7; Public Interest Organizations Reply
Comments at 16; R Street Initial Comments at 6-7; Union of Concerned
Scientists Reply Comments at 8.
    \3293\ North Carolina Commission and Staff Initial Comments at
2-3; Pattern Energy Initial Comments at 8-11.
---------------------------------------------------------------------------

    1742. Some comments request that the Commission provide distinct
treatment for Native American energy projects by adopting rules and
policies that meet the unique needs of Tribes and that allow
alternative means for fulfilling interconnection requirements, such as
by providing additional time for the posting of deposits or eliminating
commercial readiness requirements.\3294\

Other comments request that the Commission incorporate environmental
justice considerations into the interconnection process by quantifying
in the proportional impact analysis the remediation of past economic
injustice and benefits of renewable development in impoverished areas
\3295\ or by prioritizing the provision of low-cost, clean energy to
low income and people of color communities under the FPA's public
interest standard.\3296\
---------------------------------------------------------------------------

    \3294\ OSPA Reply Comments at 15-16.
    \3295\ OSPA Initial Comments at 15-16; OSPA Reply Comments at 3.
    \3296\ Energy Keepers Initial Comments at 3; Navajo Utility
Initial Comments at 13. Public Interest Organizations Reply Comments
at 11.
---------------------------------------------------------------------------

2. Commission Determination
    1743. We consider the comments referenced in the section above to
be beyond the scope of this proceeding. The Commission proposed
specific reforms in the NOPR, to which commenters have responded and
for which a record has been established. Even for those issues
tangentially connected to NOPR proposals, the record here is inadequate
to support their full consideration. Further, we consider issues
regarding the coordination of transmission planning with generator
interconnection to be beyond the scope of this rulemaking. We note that
the Commission proposed reforms related to coordination between
regional transmission planning and cost allocation and generator
interconnection in Docket No. RM21-17-000.\3297\
---------------------------------------------------------------------------

    \3297\ ANOPR, 176 FERC ] 61,024.
---------------------------------------------------------------------------

IV. Compliance Procedures

A. NOPR Proposal

    1744. In the NOPR, the Commission proposed to require each
transmission provider to submit a compliance filing within 180 days of
the effective date of the final rule revising its LGIP, LGIA, SGIP, and
SGIA, as necessary, to demonstrate that it meets the requirements set
forth in the final rule.\3298\ The Commission also proposed to permit
appropriate entities to seek an ``independent entity variation'' or a
``regional reliability variation'' from the proposed
requirements.\3299\ The Commission further noted that 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 variation standard. Where these provisions would be
modified by the final rule, the Commission proposed to require
transmission providers to either comply with the final rule or
demonstrate that these previously approved variations continue to meet
the ``consistent with or superior to'' and ``regional reliability
variation'' standard for non-RTO/ISO transmission providers and the
independent entity variation standard for RTOs/ISOs.
---------------------------------------------------------------------------

    \3298\ NOPR, 179 FERC ] 61,194 at P 342.
    \3299\ Id. (citing Order No. 2003, 104 FERC ] 61,103 at PP 822-
827; Order No. 2006, 111 FERC ] 61,220 at PP 546-550).
---------------------------------------------------------------------------

    1745. The Commission explained that it would assess whether each
compliance filing satisfies the proposed requirements and issue
additional orders as necessary to ensure that each transmission
provider meets the requirements of the final rule.\3300\
---------------------------------------------------------------------------

    \3300\ Id. P 343.
---------------------------------------------------------------------------

    1746. The Commission also proposed that non-public utility
transmission providers would have to adopt the proposed requirements as
a condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No.
888.\3301\
---------------------------------------------------------------------------

    \3301\ Id. P 344.
---------------------------------------------------------------------------

B. Comments

1. Compliance Filing Deadline
    1747. Consumers Energy and NRECA support the proposed requirement
for transmission providers to submit compliance filings within 180 days
of the effective date of a final rule in this proceeding.\3302\ NRECA
states that 180 days is a reasonable amount of time for transmission
providers to assess their generation portfolios and for interconnection
customers to gauge project viability and withdraw those interconnection
requests that are not commercially ready.\3303\ Consumers Energy
suggests that the Commission require RTOs/ISOs to justify any
individual extensions for compliance filings.\3304\ NRECA asks the
Commission to waive any existing withdrawal penalties during the period
between a final rule and compliance filings to encourage the rapid
withdrawal of speculative interconnection requests and the pursuit of
ready interconnection requests.\3305\
---------------------------------------------------------------------------

    \3302\ Consumers Energy Initial Comments at 10; NRECA Initial
Comments at 7, 49.
    \3303\ NRECA Initial Comments at 7, 49.
    \3304\ Consumers Energy Initial Comments at 10.
    \3305\ NRECA Initial Comments at 49.
---------------------------------------------------------------------------

    1748. Some commenters argue that the Commission should provide a
longer time period for compliance filings because the scope and
complexity of the reforms will require substantial time and resources
and will involve lengthy stakeholder processes.\3306\ Some commenters
also note that transmission providers will need to balance other
priorities while developing compliance filings, such as administering
the interconnection queue and pursuing transmission planning
reforms.\3307\ Some commenters state that the 180-day period will be
difficult for large, multi-state RTOs/ISOs that must develop large-
scale tariff revisions in conjunction with large stakeholder
communities.\3308\ EEI suggests a 240-day deadline for compliance
filings,\3309\ while other commenters state that one year would be more
appropriate.\3310\
---------------------------------------------------------------------------

    \3306\ Dominion Initial Comments at 6; EEI Initial Comments at
22; MISO Initial Comments at 126; NEPOOL Initial Comments at 12.
    \3307\ EEI Initial Comments at 22; MISO Initial Comments at 126.
    \3308\ Avangrid Initial Comments at 36-37; Dominion Initial
Comments at 41-42; MISO Initial Comments at 126.
    \3309\ EEI Initial Comments at 22.
    \3310\ Dominion Initial Comments at 6; MISO Initial Comments at
126.
---------------------------------------------------------------------------

    1749. PJM asks the Commission to hold its compliance filing
obligation in abeyance until PJM completes the transition mechanism
from its recent interconnection queue reform in Docket No. ER22-2110-
000, which was the result of an 18-month stakeholder process.\3311\ PJM
states that, if it is required to submit a compliance filing during the
transition process, that will cast a cloud over the transition process
while the request for an independent entity variation works through a
prolonged regulatory process, bringing into doubt interconnection
agreements finalized as part of the transition and further aggravating
backlogs.\3312\ PJM explains that, when it completes this transition
process, it can evaluate whether to adopt the final rule's reforms or
demonstrate that its reforms are superior.\3313\ PJM asserts that such
a ``staged'' compliance process aligns with past Commission decisions
and would bring more certainty to interconnection customers.\3314\
---------------------------------------------------------------------------

    \3311\ PJM Initial Comments at 2-5, 11; see also OPSI Initial
Comments at 2-3 (explaining that it will be crucial that this
proceeding does not disrupt PJM's ongoing interconnection queue
reform); see also PJM Interconnection, L.L.C., 181 FERC ] 61,162.
    \3312\ PJM Initial Comments at 2, 5, 11.
    \3313\ Id. at 12.
    \3314\ Id. at 3 (citing, e.g., Order No. 890, 118 FERC ] 61,119
at P 135 (adopting a two-tiered implementation process of the final
rule)).
---------------------------------------------------------------------------

2. Regional Flexibility
    1750. A number of commenters call for the final rule to provide
regional flexibility to account for differences in geography, state
policies and regulatory

frameworks, different network electrical characteristics, market
structures, resource mixes, and other factors.\3315\ Many commenters
explain that many transmission providers have already adopted or are in
the process of adopting some of the NOPR proposals or similar processes
targeting the challenges cited in the NOPR.\3316\ Many commenters ask
the Commission to ensure the final rule acknowledges and accommodates
existing interconnection queue reform efforts and does not undo or
disrupt progress.\3317\ Some commenters specifically ask the Commission
to allow transmission providers like PJM and Dominion to implement
recent interconnection queue reform proposals, even though they differ
in some aspects from the NOPR.\3318\ Some commenters ask the Commission
to continue applying its current standards for variations from the pro
forma LGIP (i.e., independent entity variations for RTOs/ISOs and
consistent with or superior to variations for non-RTOs/ISOs).\3319\ For
example, ISO-NE contends that the Commission should respect its
existing independent entity variations and allow it to continue
building upon those variations.\3320\
---------------------------------------------------------------------------

    \3315\ APPA-LPPC Initial Comments at 2-3; Avangrid Initial
Comments at 36; Avangrid Reply Comments at 4; Dominion Reply
Comments at 4; EEI Initial Comments at 3-4; EEI Reply Comments at
13; Idaho Power Initial Comments at 1; Illinois Commission Comments
at 3; Indicated PJM TOs Initial Comments at 1-2; Indicated PJM TOs
Reply Comments at 43; ISO-NE Initial Comments at 3, 13, 15-16, 38;
MISO TOs Initial Comments at 13; NARUC Initial Comments at 6-7;
National Grid Initial Comments at 4-5; NEPOOL Initial Comments at 3-
4, 12, 17; NESCOE Reply Comments at 4; NRECA Initial Comments at 7;
NYTOs Initial Comments at 6; North Dakota Commission Initial
Comments at 2; Southern Initial Comments at 14-15; U.S. Chamber of
Commerce Initial Comments at 2-3.
    \3316\ ACORE Reply Comments at 6; Alliant Initial Comments at 1;
Ameren Initial Comments at 35; APPA-LPPC Initial Comments at 2-3;
ClearPath Initial Comments at 6; Early Adopters Coalition Initial
Comments at 2, 13; EEI Initial Comments at 3-4; MISO Initial
Comments at 2-3, 18; MISO Reply Comments at 2; NARUC Initial
Comments at 10-11; National Grid Initial Comments at 4-5; NYISO
Reply Comments at 2; NYTOs Initial Comments at 6; Omaha Public Power
Initial Comments at 13; U.S. Chamber of Commerce Initial Comments at
2-3.
    \3317\ ACORE Reply Comments at 6; Alliant Initial Comments at 1;
APPA-LPPC Initial Comments at 2-3; Ameren Initial Comments at 35;
Early Adopters Coalition Initial Comments at 2-3, 13, 19, 21;
Dominion Initial Comments at 42; Dominion Reply Comments at 4; Duke
Southeast Utilities Initial Comments at 3-4; Illinois Commission
Comments at 3; Indicated PJM TOs Initial Comments at 1-2; Indicated
PJM TOs Reply Comments at 9; MISO Initial Comments at 4-5, 18-19,
128; MISO TOs Initial Comments at 7-9; NARUC Initial Comments at 7,
11; National Grid Initial Comments at 4-5; NRECA Initial Comments at
8; NYTOs Initial Comments at 6; Omaha Public Power Initial Comments
at 13; OMS Initial Comments at 3-4; PacifiCorp Initial Comments at
2; U.S. Chamber of Commerce Initial Comments at 2-3.
    \3318\ ClearPath Initial Comments at 6; Dominion Initial
Comments at 5-6; Indicated PJM TOs Initial Comments at 1-2; MISO
Reply Comments at 2; PJM Initial Comments at 2.
    \3319\ Ameren Initial Comments at 35; Consumer Protection
Coalition Reply Comments at 2; EEI Initial Comments at 3; Google
Reply Comments at 7-8; Indicated PJM TOs Initial Comments at 9;
Indicated PJM TOs Reply Comments at 44; ISO-NE Initial Comments at
13-15; National Grid Initial Comments at 4-5; NEPOOL Initial
Comments at 3; NYTOs Initial Comments at 6; PG&E Initial Comments at
2; PG&E Reply Comments at 2; PJM Initial Comments at 3, 12.
    \3320\ ISO-NE Initial Comments at 8-15 (providing a detailed
overview of ISO-NE's existing independent entity variations, which
align the interconnection process with the forward capacity market,
provide for targeted clustering, and allow interconnection customers
to pursue elective transmission upgrades to support queued
interconnection requests).
---------------------------------------------------------------------------

    1751. In contrast, other commenters request that the Commission
apply a new standard when evaluating variations from the pro forma
requirements.\3321\ OMS asks the Commission to allow transmission
providers initiating their own stakeholder-supported interconnection
reforms to continue developing regionally appropriate solutions upon a
compliance showing of ``substantial conformity'' with the final rule
requirements.\3322\ MISO argues that the Commission should create an
``independent entity presumption of reasonableness,'' under which the
Commission would rebuttably presume that any previous, proactive RTO/
ISO reform that addresses the objectives of a final rule requirement
(but does not conform to every detail) is eligible for an independent
entity variation, unless an intervenor demonstrates that the previous
reform does not provide the benefit that technical compliance with the
final rule would.\3323\ NextEra also states that requiring transmission
providers and stakeholders to have to justify whether their past reform
initiatives match the Commission's new rule would likely waste time and
resources.\3324\
---------------------------------------------------------------------------

    \3321\ MISO Initial Comments at 18-19.
    \3322\ OMS Initial Comments at 4.
    \3323\ MISO Initial Comments at 18-19.
    \3324\ NextEra Reply Comments at 7.
---------------------------------------------------------------------------

    1752. Similarly, the Early Adopters Coalition ask the Commission to
rebuttably presume that first-ready, first-served interconnection queue
reforms already in place continue to be just and reasonable and not
unduly discriminatory and consistent with or superior to the pro forma
requirements.\3325\ Further, the Early Adopters Coalition and Indicated
PJM TOs argue that there is an insufficient legal foundation under FPA
section 206 to conclude that the Early Adopters Coalition's tariffs are
unjust, unreasonable, and unduly discriminatory or preferential because
the Commission's FPA section 206 finding only speaks to the generic pro
forma requirements, while many transmission providers' tariffs have
already departed from those requirements.\3326\ Indicated PJM TOs state
that the Commission lacks the authority under FPA section 206 to
require modification of a tariff that does not include the elements
determined in the final rule to be unjust and unreasonable or unduly
discriminatory.\3327\
---------------------------------------------------------------------------

    \3325\ Early Adopters Coalition Initial Comments at 18.
    \3326\ Id. at 2, 15 (citing Emera Maine v. FERC, 854 F.3d 9, 25
(D.C. Cir. 2017)); Indicated PJM TOs Reply Comments at 8; PacifiCorp
Initial Comments at 6-7.
    \3327\ Indicated PJM TOs Reply Comments at 7-9.
---------------------------------------------------------------------------

    1753. The Early Adopters Coalition also express concern that the
proposed reforms would result in a higher burden of proof to justify
departures from the pro forma requirements in future filings and signal
that the Commission may not accept further incremental improvements;
therefore, they ask the Commission to clarify that the final rule will
not stifle their ability to improve their existing tariffs.\3328\
---------------------------------------------------------------------------

    \3328\ Early Adopters Coalition Initial Comments at 21.
---------------------------------------------------------------------------

    1754. PacifiCorp expresses concern that the NOPR proposal could
disrupt some of PacifiCorp's unique processes, including its inclusion
of small generating facilities in the cluster study process with large
generating facilities and its incorporation of the Commission-
jurisdictional interconnection process into its state-level
interconnection procedures.\3329\
---------------------------------------------------------------------------

    \3329\ PacifiCorp Initial Comments at 7-9.
---------------------------------------------------------------------------

    1755. CREA and NewSun contest PacifiCorp's and the other Early
Adopters Coalition's argument that the Commission's approval of their
LGIPs under FPA section 205 exempts them from any reforms adopted in a
final rule in this proceeding because the Commission has an obligation
under FPA section 206 to remedy unjust, unreasonable, and unduly
discriminatory or preferential practices.\3330\ CREA and NewSun also
note that neither utility- nor region-specific findings are necessary
in a generic rulemaking; rather, the Commission can rely on basic
economic theory and generic factual predictions.\3331\ CREA and NewSun
also

assert that the sole authority cited by the Early Adopters Coalition,
Emera Maine v. FERC, is inapposite, because it involved a challenge to
a specific transmission owners' base return on equity, not a nationwide
rulemaking.\3332\
---------------------------------------------------------------------------

    \3330\ CREA and NewSun Reply Comments at 15-16.
    \3331\ Id. at 17-18 (citing Transmission Access Policy Study
Grp. v. FERC, 225 F.3d 667, 687 (D.C. Cir. 2000), aff'd sub nom. New
York v. FERC, 535 U.S. 1, 14 (2002); Xcel Energy Servs. v. FERC, 41
F.4th 548, 560-61 (D.C. Cir. 2022)).
    \3332\ Id. at 19.
---------------------------------------------------------------------------

    1756. In response to requests for additional flexibility, Public
Interest Organizations and Clean Energy Associations assert that
transmission providers should be required to demonstrate in compliance
filings that their approach to a given requirement complies with the
Commission's final rule.\3333\
---------------------------------------------------------------------------

    \3333\ Clean Energy Associations Reply Comments at 11; Public
Interest Organizations Reply Comments at 14.
---------------------------------------------------------------------------

    1757. Xcel asks the Commission to state in the final rule that
there is not just one just and reasonable approach to interconnection
reform.\3334\ Xcel requests that the Commission confirm that
alternative approaches used by RTOs/ISOs that achieve the policy goals
of prioritizing ready interconnection requests and increasing the speed
of interconnection queue processing are consistent with and superior to
the pro forma LGIP, instead of using the independent entity variation
standard when approving those RTOs/ISOs' compliance filings. Xcel
explains that its preferred approach would allow non-RTOs/ISOs to
replicate processes that are working efficiently in RTOs/ISOs.
---------------------------------------------------------------------------

    \3334\ Xcel Initial Comments at 17.
---------------------------------------------------------------------------

    1758. ACORE expresses concern that too much flexibility would
detract from the benefits of a final rule.\3335\ ACORE explains that a
consistent minimum set of requirements and common interconnection study
methods and best practices is essential across all transmission
providers.
---------------------------------------------------------------------------

    \3335\ ACORE Reply Comments at 6.
---------------------------------------------------------------------------

3. Reciprocity Tariffs
    1759. APPA-LPPC and NRECA seek clarification on the NOPR's
statements regarding reciprocity tariffs.\3336\ They point out that
Commission precedent allows non-public utilities to satisfy the
reciprocity requirement of Order No. 888 through one of three means:
(1) providing service to a public utility transmission provider under a
safe harbor tariff; (2) providing service under a bilateral agreement;
or (3) seeking waiver.\3337\ APPA-LPPC and NRECA explain that the
NOPR's statement that non-public utility transmission providers ``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'' could be read
to suggest that the other ways of satisfying the reciprocity
requirement no longer exist.\3338\ APPA-LPPC and NRECA ask the
Commission to clarify that non-public utilities will still be able to
satisfy reciprocity requirements through bilateral arrangements or
waiver.
---------------------------------------------------------------------------

    \3336\ APPA-LPPC Initial Comments at 34-36; NRECA Initial
Comments at 10, 50.
    \3337\ APPA-LPPC Initial Comments at 34; NRECA Initial Comments
at 50.
    \3338\ APPA-LPPC Initial Comments at 36; NRECA Initial Comments
at 51.
---------------------------------------------------------------------------

4. Effective Date
    1760. MISO asks the Commission to make the reforms effective when
orders on compliance are issued, rather than on the final rule's
effective date, to avoid retroactive implementation of the proposed
reforms and disruption in administering interconnection queues.\3339\
MISO explains that an effective date prior to the date of accepted
compliance provisions would require a transmission provider to file new
agreements with pending language, which means that transmission
providers will need to file interconnection agreements and service
agreements instead of using the electronic quarterly report (EQR)
process.
---------------------------------------------------------------------------

    \3339\ MISO Initial Comments at 127; MISO Reply Comments at 27.
---------------------------------------------------------------------------

5. Miscellaneous
    1761. SoCal Edison states that the final rule should not
automatically apply to a wholesale distribution access tariff without
further consideration in a separate rulemaking.\3340\ SoCal Edison
argues that the Commission should allow entities to align distribution-
level tariffs with corresponding transmission-level tariffs to avoid
gaming of interconnection locations and contends that the changes
proposed in this NOPR are too extensive to apply to the unique
characteristics of the distribution system.\3341\ SoCal Edison states
that the Commission has previously confirmed that reforms to the LGIP
and LGIA are not required for the interconnection agreements under the
wholesale distribution access tariff, and different processes,
interconnection costs, and penalties could introduce new challenges for
wholesale distribution providers and interconnection efficiencies that
have not been addressed in the NOPR.
---------------------------------------------------------------------------

    \3340\ SoCal Edison Initial Comments at 10; SoCal Edison Reply
Comments at 2.
    \3341\ SoCal Edison Initial Comments at 10-11.
---------------------------------------------------------------------------

C. Commission Determination

    1762. We modify the deadline for transmission providers to submit a
compliance filing to adopt the requirements of this final rule as
revisions to the LGIP, LGIA, SGIP, and SGIA in their tariffs. We
require the submission of such compliance filings within 90 calendar
days of the publication date of this final rule in the Federal Register
rather than the proposed 180 days from the effective date of the final
rule. We believe that it is important to implement this final rule in a
timely manner, given the pressing need to reform the interconnection
processes, as discussed in this final rule. On the Commission-approved
effective date of the transmission provider's compliance filing with
this final rule, the transmission provider will commence the transition
study process.\3342\ After the conclusion of the transition study
process, the transmission provider will begin the first standard
cluster study process,\3343\ and in its compliance filing, the
transmission provider will indicate the number of calendar days after
the conclusion of the transition study process when it will begin this
first standard cluster study process (e.g., 30 calendar days after the
conclusion of the transition study process).\3344\ By setting a 90-
calendar day compliance filing deadline, the Commission may be in a
position to act on the filings sooner, which will allow transmission
providers to commence the transition process and progress to the first
standard cluster study process earlier, and thereby implement the
reforms contemplated by this final rule earlier rather than later.
---------------------------------------------------------------------------

    \3342\ Pro forma LGIP section <IP_ADDRESS> (Transitional Serial
Study); Pro forma LGIP section <IP_ADDRESS> (Transitional Cluster Study).
    \3343\ We note that this standard cluster study process is
distinct from the transitional cluster study process described
above. See supra section III.A.7.c.
    \3344\ Pro forma LGIP section 3.4.1 (Cluster Request Window).
---------------------------------------------------------------------------

    1763. We note that 90 days is longer than the 60 days provided for
compliance with Order No. 2003. In their compliance filings for Order
No. 2003, transmission providers were required to adopt the pro forma
LGIP and pro forma LGIA. Under this final rule, transmission providers
are required to revise the LGIP, LGIA, SGIP, and SGIA in their tariffs,
but are not provided significant discretion as to the terms of those
documents, except for those who request deviations, as discussed below.
While we recognize that the compliance filings for some transmission
providers will entail more complexity, we believe that 90 calendar

days should be sufficient time to prepare and submit even the more
complex compliance filings. Further, the need to implement the reforms
set forth in this final rule earlier rather than later outweighs the
concerns raised about the timing of the compliance filing deadline.
    1764. Consistent with Order Nos. 888, 890, 2003, 2006, and 845, we
adopt the NOPR proposal to continue to apply the ``consistent with or
superior to'' standard when considering proposals from non-RTO/ISO
transmission providers to deviate from the requirements of this final
rule.\3345\ Consistent with Order Nos. 2003, 2006, and 845, we adopt
the NOPR proposal to continue to use the ``independent entity
variation'' standard when considering such proposals from RTOs/
ISOs.\3346\ Consistent with Order Nos. 888, 890, 2003, 2006, and 845,
we adopt the NOPR proposal to continue to allow non-RTO/ISO
transmission providers to use the regional differences rationale to
seek variations made in response to established reliability
requirements.\3347\ In this final rule, we make no changes to the
standards used to judge requested variations, as described in Order
Nos. 888, 890, 2003, 2006, and 845.
---------------------------------------------------------------------------

    \3345\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,769-
770; Order No. 890, 118 FERC ] 61,119 at P 109 (``[W]e reiterate
that any departures from the pro forma [open access transmission
tariff] proposed by an ISO or an RTO must be `consistent with or
superior to' the pro forma [open access transmission tariff] in this
Final Rule.''); Order No. 2003, 104 FERC ] 61,103 at P 825; Order
No. 2006, 111 FERC ] 61,220 at PP 546-547; Order No. 845, 163 FERC ]
61,043 at P 43 (explaining that a transmission provider that is not
an RTO/ISO that seeks a variation from the requirements of the final
rule must present its justification for the variation as consistent
with or superior to the pro forma LGIA or pro forma LGIP).
    \3346\ Order No. 2003, 104 FERC ] 61,103 at P 826 (``[w]ith
respect to an RTO or ISO . . . we will allow it to seek `independent
entity variations' from the Final Rule . . . This is a balanced
approach that recognizes that an RTO or ISO has different operating
characteristics depending on its size and location and is less
likely to act in an unduly discriminatory manner than a Transmission
Provider that is a market participant.''); Order No. 2006, 111 FERC
] 61,220 at PP 447, 549; Order No. 845, 163 FERC ] 61,043 at P 556.
    \3347\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,770;
Order No. 890, 118 FERC ] 61,119 at P 109; Order No. 2003, 104 FERC
] 61,103 at P 826 (``if on compliance a non-RTO or ISO Transmission
Provider offers a variation from the Final Rule LGIP and Final Rule
LGIA, and the variation is in response to established (i.e.,
approved by the Applicable Reliability Council) reliability
requirements, then it may seek to justify its variation using the
regional difference rationale.''); Order No. 2006, 111 FERC ] 61,220
at PP 546-547; Order No. 845, 163 FERC ] 61,043 at P 43.
---------------------------------------------------------------------------

    1765. We reject requests to presume that any transmission
provider's tariff meets the requirements of this final rule. We
recognize that many transmission providers have adopted or are in the
process of adopting similar reforms to those adopted in this final
rule. We do not intend to disrupt these ongoing transition processes or
stifle further innovation. On compliance, transmission providers can
propose deviations from the requirements adopted in this final rule--
including deviations seeking to minimize interference with ongoing
transition plans--and demonstrate how those deviations satisfy the
standards discussed above, which the Commission will consider on a
case-by-case basis.
    1766. We disagree with commenters that suggest that FPA section 206
requires the Commission to make findings specific to each transmission
provider's tariff in this final rule to require transmission providers
to comply with the requirements of this final rule. As some commenters
recognize, neither utility- nor region-specific findings are necessary
in a generic rulemaking.\3348\
---------------------------------------------------------------------------

    \3348\ See Transmission Access Policy Study Grp., 225 F.3d at
687-88.
---------------------------------------------------------------------------

    1767. In response to commenters that prefer regional reform over
generic one-size-fits-all reform, we note that transmission providers
may seek the appropriate variation on compliance provided the reason
for the variation is sufficiently justified and may continue to propose
solutions to interconnection issues under FPA section 205. However,
given the nation-wide need for reforms to ensure that interconnection
customers are able to interconnect to the transmission system in a
reliable, efficient, transparent, and timely manner, as well as prevent
undue discrimination, we believe that a generic rulemaking is
appropriate, as explained above in section II and throughout this final
rule.
    1768. In the NOPR, the Commission stated that non-public utility
transmission providers ``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.'' \3349\ As requested by NRECA and APPA-LPPC,\3350\ we
clarify that this final rule does not modify the Commission's
reciprocity requirement in Order Nos. 888 and 2003.\3351\ Thus, while a
non-public utility's adoption of the proposed LGIP/LGIA and SGIP/SGIA
changes is a condition of maintaining a safe harbor tariff,\3352\ non-
public utilities may still use a request for waiver or bilateral
agreements to satisfy the reciprocity requirement of Order No. 888-
A.\3353\
---------------------------------------------------------------------------

    \3349\ NOPR, 179 FERC ] 61,194 at P 344.
    \3350\ APPA-LLC Initial Comments at 34-36; NRECA Initial
Comments at 50-51.
    \3351\ Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,760-
761; Order No. 2003, 104 FERC ] 61,103 at PP 840-842.
    \3352\ Order No. 2003, 104 FERC ] 61,103 at P 842 (``A non-
public utility that has a `safe harbor' Tariff may add to its Tariff
an interconnection agreement and interconnection procedures that
substantially conform or are superior to the Final Rule LGIP and
Final Rule LGIA if it wishes to continue to qualify for safe harbor
treatment.'')
    \3353\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,285-
86; see also Order No. 2003, 104 FERC ] 61,103 at P 841; Order No.
2003-A, 106 FERC ] 61,220 at P 760 (clarifying that reciprocity
applies to interconnection service in a manner consistent with the
reciprocity provision in the pro forma open access transmission
tariff); Order No. 2006, 111 FERC ] 61,220 at P 534.
---------------------------------------------------------------------------

    1769. With respect to MISO's comments, as explained below, this
final rule is effective November 6, 2023. This final rule will be
effective as described above; however, the pro forma LGIP, pro forma
LGIA, pro forma SGIP, and pro forma SGIP requirements in transmission
providers' tariffs will not be effective until the Commission-approved
effective date of the transmission provider's filing in compliance with
this final rule. In other words, interconnection customers seeking to
interconnect to MISO's transmission system will not be subject to the
requirements of this final rule until the Commission issues an order on
MISO's compliance filing with a Commission-approved effective date for
MISO's tariff revisions.
    1770. In response to SoCal Edison's request for the Commission to
clarify that the reforms described herein will not automatically apply
to wholesale distribution access tariffs, we note that in Order No.
2003, the Commission stated that the pro forma LGIA and pro forma LGIP
adopted in that final rule apply to a request to interconnect to a
public utility's ``distribution'' facilities used to transmit electric
energy in interstate commerce on behalf of a wholesale purchaser
pursuant to a Commission-filed open access transmission tariff.\3354\
To the extent that SoCal Edison has concerns about its specific
wholesale distribution access

tariff, this is a matter better suited to SoCal Edison's compliance
filing.\3355\
---------------------------------------------------------------------------

    \3354\ See Order No. 2003, 104 FERC ] 61,103 at P 804; id. P 803
(some lower-voltage facilities are ``local distribution'' facilities
not under our jurisdiction, but some are used for jurisdictional
service such as carrying power to a wholesale power customer for
resale and are included in a public utility's open access
transmission tariff (although in some instances, there is a separate
open access transmission tariff rate for using them, sometimes
called a wholesale distribution rate.)); Order No. 2003-A, 106 FERC
] 61,220 at P 733 (``We clarify that Order No. 2003 applies to all
facilities subject to a Commission-approved [open access
transmission tariff], regardless of how the facilities may be
labeled by the Transmission Provider) (citing N. Y. v. FERC, 535
U.S. at 12; Puget Sound Energy, Inc., 104 FERC ] 61,272, at PP 16-18
(2003)).
    \3355\ See Order No. 2003-A, 106 FERC ] 61,220 at P 734. We
note, however, that the Commission has previously accepted SoCal
Edison's filing, made in compliance with Order No. 2003, to
implement provisions from the Commission's pro forma LGIA and pro
forma LGIP into its wholesale distribution access tariff. See S.
Cal. Edison Co., 110 FERC ] 61,176 (2005).
---------------------------------------------------------------------------

    1771. We also note that, in addition to the modifications described
above, the pro forma LGIP, pro forma LGIA, pro forma SGIP, pro forma
SGIP language below includes several corrections of clerical errors and
other minor, clarifying edits: see, e.g., pro forma LGIA article 8.4,
pro forma LGIP appendix G.

V. Information Collection Statement

    1772. The information collection requirements contained in this
final rule are subject to review by the Office of Management and Budget
(OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\3356\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\3357\ Respondents
subject to the filing requirements of this final rule will not be
penalized for failing to respond to the collection of information
unless the collection of information displays a valid OMB control
number.
---------------------------------------------------------------------------

    \3356\ 44 U.S.C. 3507(d).
    \3357\ 5 CFR 1320.11 (2022).
---------------------------------------------------------------------------

    1773. The reforms adopted in this final rule revise the
Commission's standard large generator interconnection procedures and
agreements (i.e., the pro forma LGIP and pro forma LGIA) and the
Commission's 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
tariff under Sec.  35.28 of the Commission's regulations.\3358\ This
final rule requires each transmission provider to amend the standard
large generator interconnection procedures and agreement and the
standard small generator interconnection procedures and agreement in
its tariff to implement the reforms adopted in this final rule, which
are intended to ensure that the generator interconnection process is
just, reasonable, and not unduly discriminatory or preferential. These
provisions affect the following collections of information: FERC-516,
Electric Rate Schedules and Tariff Filings (Control No. 1902-0096); and
FERC-516A, Standardization of Small Generator Interconnection
Agreements and Procedures (Control No. 1902-0203).
---------------------------------------------------------------------------

    \3358\ 18 CFR 35.28(f)(1) (2022).
---------------------------------------------------------------------------

    1774. In the NOPR, the Commission solicited comments on: the
Commission's need for this information; whether the information will
have practical utility; the accuracy of the burden estimates; ways to
enhance the quality, utility, and clarity of the information to be
collected or retained; and any suggested methods for minimizing
respondents' burden. In response to comments on the NOPR,\3359\ we note
that this information collection statement estimates only those burdens
\3360\ to generate, maintain, retain, or disclose or provide
information to or for a Federal agency, and does not intend to estimate
overall compliance or implementation costs for transmission providers.
---------------------------------------------------------------------------

    \3359\ Indicated PJM TOs state that the NOPR did not attempt to
quantify the administrative burden for the transmission provider's
staff to perform the tasks required by the proposed reforms, and SPP
offered an estimated range of its potential costs of administering
the proposed procedures. See Indicated PJM TOs Initial Comments at
7; SPP Initial Comments at 28; see also NOPR, 179 FERC ] 61,194 at P
358 & n.480.
    \3360\ ``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 (2022).
---------------------------------------------------------------------------

    1775. Summary of the Revisions to the Collection of Information due
to the final rule in Docket No. RM22-14-000:
     FERC-516: This final rule revises the Commission's pro
forma LGIP and pro forma LGIA (and thus requires each public utility to
amend its LGIP and LGIA) to ensure that interconnection customers are
able to interconnect to the transmission system in a reliable,
efficient, transparent, and timely manner, and prevent undue
discrimination. As illustrated in the table below, most reforms affect
the pro forma LGIP and pro forma LGIA.
     FERC-516A: Among other requirements, this final rule
amends the Commission's standard small generator interconnection
procedures and agreement (i.e., the pro forma SGIP and pro forma SGIA)
regarding evaluation of alternative transmission technologies, modeling
required for accurate interconnection studies, and maintenance of power
production during abnormal frequency conditions and certain voltage
conditions.
     Title: Electric Rate Schedules and Tariff Filings (FERC-
516) and Standardization of Small Generator Interconnection Agreements
and Procedures (FERC-516A).
     Action: Revision of collections of information in
accordance with Docket No. RM22-14-000.
     OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0203
(FERC-516A).
     Respondents: Public utility transmission providers,
including RTOs/ISOs.
     Frequency of Information Collection: One time during Year
1. Multiple times during subsequent years.
     Necessity of Information: The reforms in this final rule
ensure that interconnection customers are able to interconnect to the
transmission system in a reliable, efficient, transparent, and timely
manner, and prevent undue discrimination. The reforms are intended to
ensure that the generator interconnection process is just, reasonable,
and not unduly discriminatory or preferential.
     Internal Review: We have reviewed the reforms that impose
information collection burdens and have determined that such reforms
are necessary. These requirements 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 information collection requirements.
     Public Reporting Burden: Our estimate of the number of
reporting entities is based on the number of transmission providers
that submitted compliance filings to the Commission in response to
Order No. 845, which is the Commission's most recent rulemaking that
required transmission providers to revise their generator
interconnection procedures and agreements, and Order No. 881, which is
the Commission's most recent major rulemaking adopting reforms to the
pro forma tariff. As such, we estimate that 44 transmission providers,
including RTOs/ISOs, will be subject to this rulemaking. The burden 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. For many reforms, we estimate no
ongoing information collection burden because there is either no
information collection aspect of the reform or the requirements would
merely supplant existing ones.
    1776. The Commission estimates that the final rule in Docket No.
RM22-14-000 will adjust the burden and cost of FERC-516 and FERC-516A
as follows:

                                                      Table 1--Information Collection Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                   Changes due to Final Rule in Docket No. RM22-14-000
---------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Annual number of                             Average burden (hr.) &    Total annual burden
               Reforms                    Number of           responses per           Total number of      cost ($) per response   hours & total annual
                                         respondents            respondent          responses (rounded)           \3361\            cost ($) (rounded)
                                                    (1)  (2)....................  (1) * (2) = (3).......  (4)...................  (3) * (4) = (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        FERC-516
--------------------------------------------------------------------------------------------------------------------------------------------------------
Interconnection Information Access..           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 2.............  Ongoing: 88...........  Ongoing: 4 hr; $364...   $16,016
                                                                                Ongoing: 352 hr;
                                                                                $32,032
First Ready, First Served Cluster              44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 80 hr; $7,280.  Year 1: 3,520 hr;
 Study Process.                                          Ongoing: 4.............  Ongoing: 176..........  Ongoing: 4 hr; $364...   $320,320
                                                                                Ongoing: 704 hr;
                                                                                $64,064
Allocation of Cluster Study Costs...           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                Ongoing: 0
Allocation of Cluster Network                  44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
 Upgrade Costs.                                          Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                Ongoing: 0
Study Deposits and LGIA Deposit.....           44 (TPs)  Year 1: 1..............  Year 1: 44............  Year 1: 4 hr; $364....  Year 1: 176 hr;
                                                         Ongoing: 0.............  Ongoing: 0............  Ongoing: 0............   $16,016
                                                                                Ongoing: 0