customer's generating facility to the transmission provider's system,
with a maximum level equal to the generating facility capacity.
Accordingly, an interconnection customer cannot amass large excesses of
interconnection service beyond its own needs. Furthermore, as discussed
earlier, interconnection customers are free to seek interconnection
service through the non-surplus interconnection process of the
transmission provider. While an original interconnection customer could
maintain control over a certain amount

of interconnection service, that service will be limited to the
original interconnection customer's generating facility capacity (which
is based on the size of the generating facility it constructs and
continues to operate). If the original interconnection customer does
not construct the facility it has represented to the transmission
provider, or retires that facility, the transmission provider may
terminate the customer's LGIA in accordance with applicable provisions
in its tariff. Accordingly, we see no significant concern with hoarding
interconnection service.
e. Property Rights
i. Comments
    491. As further described below, some commenters assert that the
NOPR's surplus interconnection proposals treat interconnection service
as a property right of the interconnection customer even though they
may not have been so treated in the past. CAISO states that Commission
precedent holds that the interconnection capacity does not confer a
property right, and that where an interconnection customer builds less
generating facility capacity than that for which it requested
interconnection service, it does not retain that interconnection
capacity indefinitely, and transmission providers like CAISO may
subsequently remove it from their base case.\852\ NYISO asserts that
the NOPR would expand what is currently a contractual right, namely the
right to a particular point of interconnection, into a property right
by allowing a generator to transfer interconnection service to a third
party.\853\ SoCal Edison states that the NOPR assumes that
interconnection capacity is a property right, but that in many cases
the interconnection customer did not pay for the ``surplus.'' \854\
---------------------------------------------------------------------------

    \852\ CAISO 2017 Comments at 32 (citing CalWind Resources Inc.
v. California Independent System Operator Corp., 146 FERC ] 61,121,
at PP 33 et seq. (2014)).
    \853\ NYISO 2017 Comments at 41.
    \854\ SoCal Edison 2017 Comments at 9.
---------------------------------------------------------------------------

    492. On the other hand, some interconnection customers assert that
contracted interconnection service is indeed a property right.
Generation Developers support recognizing that surplus capacity is a
property right and asset of the existing interconnection customer.\855\
Cogeneration Association argues that transfer of capacity cannot be
done without the consent of the existing interconnection customer, and
that the existing interconnection customer should be able to negotiate
the terms and compensation for the transfer of capacity.\856\
---------------------------------------------------------------------------

    \855\ Generation Developers 2017 Comments at 41.
    \856\ Cogeneration Association 2017 Comments at 3.
---------------------------------------------------------------------------

ii. Commission Determination
    493. We are, in this final action, adopting a requirement that
transmission providers establish a process for the use or transfer of
surplus interconnection service, and we do not view that policy as
establishing a new property right to interconnection service. Rather,
as NYISO contends, interconnection service is a contractual right
provided by an LGIA. We also agree with CAISO that where the original
interconnection customer, for example, reduces the generating facility
capacity of its facility from what was originally proposed for
interconnection, it would not retain rights indefinitely to any excess
interconnection capacity thus created.
f. Original Interconnection Customer's Priority
i. Comments
    494. Some commenters argue that the proposed priority for original
interconnection customers and their affiliates should have a limited
term. MidAmerican \857\ and CAISO \858\ support a limit of three years
from when the original generation facility last produced energy. EDP
proposes a minimum of five years. EDP cites compatibility with the
five-year safe harbor granted to interconnection customer
interconnection facilities in Order No. 807 as support for a five year
priority here.\859\ MISO TOs,\860\ PJM,\861\ and TDU Systems \862\
support a time limit, either after the original commercial operations
date if the interconnection customer has failed to achieve commercial
operations, or for some period after it has ceased commercial
operations, but do not specify a duration, preferring to leave each RTO
or ISO with discretion to determine appropriate duration.
---------------------------------------------------------------------------

    \857\ MidAmerican 2017 Comments at 20.
    \858\ CAISO 2017 Comments at 33.
    \859\ EDP 2017 Comments at 8.
    \860\ MISO TOs 2017 Comments at 40.
    \861\ PJM 2017 Comments at 26.
    \862\ TDU Systems 2017 Comments at 29-30.
---------------------------------------------------------------------------

ii. Commission Determination
    495. While the Commission sought comment in the NOPR on whether any
limitations should be placed on the original interconnection customer's
priority use of its interconnection service, we find that the original
interconnection customer, through its LGIA, may use or transfer any
surplus interconnection service until it retires the generating
facility that is the subject of the LGIA. We see no reason to modify
that ability. Accordingly, original interconnection customers will
retain the ability to use, either for themselves, for an affiliate, or
for sale to a third party of their choosing, any surplus
interconnection service that may exist under their LGIAs, until their
original generating facility retires. However, as described more fully
in subsection (h) below, this right becomes more limited once the
original interconnection customer schedules the retirement of its
original generating facility.
g. Contractual Arrangements
i. Comments
    496. Commenters that were responsive to the Commission's questions
regarding contractual arrangements generally agree that contractual
arrangements are necessary between the surplus interconnection customer
and the original interconnection customer, as well as with the
transmission owner.\863\ Specifically, Cogeneration Association states
that collateral agreements between the interconnection customers are
necessary, as dealing with rights and obligations between the original
interconnection customer and new interconnection customer may not be
included in the LGIA.\864\ Similarly, AWEA supports the idea of the
original and new interconnection customers each having a separate
LGIA.\865\
---------------------------------------------------------------------------

    \863\ Cogeneration Association 2017 Comments at 5; ITC 2017
Comments at 20; Generation Developers 2017 Comments at 41; Duke 2017
Comments at 22.
    \864\ Cogeneration Association 2017 Comments at 5.
    \865\ AWEA 2017 Comments at 59.
---------------------------------------------------------------------------

    497. ITC argues that the Commission should specify in the pro forma
LGIA that the original interconnection customer will serve as the
single point of contact for operational directives and outage
coordination by the transmission provider and/or transmission owner.
According to ITC, transmission providers/owners should not be required
to coordinate these operational issues with multiple, potentially-
unaffiliated parties. Rather, ITC argues, it is appropriate that the
original interconnection customer that elects to make surplus capacity
available assume the obligation of coordinating with surplus
customers.\866\
---------------------------------------------------------------------------

    \866\ ITC 2017 Comments at 20.
---------------------------------------------------------------------------

    498. Generation Developers argue that the Commission should require
a transmission provider to have a pro forma surplus interconnection
agreement.\867\ Duke agrees with the

NOPR proposal that a new interconnection agreement for surplus
interconnection service must be executed, or filed unexecuted, by the
transmission provider, transmission owner (as applicable), and the
surplus interconnection service customer and suggests that the MISO
LGIA template provides a framework for such agreements between the
interconnection customers and transmission providers.\868\
---------------------------------------------------------------------------

    \867\ Generation Developers 2017 Comments at 41.
    \868\ Duke 2017 Comments at 22.
---------------------------------------------------------------------------

ii. Commission Determination
    499. We agree with commenters that agreements between the original
interconnection customer, the surplus interconnection service customer
(whether affiliated or not), and the transmission provider are
necessary to establish conditions such as the term of operation, the
interconnection service limit, and the mode of operation for energy
production (i.e., common or singular operation) and to establish the
roles and responsibilities of the parties for maintaining the operation
of the facility within the parameters of the surplus interconnection
service agreement. Therefore, we require that the original
interconnection customer, the surplus interconnection service customer,
and the transmission provider enter into such agreements for surplus
interconnection service and that they be filed by the transmission
provider with the Commission, because any surplus interconnection
service agreement will be an agreement under the transmission
provider's OATT.
    500. However, we decline to establish these agreements as part of
the pro forma LGIA or prescribe their terms and conditions. This will
give transmission providers flexibility to establish agreements
appropriate for their region (e.g., they may be different for RTO/ISO
and non-RTO/ISO regions) and the unique conditions of each agreement
for surplus interconnection service. It will also alleviate some
potential burden by allowing transmission providers to either file pro
forma versions of these agreements with the Commission, as was done in
MISO, or execute them as needed and file them with the Commission on an
ad hoc basis.
h. Retirement, Repowering and Continuation of Surplus Interconnection
Service After the Original Interconnection Customer's Generating
Facility Retires
i. Comments
    501. Some commenters discuss the NOPR as it might relate to
retirement of generators and replacement or repowering.\869\ Xcel
argues that the retention of rights by the interconnection customer or
its affiliates may be helpful at the current time when many utilities
are going through retirement and replacement or repowering.\870\ Xcel
argues that using this approach for repowering leads to efficiency
because re-using brownfield sites is the most cost-effective approach
to repowering, and suggests that the Commission should encourage this
practice.\871\ CAISO states that it allows repowering, and notes that,
in some cases, this process has led to the replacement of conventional
generation by electric storage.\872\ PG&E supports the CAISO repowering
process for allowing new generation on the grid while potentially
minimizing interconnection and network upgrade costs.\873\ ISO-NE
states that its forward capacity market can accommodate repowering by
maintaining the interconnection service while the interconnection
customer builds a new generating facility that can take the place of a
retiring unit.\874\
---------------------------------------------------------------------------

    \869\ For purposes of this final action, we adopt CAISO's
definition of ``repowering,'' which defines repowering as a
modification of existing generating units that does not: (i)
Increase the total capability of the plant; or (ii) substantially
change its electrical characteristics such that original reliability
studies would be affected. See Section 25.1.2 of the CAISO tariff;
Section 12 of the business practice manuals for Generator
Management, https://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Generator%20Management.
    \870\ Xcel 2017 Comments at 19.
    \871\ Id. at 20.
    \872\ CAISO 2017 Comments at 33.
    \873\ PG&E 2017 Comments at 9.
    \874\ ISO-NE 2017 Comments at 50.
---------------------------------------------------------------------------

    502. Other commenters discuss whether surplus interconnection
service should terminate at the same time the original interconnection
customer's generating facility retires. Cogeneration Association argues
that this matter should be stated in the LGIA or collateral agreement,
but that the default position should be that the termination of rights
of the surplus interconnection customer should occur simultaneously
with the termination of rights of the original interconnection
customer.\875\ Generation Developers argue for the survivorship of the
surplus interconnection service when the original interconnection
customer's generating facility retires, on the basis that the surplus
interconnection customer would have paid the original interconnection
customer for the interconnection rights.\876\ Xcel supports
survivorship because of greater commercial attractiveness and helping
the new interconnection customers to get financing.\877\
---------------------------------------------------------------------------

    \875\ Cogeneration Association 2017 Comments at 5-6.
    \876\ Generation Developers 2017 Comments at 42.
    \877\ Xcel 2017 Comments at 21.
---------------------------------------------------------------------------

ii. Commission Determination
    503. The purpose of this reform is to enable the efficient use of
any surplus interconnection service that may exist in connection with
an original interconnection customer's use of its generating facility.
The retirement or repowering of that original interconnection
customer's generating facility would represent activities outside the
normal use of that generating facility. Accordingly, we find that, with
one exception discussed below, retirement and repowering issues are
outside the scope of this rulemaking, and should instead be addressed
elsewhere (e.g., through the existing processes discussed by some
commenters).
    504. With respect to continuation of surplus interconnection
service after the retirement of the original interconnection customer's
generating facility, we find that surplus interconnection service is,
by definition, tied to the continued existence of the original
interconnection customer's interconnection service. There must be some
existing interconnection service from which the ability to provide
surplus interconnection service has been identified. As described
above, once the original interconnection service terminates, there is
no longer an original interconnection service from which the ability to
provide surplus interconnection service could be identified. Therefore,
surplus interconnection service shall not be available when the
original interconnection customer retires and permanently ceases
commercial operation.
    505. However, we believe it is appropriate to permit a limited
continuation of surplus interconnection service following the
retirement and permanent cessation of commercial operation of the
original interconnection customer's generating facility to ameliorate
the business and financial risk to the surplus interconnection service
customer if the original interconnection customer retires unexpectedly,
when two conditions are met. First, the surplus service interconnection
customer's generation facility must have been studied by the
transmission provider for sole operation at the point of
interconnection at the time of the interconnection of the surplus
service interconnection customer. Second, the original interconnection
customer (and now

retiring) must have agreed in writing that the surplus interconnection
service customer may continue to operate at either its limited share of
the original interconnection customer's generating facility capacity in
the original interconnection customer's LGIA, as reflected in its
surplus interconnection service agreement, or at any level below such
limit upon the retirement and permanent cessation of commercial
operation of the original interconnection customer's generating
facility.
    506. If these conditions are met, then the transmission provider
must permit the surplus interconnection service customer to continue
the surplus interconnection service for a limited period not to exceed
one year. To prevent gaming and abuse of the continuation of surplus
interconnection service, such service shall be limited to no more than
one year after the date of retirement and permanent cessation of
commercial operation of the original interconnection customer. If these
conditions are not met, then those agreements regarding the surplus
interconnection service must be drafted to, and must, terminate
simultaneously with the termination of the original interconnection
agreement from which surplus interconnection service was provided.
    507. We note again that interconnection customers are under no
obligation to choose surplus interconnection service rather than
seeking their own stand-alone interconnection service directly from the
transmission provider. Therefore, any interconnection customers that
require greater assurance up front that their interconnection service
will not be affected by the retirement of another generating facility
should carefully consider whether surplus interconnection service is
the right match for their particular needs.
i. Relationship to MISO Net Zero Interconnection Service
i. Comments
    508. MISO argues that, as a part of the final action, the
Commission should allow MISO to remove certain restrictions on its
existing Net Zero Interconnection Service that it argues exceed the
restrictions proposed for the surplus interconnection service.\878\
---------------------------------------------------------------------------

    \878\ MISO 2017 Comments at 36.
---------------------------------------------------------------------------

ii. Commission Determination
    509. We agree with MISO that this final action includes fewer
restrictions on the use of surplus interconnection service than what
the Commission imposed on MISO's Net Zero Interconnection Service,
which has a similar goal. As noted above, the requirements we enact in
this final action for surplus interconnection service depart in some
respects from our precedent regarding MISO's Net Zero Interconnection
Service. This final action reflects a shift in the Commission's view of
these issues as described in earlier subsections of this final action.
To the extent that MISO wishes to modify the procedures surrounding its
Net Zero Interconnection Service, MISO may propose to do so on
compliance in this proceeding, and the Commission will evaluate that
proposal to determine if it complies with the requirements of the final
action.
4. Material Modification and Incorporation of Advanced Technologies
a. NOPR Proposal
    510. Under the pro forma LGIP, an interconnection customer can
modify its interconnection request and still retain its queue position
if the modifications are either explicitly allowed under the pro forma
LGIP or if the transmission provider determines that the modifications
are not material. The pro forma LGIA defines material modifications as
``those modifications that have a material impact on the cost or timing
of any Interconnection Request with a later queue priority date.''
\879\ Under the pro forma LGIP, an interconnection customer must submit
to the transmission provider, in writing, modifications to any
information provided in the interconnection request.\880\ The pro forma
LGIP directs transmission providers to commence any necessary
additional studies related to the interconnection customer's
modification request no later than 30 calendar days after receiving
notice of the request.\881\ If the transmission provider determines
that the proposed modification is material, the interconnection
customer can choose to abandon the proposed modification or proceed and
lose its queue position.
---------------------------------------------------------------------------

    \879\ Pro forma LGIA Art. 1.
    \880\ See pro forma LGIP Section 4.4.
    \881\ See pro forma LGIP Section 4.4.4.
---------------------------------------------------------------------------

    511. In the NOPR, the Commission explained that the pro forma LGIP
does not contain guidance regarding analysis and modeling for the
incorporation of technological advancements into an existing
interconnection request. The Commission preliminarily found that the
discretion resulting from this lack of guidance can lead to unjust and
unreasonable rates, terms, and conditions, and unduly discriminatory or
preferential practices, especially for technological advancements.\882\
The Commission thus proposed to require transmission providers to
establish a technological change procedure in their LGIPs to assess
and, if necessary, study whether they can accommodate a technological
advancement without the change being considered material.\883\ The
Commission stated that such a procedure would allow an interconnection
customer to provide an analysis of how its proposed technological
advancement would result in electrical performance that is equal to or
better than the electrical performance expected prior to the
change.\884\ Using such a procedure, a transmission provider would
determine whether a technological advancement is a material
modification. If it was not a material modification, the
interconnection customer could incorporate the technological
advancement without losing its queue position.
---------------------------------------------------------------------------

    \882\ NOPR, FERC Stats. & Regs. ] 32,719 at P 216.
    \883\ Id. P 217.
    \884\ Id. PP 217-18.
---------------------------------------------------------------------------

    512. In the NOPR, the Commission also proposed to require
transmission providers to develop a definition of permissible
technological advancements that the interconnection process can
accommodate without the change being considered a material
modification.\885\ Thus, pursuant to this proposal, a permissible
technological advancement is a technological advancement that, by
definition, does not constitute a material modification. Further, the
Commission proposed that this definition should contemplate
advancements that provide cost efficiency and/or electrical performance
benefits.\886\ The Commission proposed that in the scenario where a
transmission provider requires a study for a proposed technological
advancement to not be considered a material modification, the
interconnection customer should tender an appropriate study deposit and
provide the necessary modeling data that sufficiently models the
behavior of the new equipment and any other required data about the
technological advancement to the transmission provider.\887\
---------------------------------------------------------------------------

    \885\ Id. P 217.
    \886\ Id. P 212.
    \887\ Id. P 219.
---------------------------------------------------------------------------

    513. To implement the technological change procedure, the
Commission also proposed to require transmission providers to define
technological advancements in their LGIPs. The Commission stated that
the definition should consider technological advancements to equipment
that may

achieve cost and grid performance efficiencies.\888\ Finally, the
Commission proposed to permit interconnection customers to submit
technological advancement requests for incorporation any time before
the execution of the facilities study agreement.\889\
---------------------------------------------------------------------------

    \888\ Id. P 222.
    \889\ Id. P 223.
---------------------------------------------------------------------------

    514. Accordingly, the Commission proposed to revise section 4.4.2
of the pro forma LGIP as follows (with proposed deletions in brackets
and with proposed additions in italics):

    4.4.2 Prior to the return of the executed Interconnection
Facility Study Agreement to the Transmission Provider, the
modifications permitted under this Section shall include
specifically: (a) Additional 15 percent decrease in plant size (MW),
[and] (b) Large Generating Facility technical parameters associated
with modifications to Large Generating Facility technology and
transformer impedances; provided, however, the incremental costs
associated with those modifications are the responsibility of the
requesting Interconnection Customer; and (c) a technological
advancement for the Large Generating Facility after the submission
of the interconnection request. Section 4.4.4 specifies a separate
Technological Change Procedure including the requisite information
and process that will be followed to assess whether the
Interconnection Customer's proposed technological advancement under
Section 4.4.2(c) is a Material Modification. Section 1 contains a
definition of Technological Advancement.\890\
---------------------------------------------------------------------------

    \890\ With respect to this new provisions to the pro forma LGIP,
we make minor clarifying edits to the pro forma tariff language
originally proposed in the NOPR, as shown in Appendix B to Order No.
845. Specifically, the comma after section 4.4.2(a)(2) will be
replaced with a semicolon, and pro forma section 4.4.2 will no
longer capitalize ``Technological Change Procedure.'' Additionally,
in the last sentence of pro forma section 4.4.2, ``technological
advancement'' will now say ``Permissible Technological
Advancement.'' Also, section 1 of the pro forma LGIP will contain a
placeholder for the definition of ``Permissible Technological
Advancement, and there is now a placeholder for each transmission
provider's technological change procedure in pro forma LGIP section
4.4.4.
---------------------------------------------------------------------------

b. Technological Change Procedure
i. Comments
    515. The majority of commenters support \891\ or do not object
\892\ to the proposal. AFPA and ELCON cite the proposal's potential to
lower interconnection costs and avoid costly delays in commercial
operation.\893\ AWEA comments that the proposal will provide
transparency and certainty to both the transmission provider and the
interconnection customer, and will remove a barrier to the use of the
most modern, cost effective technology.\894\ NextEra states that
transmission providers are inconsistent in considering potential
changes to the equipment being installed under an interconnection
agreement.\895\ Alliant asserts that the current definition of material
modification is unclear and that more guidance is needed from the
Commission in terms of what would trigger a material modification
study.\896\ Idaho Power agrees with the proposal provided that an
interconnection customer will be responsible for any necessary network
upgrades that are identified and for which the transmission provider
committed expenses before the technological advancement request.\897\
TDU Systems supports the flexibility built into the proposal and adds
that, if technological advancements include changes to the equipment's
electrical characteristics, then the models require modification, the
simulations must be re-run, and the results require reevaluation.\898\
---------------------------------------------------------------------------

    \891\ Alliant 2017 Comments at 13; AFPA 2017 Comments at 16;
AWEA 2017 Comments at 60; CAISO 2017 Comments at 35; Joint Renewable
Parties 2017 Comments at 12; ELCON 2017 Comments at 7; Idaho Power
2017 Comments at 6; IECA Comments at 3; ISO-NE 2017 Comments at 51;
MISO 2017 Comments at 5; NEPOOL 2017 Comments at 18; NextEra 2017
Comments at 52; TDU Systems 2017 Comments at 30-31; PJM 2017
Comments at 30.
    \892\ APPA/LPPC 2017 Comments at 26; NYISO 2017 Comments at 43;
SEIA 2017 Comments at 21.
    \893\ AFPA 2017 Comments at 4; ELCON 2017 Comments at 7.
    \894\ AWEA 2017 Comments at 60.
    \895\ NextEra 2017 Comments at 52.
    \896\ Alliant 2017 Comments at 13.
    \897\ Idaho Power 2017 Comments at 6.
    \898\ TDU Systems 2017 Comments at 30-31.
---------------------------------------------------------------------------

    516. Multiple RTOs/ISOs support or do not oppose the NOPR's
technological advancement proposal, while some do not necessarily
believe that the NOPR proposal is necessary. For example, CAISO states
that it supports the proposal.\899\ MISO also supports the proposal,
and comments that interconnection customers should not forfeit
interconnection rights simply because the technology of their
generating facility has become outdated.\900\ ISO-NE and NEPOOL state
that ISO-NE's 2016 revisions to its interconnection procedures already
establish clear rules to consistently and expeditiously determine
whether a proposed modification is material.\901\ ISO-NE states that it
developed its rules to respond to continuous requests for technical
changes, which were one contributing factor to the Maine queue
backlog.\902\ ISO-NE states that its recent tariff changes have
addressed these issues. NYISO asserts that it does not oppose the NOPR
proposal if it is limited to assessing the materiality and
consideration of whether the transmission provider can accommodate a
modification to the specific technology type initially proposed (as
opposed to changing from gas to wind, for example).\903\ PJM states
that it is not opposed to accounting for technological changes during
the study process.\904\ However, PJM cites to its current practice of
incorporating technological changes and states that a separate
``technological change procedure'' is not necessary to determine
whether such a modification is material.\905\
---------------------------------------------------------------------------

    \899\ CAISO 2017 Comments at 35.
    \900\ MISO 2017 Comments at 5.
    \901\ ISO-NE 2017 Comments at 52; NEPOOL 2017 Comments at 18.
    \902\ ISO-NE 2017 Comments at 52-53. ISO-NE noted that the
revisions were developed with stakeholders to address
interconnection challenges that have led to a backlog of
interconnection requests for 4,000 MW of primarily wind generation
in Maine. See ISO New England Inc. and Participating Transmission
Owners Admin. Comm., 155 FERC ] 61,031, at P 2 (2016).
    \903\ NYISO 2017 Comments at 43.
    \904\ PJM 2017 Comments at 30.
    \905\ PJM 2017 Comments at 30.
---------------------------------------------------------------------------

    517. Other commenters do not support the NOPR proposal or believe
that the proposed changes are unnecessary. For example, EEI and some
public utility transmission providers outside the RTOs/ISOs comment
that current material modification provisions are adequate.\906\ EEI
asserts that the Commission has not clearly explained the difference
between a technological advancement and a material modification and
that the proposal unreasonably limits a transmission provider's ability
to evaluate reliability impacts.\907\ EEI states that, if the
Commission decides to establish more granular procedures for
technological advancements, it should not duplicate the material
modification requirements. Instead, EEI suggests that the Commission
could require transmission providers to explain whenever a change that
is not explicitly listed in the pro forma LGIP constitutes a material
modification.\908\ EEI also states that it is reasonable to leave
significant discretion to sound engineering judgment in order to
balance the need to implement technological advancements, improve
performance and efficiencies, and to maintain safe, reliable
service.\909\ Southern adds that the concern should not be about
developing types of advanced technologies, but how that

technology impacts already queued requests.\910\ TVA suggests that,
rather than identifying specific pre-qualified technical advancements,
interconnection customers should update their model data before
starting the system impact study.\911\ Xcel notes that the types and
impacts of changes evolve as technology advances, and while it does not
consider a pro forma LGIP change necessary, it encourages customers to
provide studies and evidence that any change is immaterial.\912\ Xcel
also recommends that the Commission hold a technical conference or
workshop to discuss material modification issues, which it anticipates
will show the variation and difficulty involved in evaluating such
modifications.\913\
---------------------------------------------------------------------------

    \906\ AES 2017 Comments at 8-9; Duke 2017 Comments at 24; EEI
2017 Comments at 67; PG&E 2017 Comments at 9 (citing CAISO Business
Practice Manual for Generator Management Section 6); Southern 2017
Comments at 32; TVA 2017 Comments at 18; Xcel 2017 Comment at 22.
    \907\ EEI 2017 Comments at 5, 67, 68-69.
    \908\ Id. at 69, 73.
    \909\ Id. at 73.
    \910\ Southern 2017 Comments at 32.
    \911\ TVA 2017 Comments at 18.
    \912\ Xcel 2017 Comment at 22.
    \913\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    518. We adopt the NOPR proposal subject to certain clarifications.
We require transmission providers to include in their pro forma LGIP a
technological change procedure. They must also assess, and if
necessary, study whether proposed technological advancements can be
incorporated into interconnection requests without triggering the
material modification provisions of the pro forma LGIP. Furthermore,
transmission providers must, consistent with the guidance provided in
this final action, develop a definition of permissible technological
advancement. Such permissible technological advancements would, by
definition, not constitute material modifications.
    519. The technological change procedure must specify what
technological advancements can be incorporated at various stages of the
interconnection process, and the procedure must clearly identify which
requirements apply to the interconnection customer and which apply to
the transmission provider. The procedure should state that, if an
interconnection customer seeks to incorporate technological
advancements into its generating facility, it should submit a
technological advancement request. For the transmission provider to
determine that a proposed technological advancement is not a material
modification, the procedure must specify the information that the
interconnection customer must submit as part of a technological
advancement request. The procedure must also specify the conditions
under which a study will or will not be necessary to determine whether
a proposed technological advancement is a material modification.
    520. For a transmission provider to be able to determine whether a
proposed technological advancement is not a material modification, the
interconnection customer's technological advancement request must
demonstrate that the proposed incorporation of the technological
advancement would result in electrical performance that is equal to or
better than the electrical performance expected prior to the technology
change and not cause any reliability concerns (i.e., materially impact
the transmission system with regard to short circuit capability limits,
steady-state thermal and voltage limits, or dynamic system stability
and response).\914\
---------------------------------------------------------------------------

    \914\ In the next section, we respond to EEI's comment as to
what was meant by ``performance that is equal or better than the
electrical performance expected prior to the technology change.''
---------------------------------------------------------------------------

    521. The transmission provider must determine whether a requested
technological advancement is a material modification and whether or not
a study is necessary to complete the analysis of whether the
technological advancement is a material modification. The procedure
must state that, if a study is necessary to evaluate whether a
particular technological advancement is a material modification, the
transmission provider must clearly indicate to the interconnection
customer the types of information and/or study inputs that the
interconnection customer must provide to the transmission provider,
including for example, study scenarios, modeling data, and any other
assumptions. The procedure should also explain how the transmission
provider will evaluate the technological advancement request to
determine whether it is a material modification.
    522. If the transmission provider cannot accommodate a proposed
technological advancement without triggering the material modification
provision of the pro forma LGIP, the transmission provider shall
provide an explanation to the interconnection customer regarding why
the technological advancement is a material modification.
    523. We find that the current definition of material modification
may create uncertainty about whether a transmission provider must
consider a technological advancement to be a material modification, and
we agree with commenters that the requirement that we adopt in this
final action will increase transparency, create process efficiencies,
and encourage technological innovation that could lower consumer
costs.\915\ We find that, contrary to the assertions that the existing
material modification procedures are adequate, the proposed reforms are
necessary to improve certainty and transparency.
---------------------------------------------------------------------------

    \915\ See AFPA 2017 Comments at 16; AWEA 2017 Comments at 60-61;
ELCON 2017 Comments at 7; NextEra 2017 Comments at 52.
---------------------------------------------------------------------------

    524. Some transmission providers, such as PJM, believe that a
technological change procedure is unnecessary because their tariffs
already include a method to determine whether a change to an
interconnection request is a material modification. In response to
these comments, if a transmission provider believes its existing
interconnection procedures regarding the incorporation of technological
advancements would qualify for a variation from the final action
requirements or that it already complies with the requirements adopted
in this final action, it may provide such an explanation in its
compliance filing.
    525. EEI, Duke, Southern, TVA, and Xcel assert that the existing
material modification procedures are adequate to incorporate
technological advancements. However, they do not dispute our concern
that transmission providers have significant discretion over what
equipment changes constitute material modifications. EEI takes issue
with the proposal for transmission providers to specify in the
technological change procedure the conditions when a study is
necessary.\916\ EEI further asserts that the Commission has not clearly
explained the difference between a technological advancement and a
material modification and that the proposal unreasonably limits a
transmission provider's ability to evaluate reliability impacts.\917\
In response to these concerns, we note that the purpose of the
technological change procedure is to allow for equipment changes
resulting in electrical performance that is equal to or better than an
interconnection request's previously projected electrical performance
and not cause any reliability concerns.\918\ We have designed the
technological change procedure to allow transmission providers to
evaluate whether equipment changes in an interconnection request should
trigger

the material modification provisions. This new requirement increases
transparency in the interconnection process and allows transmission
providers to evaluate the impact of a proposed technological
advancement to determine whether it qualifies as a material
modification, and, thus will result in the interconnection customer
losing its queue position.
---------------------------------------------------------------------------

    \916\ EEI 2017 Comments at 69-70.
    \917\ Id. at 5, 67, 68-69.
    \918\ For example, an interconnection customer may elect to
incorporate a smart inverter that is capable of sensing and
autonomously reacting to changes on the grid.
---------------------------------------------------------------------------

    526. Regarding Xcel's request for a technical conference, we
believe our determination here is supported by the record evidence and
therefore do not believe that a technical conference on this issue is
necessary.
c. Definition of Permissible Technological Advancements
i. Comments
    527. A handful of commenters offer suggestions regarding the
definition of permissible technological advancements. Some caution
against an overly prescriptive definition to account for the
unpredictability of technology evolution.\919\ Alliant and AWEA support
an inclusive definition of technological advancement that accounts for
changes that already exist.\920\ Alliant states that while a ``loose''
definition of material modification creates uncertainty and additional
risk associated with replacing equipment or completing normal unit
maintenance, an overly rigid definition could burden generator owners
with unnecessary costs and the system operator with a longer backlog or
strained resources.\921\ Other commenters assert that the rate of
technological advancement makes it difficult to speculate which
technologies to include.\922\ MISO TOs request clearer Commission
direction to develop clear material modification guidelines.\923\ They
also state that RTO/ISO guidelines should specify that a change that
does not exceed the interconnection customer's interconnection rights
or materially impact short circuit capability limits, steady-state
thermal and voltage limits, or dynamic system stability and response is
not a material modification.\924\
---------------------------------------------------------------------------

    \919\ AWEA 2017 Comments at 62; Alliant 2017 Comments at 13-14;
Duke 2017 Comments at 25; EEI 2017 Comments at 6.
    \920\ Alliant 2017 Comments at 13-14; AWEA 2017 Comments at 62.
    \921\ Alliant 201 Comments at 13-14.
    \922\ Duke 2017 Comments at 25; EEI 2017 Comments at 69.
    \923\ MISO TOs 2017 Comments at 41.
    \924\ MISO TOs 2017 Comments at 42.
---------------------------------------------------------------------------

    528. EDP argues that changes between wind and solar technologies
should be treated as non-material modifications.\925\ Other commenters
disagree and request that the Commission make clear that permissible
technological advancements exclude changes in generation technology
type.\926\ NextEra argues that an incremental change within the same
technology class, e.g., substituting a newer model of solar panel than
originally planned, is not material.\927\ NYISO states that it opposes
any tariff changes that would consider changes ``to the technology type
that would essentially constitute a new facility as non-material
modifications--e.g., the addition of a battery element to a wind
project or the addition of a solar element to a wind project.'' \928\
NextEra submits that transmission providers should be able to define a
category of permissible technological advancements that will not need
extensive studies.\929\ EEI supports leaving the definition to the
transmission provider's discretion.\930\
---------------------------------------------------------------------------

    \925\ EDP 2017 Comments at 9.
    \926\ EEI 2017 Comments at 71; NYISO Comments at 43.
    \927\ NextEra 2017 Comments at 52.
    \928\ NYISO 2017 Comments at 43.
    \929\ NextEra 2017 Comments at 52.
    \930\ EEI 2017 Comments at 70.
---------------------------------------------------------------------------

    529. EEI requests further clarification of what is meant by
``performance that is equal or better than the electrical performance
expected prior to the technology change.'' \931\ EEI also states that
some material considerations such as electrical characteristics (e.g.,
reactive power), capacity factor, and time of use should be studied
holistically.\932\
---------------------------------------------------------------------------

    \931\ Id.
    \932\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    530. We adopt the NOPR proposal and require transmission providers
to develop a definition of permissible technological advancements that
the interconnection process can accommodate without triggering the
material modification provision of the pro forma LGIP. We are providing
transmission providers with the flexibility to propose a unique
definition for permissible technological advancements in their
compliance filings. Some commenters caution against an overly
prescriptive definition to account for the unpredictability of
technology evolution.\933\ We agree that transmission providers should
have the flexibility to account for the rapid pace of innovation when
developing the definition. The definition must make clear what category
of technological advancements can be accommodated that do not require
extensive or additional studies to determine whether a proposed
technological advancement is a material modification.\934\ As noted in
the NOPR, such permissible changes may include, for example,
advancements to turbines, inverters, plant supervisory controls, or
other technological advancements that may affect a generating
facility's ability to provide ancillary services.\935\ We clarify that
the assessment of whether a technological advancement is permissible is
limited to assessing the materiality of the change and consideration of
whether the transmission provider can accommodate a modification to the
specific technology type initially proposed in the interconnection
request. Although some commenters argue that changes between wind and
solar technologies should be treated as non-material
modifications,\936\ we disagree since such changes involve a change in
the electrical characteristics of an interconnection request, and the
transmission provider would likely need to evaluate the impacts of such
changes. We also agree that the definition of permissible technological
advancements must not include changes in generation technology or fuel
type \937\ (e.g., from gas to wind) because they involve a change in
the electrical characteristics of an interconnection request.
---------------------------------------------------------------------------

    \933\ AWEA 2017 Comments at 62; Alliant 2017 Comments at 13-14;
Duke 2017 Comments at 25; EEI 2017 Comments at 6.
    \934\ See e.g., NextEra 2017 Comments at 52.
    \935\ NOPR, FERC Stats. & Regs. ] 32,719 at P 212.
    \936\ See e.g., EDP 2017 Comments at 9.
    \937\ EEI 2017 Comments at 71; NYISO Comments at 43.
---------------------------------------------------------------------------

    531. MISO TOs request clearer Commission direction to develop
material modification guidelines. They state that RTO/ISO guidelines
should clarify that a change that does not exceed the interconnection
customer's interconnection rights or materially impact short circuit
capability limits, steady-state thermal and voltage limits, or dynamic
system stability and response, is not a material modification.\938\
Responding to comments questioning whether certain technological
advancements can be accommodated without materially affecting other
interconnection customers in the queue as well as EEI's comment as to
what was meant by ``performance that is equal or better than the
electrical performance expected prior to the technology change,'' we
find that a technological advancement that does not increase the
interconnection customer's requested interconnection service or cause
any reliability concerns

(i.e., materially impact the transmission system with regard to short
circuit capability limits, steady-state thermal and voltage limits, or
dynamic system stability and response), is generally not a material
modification. Further, we clarify that technological advancements that
do not degrade the electrical characteristics of the generating
equipment (e.g., the ratings, impedances, efficiencies, capabilities,
and performance of the equipment under steady state and dynamic
conditions) qualify as performance that is ``equal to or better than
the performance expected prior to the change.'' \939\
---------------------------------------------------------------------------

    \938\ MISO TOs 2017 Comments at 42.
    \939\ We note that TDU Systems argue for a similar
interpretation of permissible technological advancement. TDU Systems
2017 Comments at 30-31.
---------------------------------------------------------------------------

d. Timing and Deposits
i. Comments
    532. With regard to timing, EEI supports a 30-day study result
deadline from commencement and a deposit of at least $10,000 per
material modification proposal and clarification that the
interconnection customer is financially responsible for necessary
additional studies.\940\ NYISO supports only allowing modifications
early in the interconnection study process.\941\ EEI requests
clarification on when an interconnection customer should be able to
request the incorporation of advanced technology; it is unsure if the
Commission proposes to allow different technological advancements to
trigger the procedure at different points or a single set of
technological advancements prior to the facilities study agreement's
execution.\942\ It further argues that technology changes without a
change of queue position could result in additional studies and delays,
particularly if the change is material or if the process to study the
technological advancement negatively impacts the overall
interconnection study process.\943\ EEI states that any final action
should provide the flexibility for a transmission provider to evaluate
the impact of a proposed technological advancement, relative to
allowing it in the current study or requiring the generator to reenter
the queue.\944\
---------------------------------------------------------------------------

    \940\ EEI 2017 Comments at 72-73.
    \941\ NYISO 2017 Comments at 44.
    \942\ EEI 2017 Comments at 71.
    \943\ Id. at 71-72.
    \944\ Id. at 72.
---------------------------------------------------------------------------

    533. AWEA supports allowing technological advancements at any point
including after an interconnection agreement is executed and a
generating unit is online.\945\ Generation Developers argue that
transmission providers should have to respond to technological
advancement analyses within 15 days.\946\ Conversely, Bonneville
opposes a specific study completion timeframe, and suggests that a
transmission provider would meet its obligation if it uses reasonable
efforts.\947\
---------------------------------------------------------------------------

    \945\ AWEA 2017 Comments at 62.
    \946\ Generation Developers 2017 Comments at 44.
    \947\ Bonneville 2017 Comments at 11.
---------------------------------------------------------------------------

ii. Commission Determination
    534. We adopt the NOPR proposal to require the interconnection
customer to tender a deposit if the transmission provider determines
that additional studies are needed to evaluate whether a technological
advancement is a material modification. We find that the amount of the
deposit should be specified in the transmission provider's
technological change procedure. Requiring such a deposit is just and
reasonable because a deposit will reimburse the transmission provider
for the time and effort needed to complete the technological
advancement study as well as minimize the submission of frequent and/or
frivolous technological advancement requests. The transmission provider
shall describe for the interconnection customer any costs incurred to
conduct any necessary additional studies, provide its costs to the
interconnection customer, and either refund any overage or charge for
any shortage for costs that exceed the deposit amount. We are setting
the default deposit amount at $10,000. However, to the extent that a
transmission provider considers a $10,000 deposit to be too high or
low, it may propose a reasonable alternative amount in its compliance
filing and include justification supporting this alternative amount. We
agree with EEI that the interconnection customer should bear financial
responsibility for any necessary additional studies that may need to be
performed to determine whether a technological advancement is a
material modification.\948\
---------------------------------------------------------------------------

    \948\ See EEI 2017 Comments at 72-73.
---------------------------------------------------------------------------

    535. Each transmission provider's technological change procedure
must also include the timeframe for the transmission provider to
perform the study it needs to determine whether the proposed
technological advancement is a material modification and return the
results to the interconnection customer. We note that some commenters
suggested a 30-day study result deadline to determine whether a
proposed technological advancement is material.\949\ After
consideration of comments and the record in this proceeding, we believe
that it is appropriate to establish a 30-day study result deadline.
Accordingly, transmission providers must perform and complete any
necessary additional studies as soon as practicable, but no later than
30 days after the interconnection customer submits a formal
technological advancement request to the transmission provider.
Although Bonneville opposes a specific study completion timeframe, and
suggests that a transmission provider would meets its obligation if it
uses reasonable efforts,\950\ we find that, given that the pro forma
LGIP currently contains no requirement for such studies to be completed
within a specified timeframe, a 30-day requirement to determine whether
the proposed technological advancement is a material modification adds
certainty to the interconnection process.
---------------------------------------------------------------------------

    \949\ See, e.g., id.
    \950\ Bonneville 2017 Comments at 11.
---------------------------------------------------------------------------

    536. Regarding the question of when in the process the transmission
provider is no longer required to accommodate technological
advancements, we adopt the NOPR proposal to permit interconnection
customers to submit requests to incorporate technological advancements
prior to the execution of the interconnection facilities study
agreement. In response to commenters that suggest that interconnection
customers should be able to incorporate technological advancements at
any point in the interconnection process without possible loss of queue
position,\951\ we disagree. We believe that we are establishing a
reasonable cut-off point for allowing technological advancements that
will not be considered material modifications given that changes
requested during the facilities study could delay the transmission
provider's ability to tender an interconnection service agreement and,
consequently, delay other projects.\952\ In addition, in response to
EEI's concerns regarding whether the Commission envisions allowing
different technological advancements to trigger the procedure at
different points in the interconnection process, or if the Commission
is proposing to allow one single set of technological advancements
prior to the execution of the interconnection facilities study
agreement, we clarify that interconnection customers must submit

a technological advancement request for any type of technological
advancement in the interconnection process up until execution of the
interconnection facilities study agreement. However, to the extent that
a transmission provider believes that it is appropriate to establish
rules that permit technological advancements only at a single point in
its interconnection process (prior to the execution of the
interconnection facilities study agreement), we permit transmission
providers to propose such a practice in their compliance filings.
---------------------------------------------------------------------------

    \951\ See, e.g., AWEA 2017 Comments at 62 (stating that ``the
technological change procedure should be allowed at any point in the
interconnection process'').
    \952\ PJM 2017 Comments at 30.
---------------------------------------------------------------------------

5. Modeling of Electric Storage Resources for Interconnection Studies
a. NOPR Proposal
    537. The NOPR proposed to require that transmission providers
evaluate their methods for modeling electric storage resources for
interconnection studies, identify whether their current modeling and
study practices adequately and efficiently account for the operational
characteristics of electric storage resources, and explain why and how
their existing practices are or are not sufficient. The Commission also
sought comment on whether establishing a unified model for studying
electric storage resources would expedite the study process and
therefore reduce time and costs expended by transmission providers. The
Commission also asked what information electric storage resources
should provide when submitting interconnection requests that
transmission providers do not already require.
b. Comments
    538. Several commenters support the proposal to require
transmission providers to evaluate their methods for modeling electric
storage resources for interconnection studies.\953\ MISO TOs state that
MISO lacks clear standards for modeling electric storage, and ask that
the Commission convene a workshop or technical conference to allow the
industry to determine best practices.\954\ NEPOOL argues that the NOPR
proposal would improve modeling of storage and facilitate entry of
storage resources into the markets.\955\ Non-Profit Utility Trade
Associations and PJM state that they do not object to the
proposal.\956\
---------------------------------------------------------------------------

    \953\ AFPA 2017 Comments at 17; California Energy Storage
Alliance 2017 Comments at 9-11; Joint Renewable Parties 2017
Comments at 12-13; MISO TOs 2017 Comments at 43; NEPOOL 2017
Comments at 18; NextEra 2017 Comments at 53; Public Interest
Organizations 2017 Comments at 8-9; Indicated NYTOs 2017 Comments at
15.
    \954\ MISO TOs 2017 Comments at 43.
    \955\ NEPOOL 2017 Comments at 18.
    \956\ Non-Profit Utility Trade Associations 2017 Comments at 26;
PJM 2017 Comments at 30.
---------------------------------------------------------------------------

    539. Other commenters support the proposal but ask the Commission
to give transmission providers flexibility to address any necessary
changes.\957\ For example, Indicated NYTOs state that the evaluation of
storage-related interconnection must be conducted in the context of
each regional stakeholder process.\958\ Duke and NYISO take a similar
view. They oppose a unified model for studying electric storage
resources because it could remove a transmission provider's flexibility
to study the various use cases for storage.\959\
---------------------------------------------------------------------------

    \957\ Indicated NYTOs 2017 Comments at 15; ITC 2017 Comments at
20-21; Bonneville 2017 Comments at 11-12.
    \958\ Indicated NYTOs 2017 Comments at 15.
    \959\ Duke 2017 Comments at 25; NYISO 2017 Comments at 45.
---------------------------------------------------------------------------

    540. Public Interest Organizations ask the Commission not to
require all electric storage resources, including electric storage
resources that will serve as a transmission asset, to go through the
formal large generator interconnection process.\960\ Similarly, Schulte
Associates suggests that an energy storage resource should be able to
interconnect as a generator under the LGIP and LGIA and the electric
storage resource should be able to also act as a transmission asset, if
applicable.\961\
---------------------------------------------------------------------------

    \960\ Public Interest Organizations 2017 Comments at 8-9.
    \961\ Schulte Associates 2017 Comments at 4.
---------------------------------------------------------------------------

    541. Other commenters, primarily the RTOs/ISOs, believe current
modeling practices are adequate for the interconnection of electric
storage resources.\962\ ISO-NE and PJM state that their modeling
practices are able to study storage resources when they are either
charging or discharging energy.\963\ NYISO adds that modeling electric
storage resources can be challenging because it depends on the services
the resource wants to provide, but that current modeling approaches are
sufficient as long as the interconnection customer provides accurate
modeling data and validation of such data.\964\ CAISO states that its
stakeholders support CAISO's modeling of electric storage resources'
charging function as ``negative generation'' in lieu of conducting
traditional firm load studies, which some participants and commenters
identified as a best practice during the Commission's 2016 Technical
Conference and in post-technical conference comments.\965\ Idaho Power
asks the Commission to elaborate on the size and capacity of electric
storage resources to be evaluated.\966\
---------------------------------------------------------------------------

    \962\ CAISO 2017 Comments at 36-37; ISO-NE 2017 Comments at 55;
MISO 2017 Comments at 39; NYISO 2017 Comments at 45; PJM 2017
Comments at 31; AVANGRID 2017 Comments at 25.
    \963\ ISO-NE 2017 Comments at 55; PJM 2017 Comments at 31.
    \964\ NYISO 2017 Comments at 45.
    \965\ CAISO 2017 Comments at 37.
    \966\ Idaho Power 2017 Comments at 7.
---------------------------------------------------------------------------

    542. Schulte Associates suggests that electric storage resources
should be able to propose consideration as a transmission asset under
the pro forma LGIP and the pro forma LGIA and that this would require
the RTOs/ISOs to consider the potential benefits and costs to the
transmission system as part of its modeling methods going forward.\967\
ESA, NextEra, TVA, and Xcel support modeling an electric storage
resource based on its intended use,\968\ and MISO and Duke provide
examples of specific information interconnection customers should
provide.\969\
---------------------------------------------------------------------------

    \967\ Schulte Associates 2017 Comments at 4.
    \968\ ESA 2017 Comments at 17-18; NextEra 2017 Comments at 54;
TVA 2017 Comments at 18-19; Xcel 2017 Comment at 23.
    \969\ Duke 2017 Comments at 26-27; MISO 2017 Comments at 39.
---------------------------------------------------------------------------

    543. Some commenters argue that there is a need for clear modeling
guidelines for electric storage resources. MISO and ESA recommend that
the Commission require a consistent means by which transmission
providers and system operators model electric storage charging.\970\
Several commenters support the ``negative generation'' approach
employed in CAISO.\971\
---------------------------------------------------------------------------

    \970\ MISO 2017 Comments at 39; ESA 2017 Comments at 16-17.
    \971\ Id. at 17; NextEra 2017 Comments at 53; PG&E 2017 Comments
at 9.
---------------------------------------------------------------------------

c. Commission Determination
    544. In consideration of the comments, we decline to move forward
with any requirements for modeling electric storage resources in this
final action. We agree with commenters that modeling electric storage
resources as a single asset, as opposed to separate generation and load
assets, and based on their intended use has merits. These approaches
could streamline the interconnection of electric storage resources,
save costs, and avoid modeling the charging of electric storage
resources the same as other unpredictable, non-controllable load
resources. However, given the limited experience interconnecting
electric storage resources and the abundant desire for regional
flexibility, we are not imposing any standard requirements at this time
and instead continue to allow transmission providers to model electric

storage resources in ways that are most appropriate in their respective
regions. Additionally, in response to Schulte Associates, we are not
requiring Transmission Providers to model electric storage resources
serving as transmission assets under the pro forma LGIP and the pro
forma LGIA at this time. Given the flexibility that we are providing,
we find that gathering additional information on potential approaches
for modeling electric storage resources is not necessary at this time,
but we encourage transmission providers to continue to consider
approaches to modeling electric storage resources that will save costs
and improve the efficiency of the interconnection process.

D. Other Issues

1. Whether Proposed Reforms Should Be Applied to Small Generation
a. Comments
    545. In response to the Commission's question in the NOPR,\972\
several commenters suggest that new proposals accepted for the LGIP and
LGIA should also apply to the SGIP and SGIA.\973\ Joint Renewable
Parties also contend that improved transparency would assist small
generators in locating their facilities and moving through the
interconnection process efficiently and cost-effectively.\974\ ESA
supports extending the proposals regarding interconnection service
below facility capacity, surplus interconnection service, provisional
interconnection service, and electric storage modeling to apply to the
pro forma SGIA and SGIP.\975\ California Energy Storage Alliance also
suggests that the Commission consider simplified procedures for
interconnecting distributed electric storage resources that desire to
participate in wholesale markets, either as a standalone resources or
as part of an aggregation.\976\ TVA states that the small generator
interconnection process could benefit from the proposed reforms and
discussions involving affected system studies and any guidelines for
modeling and evaluating electric storage resources.\977\
---------------------------------------------------------------------------

    \972\ NOPR, FERC Stats. & Regs. ] 32,719 at P 11.
    \973\ California Energy Storage Alliance 2017 Comments at 11;
Joint Renewable Parties 2017 Comments at 3; ISO-NE 2017 Comments at
56.
    \974\ Joint Renewable Parties 2017 Comments at 11.
    \975\ ESA 2017 Comments at 18.
    \976\ California Energy Storage Alliance 2017 Comments at 11-13.
    \977\ TVA 2017 Comments at 19.
---------------------------------------------------------------------------

    546. Others argue that the proposed reforms should not apply to
small generating facilities.\978\ Duke, for instance, argues that the
SGIP and SGIA processes are designed to be streamlined and that states
use the processes as the bases for state small generator
interconnection processes.\979\ Modesto asserts that, if the Commission
believes it should make comparable revisions to the SGIP and SGIA, such
revisions should be subject to appropriate notice and comment
rulemaking procedures.\980\ Xcel states that if the Commission wishes
to pursue this possibility, it should initiate a notice of
inquiry.\981\
---------------------------------------------------------------------------

    \978\ Duke 2017 Comments at 3-4; Modesto 2017 Comments at 22;
SoCal Edison 2017 Comments at 2; Xcel 2017 Comments at 5; see also
Imperial 2017 Comments 20-21.
    \979\ Duke 2017 Comments at 3-4.
    \980\ Modesto April 2017 Comments at 22; Xcel 2017 Comments at
5.
    \981\ Id.
---------------------------------------------------------------------------

    547. PG&E and SoCal Edison ask the Commission to confirm that the
NOPR does not require changes to PG&E's wholesale distribution access
tariff and GIPs, which primarily concern SGIAs.\982\ PG&E states that
the administrative burden and costs of doing so outweighs the
benefits.\983\ PG&E states that, as explained in section 2.13 of the
wholesale distribution access tariff, such interconnection facilities
are considered distribution facilities for purposes of the wholesale
distribution access tariff.\984\
---------------------------------------------------------------------------

    \982\ PG&E 2017 Comments at 2; SoCal Edison 2017 Comments at 1-
2.
    \983\ PG&E 2017 Comments at 2.
    \984\ Id. (citing Pac. Gas & Elec. Co., 77 FERC ] 61,077 (1996);
see also SoCal Edison 2017 Comments at 1-2.
---------------------------------------------------------------------------

b. Commission Determination
    548. We decline to make the new requirements from this final action
applicable to the pro forma SGIP and the pro forma SGIA. Although the
Commission sought comment on whether any of the proposed reforms should
be applied to small generating facilities and implemented in the pro
forma SGIP and pro forma SGIA, the Commission did not make any specific
proposals as to the pro forma SGIP or pro forma SGIA. We also note that
the majority of responsive commenters oppose such a change.\985\
---------------------------------------------------------------------------

    \985\ Duke 2017 Comments at 3-4; Modesto 2017 Comments at 22;
SoCal Edison 2017 Comments at 2; Xcel 2017 Comments at 5; see also
Imperial 2017 Comments 20-21.
---------------------------------------------------------------------------

    549. In response to the parties that support adopting the final
action reforms for small generators, we find that, while some of these
reforms have the potential to aid small generator interconnection, the
differences between the large and small interconnection processes are
significant enough to prevent us from acting in this proceeding.
2. Issues Not Raised in the NOPR
a. Comments
    550. Multiple commenters have commented on issues not raised in the
NOPR. For instance, Joint Renewable Partners argue that the Commission
has allowed the states to continue to administer Qualifying Facility
(QF) interconnections where the QF sells the entire net output to the
interconnecting utility, which has resulted in less favorable
interconnection practices for QFs.\986\ Additionally, IECA urges the
Commission to alter the QF minimum export threshold to be based on
``total energy'' exported to the grid and not on net system capacity
because the current system discriminates against combined heat and
power and waste heat recovery facilities in favor of other types of
facilities.\987\
---------------------------------------------------------------------------

    \986\ Joint Renewable Parties 2017 Comments at 13-15.
    \987\ IECA 2017 Comments at 3.
---------------------------------------------------------------------------

    Forecasting Coalition states that rates for interconnection service
will decrease, and reliability will increase, if LGIPs require
transmission providers to consider non-transmission alternatives,
including dynamic line ratings.\988\ First Solar states that there is
also significant misalignment in CAISO's deliverability allocation
procedures where upgrade cost caps deprive generators of the ability to
deliver a plant's full output, which can prevent interconnection
customers from competing in solicitations or force them to withdraw
from the queue.\989\ Invenergy argues that the Commission should update
pro forma LGIA article 5.17 to incorporate recent changes in the
Internal Revenue Service safe harbor rules.\990\ CAISO, Xcel, and
Southern express views that the Commission move away from a first-come,
first-served standard to a first-ready, first-served standard.\991\
---------------------------------------------------------------------------

    \988\ Forecasting Coalition 2017 Comments at 1.
    \989\ First Solar 2017 Comments at 1.
    \990\ Invenergy 2017 comments at 16.
    \991\ CAISO 2017 Comments at 38-39; Xcel 2017 Comments at 6-7;
Southern 2017 Comments at 6.
---------------------------------------------------------------------------

b. Commission Determination
    551. We consider the comments summarized in the above section to be
outside the scope of this proceeding. The NOPR proposed a number of
specific reforms, to which commenters have reacted. The comments
discussed in the above section have raised issues unrelated to the
NOPR's proposed reforms. Even if we were inclined to agree with the
proposals made in these comments, we would not adopt them

here given the inadequacy of the record on such proposals.
3. Process Considerations
a. Comments
    552. Duke recommends that any new information required to be posted
on OASIS be permitted to be posted without requiring new templates to
be created through the NAESB process.\992\ OATI states that if the
final action requires new informational postings by transmission
providers, the Commission should direct the nature and standards for
those postings to NAESB.\993\ OATI states that access to any additional
postings made on a transmission provider's OASIS site requires secure
and controlled access. OATI asks the Commission to assess the impact of
new information on OASIS to decide if OASIS is the appropriate location
for additional information and, if so, determine how currently
available information on OASIS is accessed, and what would be necessary
to post additional information.\994\
---------------------------------------------------------------------------

    \992\ Duke 2017 Comments at 28.
    \993\ OATI 2017 Comments at 1-2.
    \994\ Id. at 7.
---------------------------------------------------------------------------

b. Commission Determination
    553. We decline to specifically require that transmission providers
work through NAESB for the development of templates or standards for
any OASIS postings they make in compliance with this final action.
Transmission providers may coordinate as they determine appropriate to
implement the Commission's requirements and to develop relevant posting
protocols. Additionally, we note that, in this final action, we adopt
OASIS requirements for the ``Transparency Regarding Study Models and
Assumptions'' and ``Interconnection Study Deadlines'' sections.
Additionally, in the ``Transparency Regarding Study Models and
Assumptions'' and ``Interconnection Study Deadlines'' adopted
requirements, we allow transmission providers to only include a link on
OASIS to the information required if it is posted on the transmission
provider's website.
4. Compliance and Implementation
a. Comments
    554. EEI, Duke, ITC, MISO TOs, and Xcel request that the Commission
allow 180 days for compliance with any final action.\995\ Duke and ITC
also request a date of one year after the final action for
implementation of the revised OATTs included in the compliance
filings.\996\
---------------------------------------------------------------------------

    \995\ EEI 2017 Comments at 77; Duke 2017 Comments at 28; ITC
2017 Comments at 21; MISO TOs 2017 Comments at 44; Xcel 2017
Comments at 23.
    \996\ Duke 2017 Comments at 28; ITC 2017 Comments at 21.
---------------------------------------------------------------------------

b. Commission Determination
    555. Section 35.28(f)(1) of the Commission's regulations requires
every public utility with a non-discriminatory OATT on file to also
have on file the pro forma LGIP and pro forma LGIA ``required by
Commission rulemaking proceedings promulgating and amending'' such
agreements. Despite the comments described above, we see no reason to
delay the effective date or extend the compliance deadline of this
final action. Therefore, the Commission is requiring all public utility
transmission providers to submit compliance filings to adopt the
requirements of this final action as revisions to the LGIP and LGIA in
their OATTs no later than 90 days after the issuance of this final
action in the Federal Register.\997\
---------------------------------------------------------------------------

    \997\ NOPR, FERC Stats. & Regs. ] 32,719 at P 231.
---------------------------------------------------------------------------

    556. Some public utility transmission providers may have provisions
in their existing LGIPs or LGIAs subject to the Commission's
jurisdiction that the Commission has deemed to be consistent with or
superior to the pro forma LGIP or pro forma LGIA or permissible under
the independent entity variation standard or regional reliability
standard.\998\ Where these provisions are modified by this final
action, public utility transmission providers must either comply with
this final action or demonstrate that these previously-approved
variations continue to be consistent with or superior to the pro forma
LGIP and pro forma LGIA as modified by this final action or continue to
be permissible under the independent entity variation standard or
regional reliability standard.\999\ We also find that transmission
providers that are not public utilities must adopt the requirements of
this final action as a condition of maintaining the status of their
safe harbor tariff or otherwise satisfying the reciprocity requirement
of Order No. 888.\1000\
---------------------------------------------------------------------------

    \998\ See Order No. 792, 145 FERC ] 61,159 at P 270.
    \999\ See 18 CFR 35.28(f)(1)(i) (2017).
    \1000\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------

V. Information Collection Statement

    557. The collection of information contained in this final action
is being submitted to the Office of Management and Budget (OMB) for
review under section 3507(d) of the Paperwork Reduction Act of
1995.\1001\ OMB's regulations,\1002\ in turn, require approval of
certain information collection requirements imposed by agency rules.
Upon approval of a collection(s) of information, OMB will assign an OMB
control number and an expiration date. Respondents subject to the
filing requirements of a rule will not be penalized for failing to
respond to the collection of information unless the collection of
information displays a valid OMB control number.
---------------------------------------------------------------------------

    \1001\ See 44 U.S.C. 3507(d) (2012).
    \1002\ 5 CFR part 1320 (2017).
---------------------------------------------------------------------------

    558. The reforms adopted in this final action revise the
Commission's pro forma LGIP and pro forma LGIA. This final action
requires each public utility transmission provider to amend its LGIP
and LGIA to: (1) Remove the limitation that interconnection customers
may only exercise the option to build transmission provider's
interconnection facilities and stand alone network upgrades in
instances when the transmission owner cannot meet the dates proposed by
the interconnection customer; (2) require that transmission providers
establish interconnection dispute resolution procedures that would
allow a disputing party to unilaterally seek non-binding dispute
resolution; (3) require transmission providers to outline and make
public a method for determining contingent facilities; (4) require
transmission providers to list the specific study processes and
assumptions for forming the network models used for interconnection
studies; (5) revise the definition of ``Generating Facility'' to
explicitly include electric storage resources; (6) establish reporting
requirements for aggregate interconnection study performance; (7) allow
interconnection customers to request a level of interconnection service
that is lower than their generating facility capacity; (8) require
transmission providers to allow for provisional interconnection
agreements that provide for limited operation prior to completion of
the full interconnection process; (9) require transmission providers to
create a process for interconnection customers to use surplus
interconnection service at existing points of interconnection; and (10)
require transmission providers to set forth a procedure to allow
transmission providers to assess and, if necessary, study an
interconnection customer's technology changes without affecting the
interconnection customer's queued position. The reforms adopted in this
final action require revised filings of LGIPs and LGIAs with the

Commission. The Commission anticipates the revisions required by this
final action, once implemented, will not significantly change currently
existing burdens on an ongoing basis. With regard to those public
utility transmission providers that believe they already comply with
the revisions adopted in this final action, they can demonstrate their
compliance in the filing required 90 days after the issuance of this
final action in the Federal Register. The Commission will submit the
proposed reporting requirements to OMB for its review and approval
under section 3507(d) of the Paperwork Reduction Act.\1003\
---------------------------------------------------------------------------

    \1003\ 44 U.S.C. 3507(d) (2012).
---------------------------------------------------------------------------

    559. While the Commission expects the revisions adopted in this
final action will provide significant benefits, the Commission
understands that implementation can be a complex and costly endeavor.
The Commission solicited comments on the accuracy of the provided
burden and cost estimates and any suggest methods for minimizing the
respondents' burdens. The Commission did not receive any comments
concerning its burden or cost estimates. However, the Commission has
made changes to its NOPR proposals that are adopted in this final
action. First, the Commission has withdrawn the proposals regarding
scheduled periodic restudies, self-funding by the transmission owner,
and modeling of electric storage resources. Second, the Commission has
modified the dispute resolution requirements so that they will apply
both inside and outside RTOs/ISOs. Therefore, we have adjusted the
burden estimate accordingly.
    Burden Estimate and Information Collection Costs: The Commission
believes that the burden estimates below are representative of the
average burden on respondents. The estimated burden and cost \1004\ for
the requirements contained in this final action follow.
---------------------------------------------------------------------------

    \1004\ The estimated hourly cost (salary plus benefits) provided
in this section is based on the salary figures for May 2016 posted
by the Bureau of Labor Statistics for the Utilities sector
(available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000)
and scaled to reflect benefits using the relative importance of
employer costs in employee compensation from June 2016 (available at
https://www.bls.gov/oes/current/naics2_22.htm). The hourly estimates
for salary plus benefits are:
    Auditing and accounting (code 13-2011), $53.00.
    Computer and Information Systems Manager (code 11-3021),
$100.68.
    Computer and mathematical (code 15-0000), $60.70.
    Economist (code 19-3011), $77.96.
    Electrical Engineer (code 17-2071), $68.12.
    Information and record clerk (code 43-4199), $39.14.
    Information Security Analyst (code 15-1122), $66.34.
    Legal (code 23-0000), $143.68.
    Management (code 11-0000), $81.52.
    The average hourly cost (salary plus benefits), weighting all of
these skill sets evenly, is $76.79. The Commission rounds it to $77
per hour.

                                                    FERC 516F
----------------------------------------------------------------------------------------------------------------
                                Number of                                                          Total annual
                                applicable  Annual number of   Total number of   Average burden   burden hours &
                                registered    responses per       responses     (hours) & costs    total annual
                                 entities      respondent                         per response         cost
                                       (1)  (2).............  (1) * (2) = (3).  (4)............  (3) * (4) = (5)
----------------------------------------------------------------------------------------------------------------
Issue A1--Scheduled periodic           126  N/A.............  N/A.............  N/A............  N/A.
 restudies \1005\.                       6  N/A.............  N/A.............  N/A............  N/A.
Issue A2--Interconnection              126  1 (Year 1); 0     126 (Year 1); 0   4 hrs. (Year     504 hrs. (Year
 customer's option to build                  (Ongoing)         (Ongoing).        1); $308.        1); $38,808.
 (Non-RTO/ISO).                              \1006\.                            0 hrs.           0 hrs.
                                                                                (Ongoing); $0.   (Ongoing); $0.
Issue A2--Interconnection                6  1 (Year 1); 0     6 (Year 1); 0     4 hrs. (Year     24 hrs. (Year
 customer's option to build                  (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
 (RTO/ISO).                                                                     0 hrs.           0 (Ongoing); $0
                                                                                (Ongoing); $0.
Issue A3--Self-funding by the          126  N/A.............  N/A.............  N/A............  N/A.
 transmission owner \1007\
 (Non-RTO/ISO).
Issue A3--Self-funding by the            6  N/A.............  N/A.............  N/A............  N/A.
 transmission owner (RTO/ISO).
Issue A4--RTO/ISO dispute              126  1 (Year 1); 0     126 (Year 1); 0   4 hrs. (Year     504 hrs. (Year
 resolution (Non-RTO/ISO).                   (Ongoing).        (Ongoing).        1); $308.        1); $38,808.
                                                                                0 hrs.           0 hrs.
                                                                                (Ongoing).       (Ongoing); $0.
Issue A4--RTO/ISO dispute                6  1 (Year 1); 0     6 (Year 1); 0     4 hrs. (Year     24 hrs. (Year
 resolution (RTO/ISO).                       (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
                                                                                0 hrs.           0 (Ongoing) $0.
                                                                                (Ongoing).
Issue A5--Capping costs for            126  N/A.............  N/A.............  N/A............  N/A.
 network upgrades \1008\ (Non-
 RTO/ISO).
Issue A5--Capping costs for              6  N/A.............  N/A.............  N/A............  N/A.
 network upgrades (RTO/ISO).
Issue B1--Identification and           126  1 (Year 1); 0     126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 definition of contingent                    (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 facilities (Non-RTO/ISO).                                                      0 hrs.;           $776,160.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue B1--Identification and             6  1 (Year 1); 0     6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 definition of contingent                    (Ongoing).        (Ongoing).        1); $6,160.      1);
 facilities (RTO/ISO).                                                          0 hrs.;          $36,960.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue B2--Transparency in the          126  1 (Year 1); 0     126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 interconnection process (Non-               (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 RTO/ISO).                                                                      0 hrs.;           $776,160.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue B2--Transparency in the            6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 interconnection process (RTO/               (Ongoing).        (Ongoing).        1); $6,160.      1);
 ISO).                                                                          0 hrs.;          $36,960.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue B3--Curtailment                  126  N/A.............  N/A.............  N/A............  N/A.
 concerns (Non-RTO/ISO).
Issue B3--Curtailment                    6  N/A.............  N/A.............  N/A............  N/A.
 concerns (RTO/ISO).
Issue B4--Definition of                126  1 (Year 1); 0     126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 generating facility (non-RTO/               (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 ISO).                                                                          0 hrs.;           $776,160.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue B4--Definition of                  6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 generating facility (RTO/                   (Ongoing).        (Ongoing).        1); $6,160.      1);
 ISO).                                                                          0 hrs.;          $36,960.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.

Issue B5--Interconnection              126  1 (Year 1); 4     126 (Year 1);     4 hrs. (Year     504 hrs. (Year
 study deadlines (non-RTO/                   (Ongoing).        504 (Ongoing).    1); $308.        1); $38,808.
 ISO).                                                                          4 hrs.           2,016 hrs.
                                                                                (Ongoing) $308.  (Ongoing);
                                                                                $155,232.
Issue B5--Interconnection                6  1 (Year 1) 4      6 (Year 1); 24    4 hrs. (Year     24 hrs. (Year
 study deadlines (RTO/ISO).                  (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
                                                                                4 hrs.           96 hrs.
                                                                                (Ongoing);       (Ongoing);
                                                                                $308.            7,392.
Issue B6--Improving                    126  N/A.............  N/A.............  N/A............  N/A.
 Coordination of Affected
 Systems \1009\ (non-RTO/ISO).
Issue B6--Improving                      6  N/A.............  N/A.............  N/A............  N/A.
 Coordination of Affected
 Systems (RTO/ISO).
Issue C1--Requesting                   126  1 (Year 1) 0      126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 interconnection service                     (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 below generating facility                                                      0 hrs.;           $776,160.
 capacity (Non-RTO/ISO).                                                         (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue C1--Requesting                     6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 interconnection service                     (Ongoing).        (Ongoing).        1); $6,160.      1);
 below generating facility                                                      0 hrs.;          $36,960.
 capacity (RTO/ISO).                                                             (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue C2--Provisional                  126  1 (Year 1) 0      126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 agreements (non-RTO/ISO).                   (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
                                                                                0 hrs.;           $776,160.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue C2--Provisional                    6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 agreements (RTO/ISO).                       (Ongoing).        (Ongoing).        1); $6,160.      1);
                                                                                0 hrs.;          $36,960.
                                                                                (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue C3--Utilization of               126  1 (Year 1) 0      126 (Year 1); 0   4 hrs. (Year     504 hrs. (Year
 surplus interconnection                     (Ongoing).        (Ongoing).        1); $308.        1); $38,808.
 service (non-RTO/ISO).                                                         0 hrs.           0 hrs.
                                                                                (Ongoing) $0.    (Ongoing); $0.
Issue C3--Utilization of                 6  1 (Year 1) 0      6 (Year 1); 0     4 hrs. (Year     24 hrs. (Year
 surplus interconnection                     (Ongoing).        (Ongoing).        1); $308.        1); $1,848.
 service (RTO/ISO).                                                             0 hrs.           0 (Ongoing) $0.
                                                                                (Ongoing) $0.
Issue C4--Material                     126  1 (Year 1) 0      126 (Year 1); 0   80 hrs. (Year    10,080 hrs.
 modification and                            (Ongoing).        (Ongoing).        1); $6,160.      (Year 1);
 incorporation of advanced                                                      0 hrs.;           $776,160.
 technologies (non-RTO/ISO).                                                     (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue C4--Material                       6  1 (Year 1) 0      6 (Year 1); 0     80 hrs. (Year    480 hrs. (Year
 modification and                            (Ongoing).        (Ongoing).        1); $6,160.      1);
 incorporation of advanced                                                      0 hrs.;          $36,960.
 technologies (RTO/ISO).                                                         (Ongoing); $0.  0 hrs.
                                                                                (Ongoing); $0.
Issue C5--Modeling of                  126  N/A.............  N/A.............  N/A............  N/A.
 electric storage resources
 \1010\ (non-RTO/ISO).
Issue C5--Modeling of                    6  N/A.............  N/A.............  N/A............  N/A.
 electric storage resources
 (RTO/ISO).
----------------------------------------------------------------------------------------------------------------
    Total....................       Non-RTO/ISO, Year 1       1,260...........  62,244 hrs.; $4,792,788
                                    Non-RTO/ISO, Ongoing      504.............  2,016 hrs.; $155,232
                                      RTO/ISO, Year 1         60..............  2,976 hrs.; $229,152
                                      RTO/ISO, Ongoing        24..............  96 hrs.; $7,392
----------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the cost of compliance
as follows:
---------------------------------------------------------------------------

    \1005\ There are no estimates for this section, because the
Commission has withdrawn the NOPR proposal.
    \1006\ Ongoing refers to Year 2 and ongoing.
    \1007\ There are no estimates for this section, because the
Commission has withdrawn the NOPR proposal.
    \1008\ There are no estimates for this issue, because the NOPR
did not propose, and the final action did adopt, any requirements
for this issue.
    \1009\ There are no estimates for this issue, because the NOPR
did not propose, and the final action did adopt, any requirements
for this issue.
    \1010\ There are no estimates for this section, because the
Commission has withdrawn the NOPR proposal.

 Year 1: $5,021,940
 Ongoing: $162,624

    Year 1 costs reflect costs to comply with the final action. Year 2
represents ongoing costs that the transmission provider will face on an
ongoing basis to fulfill the directives of this final action. The
reforms adopted in this final action, once implemented, would not
significantly change existing burdens on an ongoing basis.
    The one-time burden of 65,220 hours will be averaged over three
years (65,220 / 3 = 21,740 hours/year over three years).
    The ongoing burden of 2,112 hours applies to only Year 2 and
beyond.
    The number of responses is also averaged over three years (1,320
responses (one-time) + 528 responses (Year 2) + 528 responses (Year 3))
/ 3 = 792 responses/year.
    The responses and burden for Years 1-3 will total respectively as
follows:
    Year 1: 792 responses; 21,740 hours.
    Year 2: 792 responses; 21,740 hours + 2,112 hours + 2,112 hours =
25,964 hours.
    Year 3: 792 responses; 21,740 hours + 2,112 hours + 2,112 hours =
25,964 hours.
    Title: FERC-516F, Electric Rate Schedules and Tariff Filings.
    Action: Proposed information collection.
    OMB Control No.: TBD.
    Respondents for Proposal: Businesses or other for profit and/or
not-for-profit institutions.
    Frequency of Information: One-time during Year 1. Multiple times
during subsequent years.
    Necessity of Information: The Commission issues this final action
to address interconnection practices that may be resulting in unjust
and unreasonable or unduly discriminatory or preferential rates, terms,
and conditions. The reforms are designed to improve certainty in the
interconnection process, to promote more informed

interconnection decisions by interconnection customers, and to enhance
interconnection processes.
    Internal Review: The Commission has reviewed the proposed changes
and has determined that such changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has specific, objective support for the burden estimates
associated with the information collection requirements.
    560. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen
Brown, Office of the Executive Director], email:
[email protected], phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
    561. Comments concerning the collection of information and the
associated burden estimate(s) in the final action should be sent to the
Commission in this docket and may also be sent to the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW, Washington, DC 20503 [Attention: Desk Officer for
the Federal Energy Regulatory Commission].
    562. Due to security concerns, comments should be sent
electronically to the following email address:
[email protected]. Comments submitted to OMB should refer to
FERC-516F and OMB Control No. to be determined.

VI. Environmental Analysis

    563. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\1011\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this final action under
Sec.  380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts, and regulations that affect rates, charges, classification,
and services.\1012\
---------------------------------------------------------------------------

    \1011\ Regulation Implementing National Environmental Policy Act
of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \1012\ 18 CFR 380.4(a)(15) (2017).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    564. The Regulatory Flexibility Act of 1980 (RFA) \1013\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA
mandates consideration of regulatory alternatives that accomplish the
stated objectives of a rule and that minimize any significant economic
impact on a substantial number of small entities. The Small Business
Administration's (SBA) Office of Size Standards develops the numerical
definition of a small business.\1014\ The small business size standards
are provided in 13 CFR 121.201.
---------------------------------------------------------------------------

    \1013\ 5 U.S.C. 601-12 (2012).
    \1014\ 13 CFR 121.101 (2017) Sector 22 (Utilities), NAICS code
22121 (Electric Power Transmission and Control).
---------------------------------------------------------------------------

    565. The Commission estimates that the total number of public
utility transmission providers that would have to modify the LGIPs and
LGIAs within their currently effective OATTs is 132. Of these, the
Commission estimates that approximately 43 percent are small entities
(approximately 57 entities). The Commission estimates the average total
cost to each of these entities will require on average 494 hours or
$38,045 in Year 1,\1015\ and 16 hours or $1,232 in subsequent
years.\1016\ According to SBA guidance, the determination of
significance of impact ``should be seen as relative to the size of the
business, the size of the competitor's business, and the impact the
regulation has on larger competitors.'' \1017\ The Commission does not
consider the estimated burden to be a significant economic impact. As a
result, the Commission certifies that the revisions adopted in this
final action will not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------

    \1015\ 65,220 hours / 132 = 494 hours/respondent; $5,021,940 /
132 = $38,045/respondent.
    \1016\ 2,112 hours / 132 = 16 hours/respondent; $162,624 / 132 =
$1,232/respondent.
    \1017\ U.S. Small Business Administration, A Guide for
Government Agencies: How to Comply with the Regulatory Flexibility
Act, at 18 (August 2017), https://www.sba.gov/sites/default/files/advocacy/How-to-Comply-with-the-RFA-WEB.pdf.
---------------------------------------------------------------------------

VIII. Document Availability

    566. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE, Room 2A,
Washington, DC 20426.
    567. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number of this document, excluding the last three digits, in
the docket number field.
    568. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
[email protected].

IX. Effective Date and Congressional Notification

    569. The final action is effective July 23, 2018. The Commission
has determined with the concurrence of the Administrator of the Office
of Information and Regulatory Affairs of OMB that this action is not a
``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996. This final action is being
submitted to the U.S. Senate, the U.S. House of Representatives, and
the U.S. Government Accountability Office.

List of Subjects in 18 CFR Part 37

    Conflicts of interest, Electric power plants, Electric utilities,
Reporting and recordkeeping requirements.

    By the Commission.

    Issued: April 19, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2018-08659 Filed 5-8-18; 8:45 am]
 BILLING CODE 6717-01-P