Commission's proposal.\424\ AWEA further states that it does not oppose
the addition of the proposed primary frequency response capability
requirement to interconnection standards for new non-synchronous
generators, and that the proposed deadband and response rates for
capability settings of maximum 5 percent droop and 0.036 Hz
deadband appear reasonable and consistent with industry practice.\425\
---------------------------------------------------------------------------

    \424\ AWEA Comments at 4.
    \425\ Id. at 4-5.
---------------------------------------------------------------------------

    206. However, Sunflower and Mid-Kansas contend that, given current
adequate frequency response performance and a lack of sufficient data
in the record on the extent to which primary frequency response is
needed from wind generating facilities, the Commission should not adopt
a blanket requirement that includes wind generating facilities at this
time. Sunflower and Mid-Kansas assert that the Commission should
instead proceed with further analysis first, as contemplated by NERC,
or at least allow for flexibility in the requirements.\426\
---------------------------------------------------------------------------

    \426\ Sunflower and Mid-Kansas Comments at 4.
---------------------------------------------------------------------------

c. Commission Determination
    207. We are not persuaded by Sunflower and Mid-Kansas to exempt
wind generating facilities from the primary frequency response

requirements of this final action. As discussed above, a key focus of
this final action is the ongoing shift of the generation resource mix,
with declining amounts of traditional synchronous generating facilities
that historically have provided primary frequency response and
increasing penetrations of non-synchronous generation, including wind
generating facilities that historically have not been a significant
source of primary frequency response. Unlike certain CHP or nuclear
generating facilities, the record does not indicate that there is an
economic, technical, or regulatory basis for a generic exemption for
newly interconnecting wind generating facilities. In particular, we are
persuaded by AWEA's assertion that the proposed primary frequency
response capability requirements can be met at low cost for new wind
projects, and that newly interconnecting wind facilities should not
have difficulty complying with the proposed deadband of 0.036 Hz and a maximum 5 percent droop parameter.\427\
Accordingly, we will not exempt wind generating facilities from the
requirements of this final action.
---------------------------------------------------------------------------

    \427\ AWEA Comments at 4.
---------------------------------------------------------------------------

6. Surplus Interconnection
a. NOPR Proposal
    208. In the NOPR, the Commission did not propose any provisions
related to surplus interconnection service.\428\
---------------------------------------------------------------------------

    \428\ See Reform of Generator Interconnection Procedures and
Agreements, Notice of Proposed Rulemaking, 82 FR 4464 (Jan. 13,
2017), 157 FERC ] 61,212 (2016). Surplus interconnection service
refers to an instance where an interconnection customer has an
interconnection agreement which provides more interconnection
service than it currently uses, and may wish to add resources, such
as electric storage resources, which were not planned with part of
the original interconnection request, or it may wish to sell surplus
interconnection service without conveying the originally planned
generating facility as part of the sale.
---------------------------------------------------------------------------

b. Comments
    209. ESA states that the Commission recently issued a NOPR which
proposes to make available the use of surplus interconnection service,
which is intended to maximize the use of existing interconnection
service capacity and concerns generating facilities that are existing
interconnection customers.\429\ ESA contends that these forms of
interconnections should not be considered ``new interconnection'' for
the purposes of primary frequency response capability requirements, and
requests that the Commission exempt surplus interconnection services
from its proposed primary frequency response requirements.\430\
---------------------------------------------------------------------------

    \429\ ESA Comments at 5.
    \430\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    210. We find that ESA's request that surplus interconnection
service should not be considered ``new interconnection'' for purposes
of this final action is premature, because the Commission has yet to
issue any final action that addresses surplus interconnection
service.\431\
---------------------------------------------------------------------------

    \431\ We further note that MISO's Net Zero Interconnection
Service is an interconnection request that results in a GIA. As
such, a generator connecting to the transmission system using Net
Zero Interconnection Service would be expected to comply with this
final action. See MISO Tariff Attachment X <IP_ADDRESS> (Additional
Requirements for a Net Zero Interconnection Request application).
---------------------------------------------------------------------------

7. Small Generating Facilities
a. NOPR Proposal
    211. In the NOPR, the Commission proposed to apply the proposed
requirements to newly interconnecting small generating facilities. The
Commission stated that the record suggests that small generating
facilities are capable of installing and enabling governors at low cost
in a manner comparable to large generating facilities.\432\ The
Commission concluded that given recent technological advances, the
Commission did not anticipate that requiring the pro forma SGIA to be
amended to include requirements for primary frequency response
capability would present a barrier for small generating facilities,
and, given the need for additional primary frequency response
capability and an increasingly large market penetration of small
generating facilities, the Commission believed that there is a need to
add these requirements to the pro forma SGIA to help ensure primary
frequency response capability. In support, the Commission referenced
PJM's recent changes to its interconnection agreements to require new
large and small non-synchronous generating facilities to install
enhanced inverters, which include primary frequency response capability
requirements.\433\
---------------------------------------------------------------------------

    \432\ NOPR, 157 FERC ] 61,122 at P 41 (citing IEEE-P1547 Working
Group NOI Comments at 1, 5, and 7).
    \433\ Id. P 42.
---------------------------------------------------------------------------

b. Comments
i. NOPR Comments
    212. Most commenters who generally supported the NOPR's proposal
did not differentiate between small and large generators. APPA et al.
contends applying the primary frequency response requirement to all
generators is important, particularly given that non-synchronous
generators and small generators are making up a growing share of the
changing generation resource mix.\434\ EEI states that it supports the
Commission acting to remove inconsistencies between the pro forma LGIA
and the pro forma SGIA because there is no economical or technical
basis for treating large and small generating facilities differently
when they are both capable of installing and enabling governors at
comparable costs.\435\
---------------------------------------------------------------------------

    \434\ APPA et al. Comments at 5.
    \435\ EEI Comments at 8.
---------------------------------------------------------------------------

    213. Some commenters,\436\ however, raise concerns that small
generating facilities could face disproportionate costs to install
primary frequency response capability. For example, the Public Interest
Organizations argue that the Commission's discussion of the economic
impact on small generating facilities of installing primary frequency
response capability is limited, and claimed the cited evidence in the
NOPR does not directly support the Commission's conclusion that ``small
generating facilities are capable of installing and enabling governors
at low cost in a manner comparable to large generating facilities.''
\437\ In support of their position, Public Interest Organizations note
SolarCity Corporation's concern that ``a requirement that all
generating facilities have frequency response capability may cost more
for some resources, including behind-the-meter and distributed energy
resources.'' \438\ Public Interest Organizations state that they
therefore encourage the Commission to further investigate the cost for
small renewable energy generating facilities to install frequency
response capability before making the proposed revisions to the pro
forma SGIA.\439\
---------------------------------------------------------------------------

    \436\ See NRECA Comments at 8; Public Interest Organizations
Comments at 3; TVA Comments at 4; Idaho Power Comments at 2.
    \437\ Public Interest Organizations Comments at 3 (citing NOPR,
157 FERC ] 61,122 at P 42).
    \438\ Id. at 3 (citing SolarCity Corporation's NOI Comments at
4).
    \439\ Id. at 3-4.
---------------------------------------------------------------------------

    214. Other commenters request the Commission adopt a size
limitation for applying the NOPR requirements. For example, TVA
requests an exemption for generating facilities under 5 MVA as long as
they do not aggregate with facilities greater than 75 MVA or connect to
the grid at 100 kV or above.\440\ Similarly, Idaho Power and NRECA
request that the Commission consider exempting generating facilities

that are smaller than 10 MW. Idaho Power states that it would be
difficult to determine compliance if the required response is too
small.\441\ NRECA suggests that small generating facilities might have
a different cost-benefit analysis than large generating facilities, and
asserts that there is not a sufficient record to conclude that the
proposed requirement to install primary frequency response capability
will not pose an undue burden on smaller generating facilities.\442\
---------------------------------------------------------------------------

    \440\ TVA Comments at 4.
    \441\ Idaho Power Comments at 2.
    \442\ NRECA Comments at 8.
---------------------------------------------------------------------------

ii. Supplemental Comments
    215. NAGF, Tri-State, ISO-RTO Council, SoCal Edison, and WIRAB
support applying the proposed requirements to small generating
facilities.\443\ ISO-RTO Council states that the proposed requirements
are consistent with the current requirements of PJM, NYISO, ISO-NE, and
CAISO, all of which require small generators to install, maintain, and
operate equipment capable of providing primary frequency response as a
condition of interconnection.\444\ ISO-RTO Council contends that these
requirements have been in place for several years, have not resulted in
operational issues or challenges associated with such requirements, and
have not required exemptions for small generators.\445\
---------------------------------------------------------------------------

    \443\ NAGF Supplemental Comments at 2; Tri-State Supplemental
Comments at 3; ISO-RTO Council Supplemental Comments at 6; SoCal
Edison Supplemental Comments at 2; WIRAB Supplemental Comments at 7.
    \444\ ISO-RTO Supplemental Comments at 3.
    \445\ ISO-RTO Council Supplemental Comments at 4.
---------------------------------------------------------------------------

    216. Further, ISO-RTO Council asserts that ``providing an exemption
or variation to the NOPR requirements for small generators and electric
storage resources could allow such resources to avoid solving the very
problem to which such resources contribute and the NOPR rules were
meant to address.'' \446\ In particular, ISO-RTO Council points out
that the ongoing transformation of the generation resource mix involves
the loss of the inertia and primary frequency response contributions
from baseload and synchronous generating facilities that have and will
retire. Since non-synchronous generators, small generators, distributed
energy resources, and electric storage resources will comprise an
increasing percentage of the future generation mix, ISO-RTO Council
states that they should contribute their fair share of primary
frequency response in accordance with the requirements proposed in the
NOPR.\447\
---------------------------------------------------------------------------

    \446\ Id. at 2.
    \447\ Id. at 2, 3.
---------------------------------------------------------------------------

    217. EEI adds that as the market penetration of small generating
facilities increases, there will be a growing need for primary
frequency response from these non-traditional generating
facilities.\448\ EEI argues that ``[i]f the Commission exempts new
small generating resources from installing primary frequency response
capability now, then retrofitting them may be needed in the future to
address reliability concerns, which will be more costly.'' \449\ EEI
states, however, that the potential costs for small generating
facilities can be reduced if the Commission limits its proposal to
solely installing primary frequency response capability and not
adopting the proposed operating requirements for droop, deadband, and
timely and sustained response in the pro forma LGIA and pro forma
SGIA.\450\
---------------------------------------------------------------------------

    \448\ EEI Supplemental Comments at 8.
    \449\ Id.
    \450\ Id. at 4.
---------------------------------------------------------------------------

    218. APS suggests that all generating facilities should contribute
to primary frequency response and opposes a blanket exemption for small
generating facilities. Rather, APS suggests that determining whether
and how small generating facilities contribute to primary frequency
response should be a collaborative effort among the balancing
authority, transmission provider, and interconnection customer.\451\
---------------------------------------------------------------------------

    \451\ APS Supplemental Comments at 10-11.
---------------------------------------------------------------------------

    219. While AES Companies oppose the NOPR, they state that the size
of any particular generating facility should not impact the solution
implemented.\452\ NRECA agrees that there should be flexibility for
balancing authorities, RTOs/ISOs, or other public utility transmission
providers to adopt requirements for primary frequency response
capability in response to specific concerns in their regions in
instances where generating facilities have particular operating or
other characteristics which make it unreasonable from a cost-benefit or
technical perspective to require primary frequency response capability
as a condition precedent to interconnection.\453\ SDG&E remains
concerned that unnecessary capital costs will be incurred if the
Commission chooses to require all new generators to have primary
frequency response capability, and that generation owners will attempt
to pass those costs along to consumers.\454\
---------------------------------------------------------------------------

    \452\ AES Companies Supplemental Comments at 42.
    \453\ NRECA Supplemental Comments at 2-3.
    \454\ SDG&E Supplemental Comments at 3-4.
---------------------------------------------------------------------------

    220. Finally, Sunrun states that even inverters certified to UL
1741 SA \455\ may or may not have certified frequency-watt response
capability, as it is not required for California's phase one advanced
inverter implementation, and even the most progressive state-level
inverter function requirements may fall short of enabling primary
frequency response capability, leaving a number of important unknowns
to small systems also needing to aggregate and participate in wholesale
markets.\456\
---------------------------------------------------------------------------

    \455\ The UL 1741 Standard is intended for use with distributed
energy resources. See UL 1741, Standard for Inverters, Converters,
Controllers, and Interconnection System Equipment for Use with
Distributed Energy Resources, https://standardscatalog.ul.com/standards/en/standard_1741_2. The Commission discusses the
applicability of the final action to distributed energy resources in
Section II.H.3.
    \456\ Sunrun Supplemental Comments at 3-4.
---------------------------------------------------------------------------

    221. In response to the Commission's question about whether the
costs for small generating facilities to install, maintain, and operate
governors or equivalent controls are proportionally comparable to the
costs for large generating facilities, NRECA states that a size
threshold is necessary so that small generators will not be forced to
forego interconnection because the cost of including primary frequency
response capability outweighs the benefit of interconnection.\457\
However, WIRAB states that costs for inverters capable of providing
primary frequency response have declined. WIRAB submits that in 2013,
the cost between a traditional inverter and an inverter capable of
providing primary frequency response was less than 1 percent of the
overall project. WIRAB adds that it is now standard practice to install
such inverters for all utility scale, non-synchronous generating
facilities because operational changes and updates can be made through
software changes.\458\ Further, WIRAB states that if the Commission
determines that small generating facilities may experience
disproportionate cost impacts associated with the proposed requirement,
the Commission should establish an exemption that would allow small
generators to provide a demonstration of disproportionate costs to its
utility to be exempt from the primary frequency response
requirements.\459\ SoCal Edison agrees that given significant
technological advances in generation facilities and equipment,
including inverters, the proposed primary

frequency response requirements for small generating facilities will
not present a barrier to entry.\460\
---------------------------------------------------------------------------

    \457\ NRECA Supplemental Comments at 4.
    \458\ WIRAB Supplemental Comments at 6-7.
    \459\ Id. at 7.
    \460\ SoCal Edison Supplemental Comments at 3.
---------------------------------------------------------------------------

    222. In response to the Commission's question about whether PJM's
recent modifications to its interconnection agreements address concerns
regarding possible disproportionate costs resulting from applying the
NOPR to all small generating facilities, ISO-RTO Council states that
PJM has not experienced any decrease in the number of interconnection
requests of small non-synchronous generators since requiring non-
synchronous generating facilities to install enhanced inverters that
include primary frequency response capability.\461\ ISO-RTO Council
states that in the last year, 30 new generating facilities were placed
into service, and of those, 25 were small generating facilities and
five were large generating facilities.\462\
---------------------------------------------------------------------------

    \461\ ISO-RTO Supplemental Comments at 6.
    \462\ Id. at 7.
---------------------------------------------------------------------------

c. Commission Determination
    223. We will not exempt small generating facilities from the
requirements. The Commission has previously acted under FPA section 206
to remove inconsistencies between the pro forma LGIA and pro forma SGIA
where there is no economic or technical basis for treating large and
small generating facilities differently.\463\ The record indicates that
small generating facilities are capable of installing and enabling
governors or equivalent technologies at low cost in a manner comparable
to large generating facilities; therefore it would be unduly
discriminatory or preferential to not impose the requirements of this
final action on small generating facilities. There is limited and
unpersuasive information in the record indicating that certain small
generating facilities would face disproportionate costs to install,
maintain, and operate equipment capable of providing primary frequency
response. Moreover, the record demonstrates that small generating
facilities are technically capable of providing primary frequency
response. No commenter provided evidence to suggest that imposing the
requirements of this final action on small generators would be
disproportionately costly or otherwise unduly burdensome.
---------------------------------------------------------------------------

    \463\ See Order No. 828, 156 FERC ] 61,062 (revising the pro
forma SGIA such that small generating facilities have frequency and
voltage ride through requirements comparable to large generating
facilities).
---------------------------------------------------------------------------

    224. In particular, we are persuaded by commenter assertions that
that small generating facilities are making up a growing percentage of
the generation resource mix,\464\ and that as the market penetration of
small generating facilities increases, there will be a growing need for
primary frequency response from these generating facilities.\465\ We
are also persuaded by commenter assertions that there is no economical
or technical basis for treating large and small generating facilities
differently when they are both capable of installing and enabling
governors at comparable costs.\466\ Finally, we do not believe that the
actions we take here will present a barrier to entry to small
generating facilities. We note ISO-RTO Council's assertion that ``PJM
has not experienced any decrease in the number of interconnections
requests or interconnections of small non-synchronous generators since
requiring nonsynchronous generating facilities to install enhanced
inverters that include primary frequency response capability.'' \467\
---------------------------------------------------------------------------

    \464\ APPA et al. Comments at 5.
    \465\ EEI Comments at 8.
    \466\ SoCal Edison Comments at 3.
    \467\ ISO-RTO Council Supplemental Comments at 7.
---------------------------------------------------------------------------

8. Requests To Establish a Waiver Process and Consider Potential Impact
on Load and New Technology
a. NOPR
    225. In the NOPR, the Commission did not propose any waiver
procedures.
b. Comments
    226. NRECA requests that the Commission consider permitting
transmission providers to establish ``penetration level thresholds''
for primary frequency response because ``[g]enerators can differ in
their impact on the transmission grid based on factors such as size and
technology.'' \468\ NRECA contends that in areas with sufficient
primary frequency response capability, including the cost of primary
frequency response in new generating facilities may not necessarily be
warranted and should therefore not be required as a condition of
interconnection.\469\ NRECA further asserts that the Commission should
``bear in mind that the costs for frequency response capability will be
recovered from load. Customers should not have to pay for capability
that is not necessary for reliability.'' \470\
---------------------------------------------------------------------------

    \468\ NRECA Comments at 8.
    \469\ Id.
    \470\ Id. at 9.
---------------------------------------------------------------------------

    227. Both NRECA and AES Companies express concern about the
potential impact of the proposed requirements on new technologies and
innovation. AES Companies assert that the proposed requirements for new
generating facilities to install primary frequency response capability
as well operate with specified droop and deadband settings will
``stymie the use of more efficient technology solutions as they become
available and impose unnecessary costs on load.'' \471\ Similarly,
NRECA is concerned that the Commission's ``all-encompassing proposal''
could risk limiting ``the deployment of the sorts of technologies and
innovation which the Commission has pledged to encourage, without
conferring reliability benefits that warrant such risks.'' \472\
---------------------------------------------------------------------------

    \471\ AES Companies Comments at 12.
    \472\ NRECA Comments at 6.
---------------------------------------------------------------------------

    228. NRECA contends that the Commission should adopt ``a waiver
process whereby if a new interconnecting generating facility is neither
needed for primary frequency response capability, nor causes any harm
to the reliability of the grid in this regard, primary frequency
response capability would not be a condition of interconnection.''
\473\
---------------------------------------------------------------------------

    \473\ Id. at 8-9.
---------------------------------------------------------------------------

c. Commission Determination
    229. We decline to adopt a waiver process for new generating
facilities. Considering the dynamic and evolving nature of primary
frequency response, we are not persuaded by NRECA's suggestion that the
current specific needs of individual balancing authority areas within
each Interconnection should determine whether to adopt minimum uniform
primary frequency response requirements as a condition of
interconnection. While the level of primary frequency response
capability may be adequate in certain individual areas, NERC
assessments indicate that the Bulk-Power System as a whole has
experienced a decline in primary frequency response. In this regard, we
reject NRECA's suggestion that ``an imminent reliability threat'' must
exist to justify new primary frequency requirements such as those we
adopt in this final action.\474\ We clarify that this final action is
intended to ensure that the overall level of primary frequency response
capability remains adequate as the generation resource mix continues to
change. Accordingly, we decline NRECA's request to develop a generic
waiver process to exempt newly interconnecting generating facilities
from the requirements of this final action.
---------------------------------------------------------------------------

    \474\ Id. at 7.
---------------------------------------------------------------------------

    230. In addition, we disagree with NRECA and AES Companies that
this

final action will result in unreasonable or unnecessary costs to load,
based on the record indicating that cost of installing primary
frequency response capability for new generating facilities is minimal.
As explained in Section II.E.2 above, many commenters agree that costs
associated with primary frequency response are minimal for new
generating facilities.
    231. Finally, we find NRECA's and AES Companies' assertions
regarding the potential adverse impact of the new primary frequency
requirements adopted in this final action on technology and innovation
to be speculative and unsupported. In this regard, we clarify that
should the new primary frequency response requirements present
obstacles to new, more efficient generating facilities that may be
developed in the future, nothing in this final action prohibits
prospective interconnection customers owning such facilities from
seeking appropriate relief from the Commission.

I. Regional Flexibility

1. NOPR Proposal
    232. In the NOPR, the Commission proposed that public utility
transmission providers must either comply with the final action,
demonstrate that previously-approved variations continue to be
consistent with or superior to the pro forma LGIA and pro forma SGIA as
modified by the final action, or seek ``independent entity variations''
from the proposed revisions to the pro forma LGIA and pro forma
SGIA.\475\
---------------------------------------------------------------------------

    \475\ NOPR, 157 FERC ] 61,122 at P 59. See Order No. 2003, FERC
Stats. & Regs. ] 31,146 at PP 822-827.
---------------------------------------------------------------------------

2. Comments
    233. Some commenters object to the proposal to make operating
requirements uniform, contending that such uniformity fails to account
for differences across regions and generating facilities--particularly
those utilizing new technology and fuel sources--and the actual need
for primary frequency response.\476\
---------------------------------------------------------------------------

    \476\ See, e.g., APS Supplemental Comments at 5-6; MISO TOs
Comments at 2; SoCal Edison Comments at 3; Xcel Comments at 7; NYTO
Supplemental Comments at 3-4.
---------------------------------------------------------------------------

3. Commission Determination
    234. As explained above in Section II.B.3.a, we disagree with
commenters who support a completely regional approach. We believe that
the most effective approach to addressing concerns regarding primary
frequency response is to establish and maintain minimum, uniform
requirements for all newly interconnecting generating facilities.
However, we recognize that unique circumstances or needs of some
individual regions or areas may warrant different operating
requirements. Therefore, we adopt the NOPR proposal and will allow
transmission providers to propose variations to the operating
requirements adopted in this final action. Specifically, the following
methods for proposing variations adopted in Order No. 2003 will be
available here: (1) Variations based on Regional Entity reliability
requirements; (2) variations that are ``consistent with or superior
to'' the final action; and (3) ``independent entity variations'' filed
by RTOs/ISOs.\477\
---------------------------------------------------------------------------

    \477\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 822-
827. A very similar approach was taken in Order No. 827, FERC Stats.
& Regs. ] 31,385 at P 69 and Order No. 828, 156 FERC ] 61,062 at PP
40-41.
---------------------------------------------------------------------------

    235. Finally, we clarify that the Commission will also consider
requests for ``regional reliability variations,'' provided they are
supported by references to regional Reliability Standards. In addition,
in any such request, the transmission provider shall explain why these
regional Reliability Standards support the requested variation, and
shall include the text of the referenced Reliability Standards.\478\
---------------------------------------------------------------------------

    \478\ See Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 546.
---------------------------------------------------------------------------

J. Miscellaneous Comments

1. Uniform System of Accounts
a. Comments
    236. Xcel states that the Commission should add a new account to
the FERC Uniform System of Accounts to allow the identification and
tracking of cost information associated with primary frequency
response. Xcel argues that a new FERC account would allow for the
collection of installed cost information ``so that the Commission can
ensure that any rates reflect those costs and recover the costs form
the appropriate customer base (i.e., transmission versus production
customers).'' \479\
---------------------------------------------------------------------------

    \479\ Xcel Comments at 9-10.
---------------------------------------------------------------------------

b. Commission Determination
    237. We deny this request. First, the costs of installing,
maintaining, and operating a governor or equivalent controls is not
significant and is captured by other accounts.\480\ Second, synchronous
generating facilities have installed, maintained, and operated
governors for many years and Xcel has not demonstrated why changed
circumstances require new accounts to capture these costs. It is also
not clear why these existing accounts could not similarly be applied to
non-synchronous generating facilities.
---------------------------------------------------------------------------

    \480\ Examples of these other accounts are described in Appendix
C of this final action.
---------------------------------------------------------------------------

2. Capability of Load To Provide Primary Frequency Response
a. Comments
    238. Union of Concerned Scientists asserts that while it believes
that the NOPR proposal is ``an important step'' and the Commission
should ``complete this rulemaking,'' the NOPR proposal ``omit[s]
discussion of how the utility industry may draw on the capability of
loads to provide frequency response.'' \481\ Accordingly, Union of
Concerned Scientists urges the Commission to ``guide utilities to
include load resources in the development of primary frequency response
services and requirements.'' \482\ Union of Concerned Scientists
maintains that the NOPR proposal is a necessary, but insufficient, step
in addressing primary frequency response because: (1) The NOPR excludes
load from consideration as a primary frequency response resource; and
(2) the reliance on headrooT from generating facilities for the
provision of primary frequency response results in a greater economic
cost to generating facilities compared to the zero marginal cost of
load as a resource for providing primary frequency response.\483\
---------------------------------------------------------------------------

    \481\ Union of Concerned Scientists Comments at 3.
    \482\ Id. at 8.
    \483\ Id. at 7-8.
---------------------------------------------------------------------------

b. Commission Determination
    239. We decline in this final action to address the need for load
resources to provide primary frequency response. While we note that
there are many complicated issues related to the provision of primary
frequency response by load resources, we find that these issues are
beyond the scope of this proceeding, which is limited to modifications
to the pro forma LGIA and the pro forma SGIA. We recognize that
currently some load resources can and do provide some primary frequency
response. Nothing in this final action is meant to discourage or
prevent them from doing so.
3. Primary Frequency Response Obligations and Pools
a. Comments
    240. AES Companies state that NERC's Essential Reliability Services
Task Force recommended that all new generating facilities should
support the capability to manage frequency control, not that they
should provide primary

frequency response themselves.\484\ As a result, AES Companies suggest
that the Commission modify the NOPR proposal to allow the
interconnection customer to demonstrate that they can provide its
proportional share of primary frequency response, either through self-
supply from other generating facilities within its fleet or via
procurement from a third party.\485\ AES Companies further suggest that
utilities and other generation owners should then be allowed to form
pools and/or aggregate their resources to meet an allocated
proportionate share of their primary frequency response
responsibility.\486\
---------------------------------------------------------------------------

    \484\ AES Companies Comments at 12.
    \485\ Id.
    \486\ Id.
---------------------------------------------------------------------------

b. Commission Determination
    241. We reject AES Companies' suggestions. Adopting these
suggestions would add complications and create substantial uncertainty
for generating facilities providing primary frequency response, which
will detract from one of the Commission's goals (i.e., minimizing
complexity and uncertainty with regard to primary frequency response).

K. Specific Revisions to the Pro Forma LGIA and Pro Forma SGIA

1. NOPR Proposal
    242. To implement the proposed primary frequency response
requirements, the Commission proposed in the NOPR to revise Sections
9.6 and <IP_ADDRESS> of the pro forma LGIA and add new Sections 9.6.4,
<IP_ADDRESS>, and <IP_ADDRESS> to the pro forma LGIA.\487\ Similarly, the
Commission proposed to revise Section 1.8 of the pro forma SGIA and add
new Sections 1.8.4, <IP_ADDRESS>, and <IP_ADDRESS> to the pro forma SGIA.\488\
---------------------------------------------------------------------------

    \487\ NOPR, 157 FERC ] 61,122 at P 52.
    \488\ Id. P 53.
---------------------------------------------------------------------------

2. Comments
    243. As noted above in Sections II.B.2.a, II.B.2.b, II.B.2.c,
II.C.2, II.H.1.b, and II.H.2.b of this final action, Bonneville, EEI,
ELCON, NERC, ISO-RTO Council, and WIRAB request certain modifications
to the proposed changes to pro forma LGIA and pro forma SGIA as
discussed in the NOPR. AES Companies also request to modify Section 9.6
of the pro forma LGIA.\489\
---------------------------------------------------------------------------

    \489\ AES Companies Comments at 15.
---------------------------------------------------------------------------

3. Commission Determination
    244. We deny AES Companies' request to modify Section 9.6 of the
pro forma LGIA as the request is related to reactive power and thus
beyond the scope of this proceeding. We also deny AES Companies other
proposed modifications to the pro forma LGIA and pro forma SGIA.
    245. Further, as explained in Sections II.B and II.C above, we
conclude that EEI's requested modifications to the proposed revisions
in the pro forma LGIA and pro forma SGIA that undermine uniformity are
not consistent with the objectives explained herein and therefore are
denied. However, we adopt EEI's requested language pertaining to timely
and sustained response, particularly the phrase ``shall not block or
inhibit governor or equivalent controls.''
    246. In light of the above discussion, we revise the pro forma LGIA
to modify Sections 9.6 and <IP_ADDRESS> and adds new Sections 9.6.4,
<IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, and <IP_ADDRESS>. This section contains the
totality of the revised revisions the pro forma LGIA. The revisions,
with bracketed deletions from and italicized additions to the pro forma
LGIA are as follows:

9.6 Reactive Power and Primary Frequency Response

    <IP_ADDRESS> [Governors and] Voltage Regulators. Whenever the Large
Generating Facility is operated in parallel with the Transmission
System [and the speed governors (if installed on the generating unit
pursuant to Good Utility Practice)] and voltage regulators are capable
of operation, Interconnection Customer shall operate the Large
Generating Facility with its [speed governors and] voltage regulators
in automatic operation. If the Large Generating Facility's [speed
governors and] voltage regulators are not capable of such automatic
operation, Interconnection Customer shall immediately notify
Transmission Provider's system operator, or its designated
representative, and ensure that such Large Generating Facility's
reactive power production or absorption (measured in MVARs) are within
the design capability of the Large Generating Facility's generating
unit(s) and steady state stability limits. Interconnection Customer
shall not cause its Large Generating Facility to disconnect
automatically or instantaneously from the Transmission System or trip
any generating unit comprising the Large Generating Facility for an
under or over frequency condition unless the abnormal frequency
condition persists for a time period beyond the limits set forth in
ANSI/IEEE Standard C37.106, or such other standard as applied to other
generators in the Control Area on a comparable basis. (Bracketed text
is deleted, italicized text are additions.)
    9.6.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Large
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Large Generating Facility's real
power output in accordance with the droop and deadband parameters and
in the direction needed to correct frequency deviations.
Interconnection Customer is required to install a governor or
equivalent controls with the capability of operating: (1) With a
maximum 5 percent droop and 0.036 Hz deadband; or
(2) in accordance with the relevant droop, deadband, and timely and
sustained response settings from an approved NERC Reliability Standard
providing for equivalent or more stringent parameters. The droop
characteristic shall be: (1) Based on the nameplate capacity of the
Large Generating Facility, and shall be linear in the range of
frequencies between 59 to 61 Hz that are outside of the deadband
parameter; or (2) based an approved NERC Reliability Standard providing
for an equivalent or more stringent parameter. The deadband parameter
shall be: the range of frequencies above and below nominal (60 Hz) in
which the governor or equivalent controls is not expected to adjust the
Large Generating Facility's real power output in response to frequency
deviations. The deadband shall be implemented: (1) Without a step to
the droop curve, that is, once the frequency deviation exceeds the
deadband parameter, the expected change in the Large Generating
Facility's real power output in response to frequency deviations shall
start from zero and then increase (for under-frequency deviations) or
decrease (for over-frequency deviations) linearly in proportion to the
magnitude of the frequency deviation; or (2) in accordance with an
approved NERC Reliability Standard providing for an equivalent or more
stringent parameter. Interconnection Customer shall notify Transmission
Provider that the primary frequency response capability of the Large
Generating Facility has been tested and confirmed during commissioning.
Once Interconnection Customer has synchronized the Large Generating
Facility with the

Transmission System, Interconnection Customer shall operate the Large
Generating Facility consistent with the provisions specified in
Sections <IP_ADDRESS> and <IP_ADDRESS> of this Agreement. The primary frequency
response requirements contained herein shall apply to both synchronous
and non-synchronous Large Generating Facilities.
    <IP_ADDRESS> Governor or Equivalent Controls. Whenever the Large
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Large Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall: (1) In
coordination with Transmission Provider and/or the relevant balancing
authority, set the deadband parameter to: (1) A maximum of 0.036 Hz and set the droop parameter to a maximum of 5
percent; or (2) implement the relevant droop and deadband settings from
an approved NERC Reliability Standard that provides for equivalent or
more stringent parameters. Interconnection Customer shall be required
to provide the status and settings of the governor or equivalent
controls to Transmission Provider and/or the relevant balancing
authority upon request. If Interconnection Customer needs to operate
the Large Generating Facility with its governor or equivalent controls
not in service, Interconnection Customer shall immediately notify
Transmission Provider and the relevant balancing authority, and provide
both with the following information: (1) The operating status of the
governor or equivalent controls (i.e., whether it is currently out of
service or when it will be taken out of service); (2) the reasons for
removing the governor or equivalent controls from service; and (3) a
reasonable estimate of when the governor or equivalent controls will be
returned to service. Interconnection Customer shall make Reasonable
Efforts to return its governor or equivalent controls into service as
soon as practicable. Interconnection Customer shall make Reasonable
Efforts to keep outages of the Large Generating Facility's governor or
equivalent controls to a minimum whenever the Large Generating Facility
is operated in parallel with the Transmission System.
    <IP_ADDRESS> Timely and Sustained Response. Interconnection Customer
shall ensure that the Large Generating Facility's real power response
to sustained frequency deviations outside of the deadband setting is
automatically provided and shall begin immediately after frequency
deviates outside of the deadband, and to the extent the Large
Generating Facility has operating capability in the direction needed to
correct the frequency deviation. Interconnection Customer shall not
block or otherwise inhibit the ability of the governor or equivalent
controls to respond and shall ensure that the response is not
inhibited, except under certain operational constraints including, but
not limited to, ambient temperature limitations, physical energy
limitations, outages of mechanical equipment, or regulatory
requirements. The Large Generating Facility shall sustain the real
power response at least until system frequency returns to a value
within the deadband setting of the governor or equivalent controls. A
Commission-approved Reliability Standard with equivalent or more
stringent requirements shall supersede the above requirements.
    <IP_ADDRESS> Exemptions. Large Generating Facilities that are regulated
by the United States Nuclear Regulatory Commission shall be exempt from
Sections 9.6.4, <IP_ADDRESS>, and <IP_ADDRESS> of this Agreement. Large
Generating Facilities that are behind the meter generation that is
sized-to-load (i.e., the thermal load and the generation are near-
balanced in real-time operation and the generation is primarily
controlled to maintain the unique thermal, chemical, or mechanical
output necessary for the operating requirements of its host facility)
shall be required to install primary frequency response capability in
accordance with the droop and deadband capability requirements
specified in Section 9.6.4, but shall be otherwise exempt from the
operating requirements in Sections 9.6.4, <IP_ADDRESS>, <IP_ADDRESS>, and <IP_ADDRESS>
of this Agreement.
    <IP_ADDRESS> Electric Storage Resources. Interconnection Customer
interconnecting an electric storage resource shall establish an
operating range in Appendix C of its LGIA that specifies a minimum
state of charge and a maximum state of charge between which the
electric storage resource will be required to provide primary frequency
response consistent with the conditions set forth in Sections 9.6.4,
<IP_ADDRESS>, <IP_ADDRESS>, and <IP_ADDRESS> of this Agreement. Appendix C shall
specify whether the operating range is static or dynamic, and shall
consider (1) the expected magnitude of frequency deviations in the
interconnection; (2) the expected duration that system frequency will
remain outside of the deadband parameter in the interconnection; (3)
the expected incidence of frequency deviations outside of the deadband
parameter in the interconnection; (4) the physical capabilities of the
electric storage resource; (5) operational limitations of the electric
storage resource due to manufacturer specifications; and (6) any other
relevant factors agreed to by Transmission Provider and Interconnection
Customer, and in consultation with the relevant transmission owner or
balancing authority as appropriate. If the operating range is dynamic,
then Appendix C must establish how frequently the operating range will
be reevaluated and the factors that may be considered during its
reevaluation.
    Interconnection Customer's electric storage resource is required to
provide timely and sustained primary frequency response consistent with
Section <IP_ADDRESS> of this Agreement when it is online and dispatched to
inject electricity to the Transmission System and/or receive
electricity from the Transmission System. This excludes circumstances
when the electric storage resource is not dispatched to inject
electricity to the Transmission System and/or dispatched to receive
electricity from the Transmission System. If Interconnection Customer's
electric storage resource is charging at the time of a frequency
deviation outside of its deadband parameter, it is to increase (for
over-frequency deviations) or decrease (for under-frequency deviations)
the rate at which it is charging in accordance with its droop
parameter. Interconnection Customer's electric storage resource is not
required to change from charging to discharging, or vice versa, unless
the response necessitated by the droop and deadband settings requires
it to do so and it is technically capable of making such a transition.
    247. Similarly, the Commission modifies Section 1.8 of the pro
forma SGIA and adds new Sections 1.8.4, <IP_ADDRESS>, <IP_ADDRESS> and <IP_ADDRESS>,
and <IP_ADDRESS>. This section contains the totality of the revised
revisions the pro forma SGIA. The revisions, with italicized additions
to the pro forma SGIA are as follows:
    1.8 Reactive Power and Primary Frequency Response
    1.8.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Small
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Small Generating Facility's real
power output

in accordance with the droop and deadband parameters and in the
direction needed to correct frequency deviations. Interconnection
Customer is required to install a governor or equivalent controls with
the capability of operating: (1) With a maximum 5 percent droop and
0.036 Hz deadband; or (2) in accordance with the relevant
droop, deadband, and timely and sustained response settings from an
approved NERC Reliability Standard providing for equivalent or more
stringent parameters. The droop characteristic shall be: (1) Based on
the nameplate capacity of the Small Generating Facility, and shall be
linear in the range of frequencies between 59 to 61 Hz that are outside
of the deadband parameter; or (2) based an approved NERC Reliability
Standard providing for an equivalent or more stringent parameter. The
deadband parameter shall be: the range of frequencies above and below
nominal (60 Hz) in which the governor or equivalent controls is not
expected to adjust the Small Generating Facility's real power output in
response to frequency deviations. The deadband shall be implemented:
(1) Without a step to the droop curve, that is, once the frequency
deviation exceeds the deadband parameter, the expected change in the
Small Generating Facility's real power output in response to frequency
deviations shall start from zero and then increase (for under-frequency
deviations) or decrease (for over-frequency deviations) linearly in
proportion to the magnitude of the frequency deviation; or (2) in
accordance with an approved NERC Reliability Standard providing for an
equivalent or more stringent parameter. Interconnection Customer shall
notify Transmission Provider that the primary frequency response
capability of the Small Generating Facility has been tested and
confirmed during commissioning. Once Interconnection Customer has
synchronized the Small Generating Facility with the Transmission
System, Interconnection Customer shall operate the Small Generating
Facility consistent with the provisions specified in Sections <IP_ADDRESS>
and <IP_ADDRESS> of this Agreement. The primary frequency response
requirements contained herein shall apply to both synchronous and non-
synchronous Small Generating Facilities.
    <IP_ADDRESS> Governor or Equivalent Controls. Whenever the Small
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Small Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall: (1) In
coordination with Transmission Provider and/or the relevant balancing
authority, set the deadband parameter to: (1) A maximum of 0.036 Hz and set the droop parameter to a maximum of 5
percent; or (2) implement the relevant droop and deadband settings from
an approved NERC Reliability Standard that provides for equivalent or
more stringent parameters. Interconnection Customer shall be required
to provide the status and settings of the governor or equivalent
controls to Transmission Provider and/or the relevant balancing
authority upon request. If Interconnection Customer needs to operate
the Small Generating Facility with its governor or equivalent controls
not in service, Interconnection Customer shall immediately notify
Transmission Provider and the relevant balancing authority, and provide
both with the following information: (1) The operating status of the
governor or equivalent controls (i.e., whether it is currently out of
service or when it will be taken out of service); (2) the reasons for
removing the governor or equivalent controls from service; and (3) a
reasonable estimate of when the governor or equivalent controls will be
returned to service. Interconnection Customer shall make Reasonable
Efforts to return its governor or equivalent controls into service as
soon as practicable. Interconnection Customer shall make Reasonable
Efforts to keep outages of the Small Generating Facility's governor or
equivalent controls to a minimum whenever the Small Generating Facility
is operated in parallel with the Transmission System.
    <IP_ADDRESS> Timely and Sustained Response. Interconnection Customer
shall ensure that the Small Generating Facility's real power response
to sustained frequency deviations outside of the deadband setting is
automatically provided and shall begin immediately after frequency
deviates outside of the deadband, and to the extent the Small
Generating Facility has operating capability in the direction needed to
correct the frequency deviation. Interconnection Customer shall not
block or otherwise inhibit the ability of the governor or equivalent
controls to respond and shall ensure that the response is not
inhibited, except under certain operational constraints including, but
not limited to, ambient temperature limitations, physical energy
limitations, outages of mechanical equipment, or regulatory
requirements. The Small Generating Facility shall sustain the real
power response at least until system frequency returns to a value
within the deadband setting of the governor or equivalent controls. A
Commission-approved Reliability Standard with equivalent or more
stringent requirements shall supersede the above requirements.
    <IP_ADDRESS> Exemptions. Small Generating Facilities that are regulated
by the United States Nuclear Regulatory Commission shall be exempt from
Sections 1.8.4, <IP_ADDRESS>, and <IP_ADDRESS> of this Agreement. Small
Generating Facilities that are behind the meter generation that is
sized-to-load (i.e., the thermal load and the generation are near-
balanced in real-time operation and the generation is primarily
controlled to maintain the unique thermal, chemical, or mechanical
output necessary for the operating requirements of its host facility)
shall be required to install primary frequency response capability in
accordance with the droop and deadband capability requirements
specified in Section 1.8.4, but shall be otherwise exempt from the
operating requirements in Sections 1.8.4, <IP_ADDRESS>, <IP_ADDRESS>, and <IP_ADDRESS>
of this Agreement.
    <IP_ADDRESS> Electric Storage Resources. Interconnection Customer
interconnecting an electric storage resource shall establish an
operating range in Attachment 5 of its SGIA that specifies a minimum
state of charge and a maximum state of charge between which the
electric storage resource will be required to provide primary frequency
response consistent with the conditions set forth in Sections 1.8.4,
<IP_ADDRESS>, <IP_ADDRESS> and <IP_ADDRESS> of this Agreement. Attachment 5 shall
specify whether the operating range is static or dynamic, and shall
consider: (1) The expected magnitude of frequency deviations in the
interconnection; (2) the expected duration that system frequency will
remain outside of the deadband parameter in the interconnection; (3)
the expected incidence of frequency deviations outside of the deadband
parameter in the interconnection; (4) the physical capabilities of the
electric storage resource; (5) operational limitations of the electric
storage resource due to manufacturer specifications; and (6) any other
relevant factors agreed to by Transmission Provider and Interconnection
Customer, and in consultation with the relevant transmission owner or
balancing authority as appropriate. If the operating range is dynamic,
then Attachment 5 must establish how frequently the operating range
will be

reevaluated and the factors that may be considered during its
reevaluation.
    Interconnection Customer's electric storage resource is required to
provide timely and sustained primary frequency response consistent with
Section <IP_ADDRESS> of this Agreement when it is online and dispatched to
inject electricity to the Transmission System and/or receive
electricity from the Transmission System. This excludes circumstances
when the electric storage resource is not dispatched to inject
electricity to the Transmission System and/or dispatched to receive
electricity from the Transmission System. If Interconnection Customer's
electric storage resource is charging at the time of a frequency
deviation outside of its deadband parameter, it is to increase (for
over-frequency deviations) or decrease (for under-frequency deviations)
the rate at which it is charging in accordance with its droop
parameter. Interconnection Customer's electric storage resource is not
required to change from charging to discharging, or vice versa, unless
the response necessitated by the droop and deadband settings requires
it to do so and it is technically capable of making such a transition.
    248. The Commission is also modifying the pro forma LGIP and pro
forma SGIP to require newly interconnecting electric storage resources
to include the details of the operating range in their interconnection
request.
    249. In particular, the Commission is modifying the following
sections of the pro forma LGIP as indicated below:

Appendix 1 to LGIP Interconnection Request for a Large Generating
Facility

5. Interconnection Customer provides the following information:

h. Primary frequency response operating range for electric storage
resources.

Attachment A to Appendix 1 Interconnection Request

Unit Ratings

    Primary frequency response operating range for electric storage
resources:

Minimum State of Charge: __
Maximum State of Charge: __

    250. Similarly, the Commission is modifying the following sections
of the pro forma SGIP as indicated below. The revisions, with
italicized additions to pro forma SGIP are as follows:

Attachment 2 Small Generator Interconnection Request (Application Form)

Small Generating Facility Information

    Primary frequency response operating range for electric storage
resources:

Minimum State of Charge: __
Maximum State of Charge: __

III. Compliance and Implementation

    251. Section 35.28(f)(1) of the Commission's regulations requires
every public utility with a non-discriminatory OATT on file to also
have a pro forma LGIA and pro forma SGIA on file with the
Commission.\490\
---------------------------------------------------------------------------

    \490\ 18 CFR 35.28(f)(1) (2017).
---------------------------------------------------------------------------

    252. We reiterate that the requirements of this final action apply
to all newly interconnecting large and small generating facilities that
execute or request the unexecuted filing of a LGIA or SGIA on or after
the effective date of this final action as well as all existing large
and small generating facilities that take any action that requires the
submission of a new interconnection request that results in the filing
of an executed or unexecuted interconnection agreement on or after the
effective date of this final action. We are not requiring changes to
existing interconnection agreements that were executed, or filed
unexecuted, prior to the effective date of this final action.
    253. We require each public utility transmission provider that has
a pro forma LGIA and/or pro forma SGIA within its OATT to submit a
compliance filing within 70 days following publication of this final
action in the Federal Register.\491\ The compliance filing must
demonstrate that it meets the requirements set forth in this final
action.
---------------------------------------------------------------------------

    \491\ For purposes of this final action, a public utility is a
utility that owns, controls, or operates facilities used for
transmitting electric energy in interstate commerce, as defined by
the FPA. See 16 U.S.C. 824(e). A non-public utility that seeks
voluntary compliance with the reciprocity condition of an OATT may
satisfy that condition by filing an OATT, which includes a LGIA and
SGIA.
---------------------------------------------------------------------------

    254. Some public utility transmission providers may have provisions
in their existing pro forma LGIAs and pro forma SGIAs or other
document(s) subject to the Commission's jurisdiction that the
Commission has deemed to be consistent with or superior to the pro
forma LGIA and pro forma SGIA or are permissible under the independent
entity variation standard or regional reliability standard.\492\ Where
these provisions would be 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 LGIA and pro forma SGIA as
modified by this final action or continue to be permissible under the
independent entity variation standard or regional Reliability
Standard.\493\
---------------------------------------------------------------------------

    \492\ See Order No. 792, 145 FERC ] 61,159 at P 270.
    \493\ See 18 CFR 35.28(f)(1)(i).
---------------------------------------------------------------------------

    255. We 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.\494\
---------------------------------------------------------------------------

    \494\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,760-63 (1996),
order on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order
on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
---------------------------------------------------------------------------

IV. Information Collection Statement

    256. The following collection of information contained in this
final action is subject to review by the Office of Management and
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of
1995, 44 U.S.C. 3507(d).\495\ The Paperwork Reduction Act (PRA) \496\
requires each federal agency to seek and obtain Office of Management
and Budget (OMB) approval before undertaking a collection of
information directed to ten or more persons, or contained in a rule of
general applicability. OMB's regulations require the approval of
certain information collection requirements imposed by agency
rules.\497\ Upon approval of a collection of information, OMB will
assign an OMB control number and an expiration date. Respondents
subject to the filing requirements of this proposal will not be
penalized for failing to respond to this collection of information
unless the collection of information displays a valid OMB control
number. Transmission providers and generating facilities are subject to
the proposed revisions to the pro forma LGIA and pro forma SGIA.
---------------------------------------------------------------------------

    \495\ 44 U.S.C. 3507(d) (2012).
    \496\ 44 U.S.C. 3501-3520 (2012).
    \497\ 5 CFR 1320.11 (2017).
---------------------------------------------------------------------------

    257. This final action revises the Commission's pro forma LGIA and
pro forma SGIA in accordance with Sec.  35.28(f)(1) of the Commission's
regulations,\498\ and applies to all newly interconnecting large and
small generating facilities that execute or request the unexecuted
filing of a LGIA or SGIA on or after the effective date of this final
action as well as all existing large and small generating facilities
that

take any action that requires the submission of a new interconnection
request that results in the filing of an executed or unexecuted
interconnection agreement on or after the effective date of this final
action. Generating facilities subject to this final action will be
required to install, maintain, and operate equipment capable of
providing primary frequency response, consistent with certain operating
requirements for droop, deadband, and timely and sustained response.
The reforms adopted in this final action would require filings of pro
forma LGIAs and pro forma SGIAs with the Commission. We anticipate the
revisions required by this final action, once implemented, will not
significantly change 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 70 days after
the effective date of this final action. The Commission will submit the
proposed reporting requirements to OMB for its review and approval
under section 3507(d) of the Paperwork Reduction Act.\499\ In the NOPR,
the Commission used FERC-516B as a temporary ``placeholder''
information collection number.\500\ The Commission is now using FERC-
516 information collection because it is no longer pending at OMB in
any actions.
---------------------------------------------------------------------------

    \498\ 18 CFR 35.28(f)(1) (2017).
    \499\ 44 U.S.C. 3507(d).
    \500\ The reporting requirements in the NOPR were included under
FERC-516B (OMB Control No. 1902-0286), because FERC-516 was pending
review at OMB in an unrelated action. The reporting requirements in
this final action are included under FERC-516 (OMB Control No. 1902-
0096).
---------------------------------------------------------------------------

    258. While the Commission expects the revisions adopted in this
final action will provide significant benefits, the Commission
understands that implementation would entail some costs. The Commission
solicited comments on the collection of information and the associated
burden estimate in the NOPR. The Commission did not receive any
comments concerning its burden or cost estimates.
    Burden Estimate \501\: Costs to Comply with Paperwork Requirements:
The estimated annual costs are as follows: FERC-516: 74 entities * 1
response/entity (10 hours/response * $74.50/hour) = $56,610.\502\
---------------------------------------------------------------------------

    \501\ Burden means the total time, effort, or financial
resources expended by persons to generate, maintain, retain,
disclose or provide information to or for a Federal agency,
including: The time, effort, and financial resources necessary to
comply with a collection of information that would be incurred by
persons in the normal course of their activities (e.g., in compiling
and maintaining business records) will be excluded from the
``burden'' if the agency demonstrates that the reporting,
recordkeeping, or disclosure activities needed to comply are usual
and customary.
    \502\ The estimates for cost per response are derived using the
following formula: 2017 Average Burden Hours per Response * $76.50
per Hour = Average Cost per Response. The hourly cost figure of
$76.50 is the average FERC employee wage plus benefits. We assume
that respondents earn at a similar rate.

                                        FERC 516 in Final Action, RM16-6
----------------------------------------------------------------------------------------------------------------
                                                                                Average burden    Total annual
                                  Number of      Annual number   Total number     (hours) and      burden hours
                                 respondents     of responses    of responses     cost ($) per      and total
                                    \503\       per respondent                      response     annual cost ($)
                                           (1)             (2)     (1) * (2) =  (4)............  (3) * (4) = (5)
                                                                           (3)
----------------------------------------------------------------------------------------------------------------
LGIA & SGIA changes/                        74               1              74  10 hours;        740 hours;
 revisions.                                                                      $765.00.         $56,610.00.
                             -----------------------------------------------------------------------------------
    Total...................  ................  ..............              74  ...............  740 hours;
                                                                                $56,610.00.
----------------------------------------------------------------------------------------------------------------

    Title: FERC-516, Electric Rate Schedules and Tariff Filings.
---------------------------------------------------------------------------

    \503\ The NERC Compliance Registry lists 80 entities that
administer a transmission tariff and provide transmission service.
The Commission identifies only 74 as being subject to the proposed
requirements because 6 are Canadian entities and are not under the
Commission's jurisdiction.
---------------------------------------------------------------------------

    Action: Revision of currently approved collection of information.
    OMB Control No.: 1902-0096.
    Respondents for this Rulemaking: Businesses or other for profit
and/or not-for-profit institutions.
    Frequency of Information: One-time during year 1.
    259. Necessity of Information: The Commission is modifying the pro
forma LGIA and pro forma SGIA to require all newly interconnecting
large and small generating facilities, both synchronous and non-
synchronous, to install, maintain, and operate equipment capable of
providing primary frequency response as a condition of interconnection.
Specifically, the Commission is modifying the pro forma LGIA by
revising Sections 9.6 and <IP_ADDRESS> and adding new Sections 9.6.4,
<IP_ADDRESS>, <IP_ADDRESS> and <IP_ADDRESS>, and is modifying the pro forma SGIA by
revising section 1.8 and adding new Sections 1.8.4, <IP_ADDRESS>, <IP_ADDRESS>,
and <IP_ADDRESS>.
    260. Internal Review: The Commission has reviewed the changes and
has determined that the 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 assured itself, by means of internal review, that there
is specific, objective support for the burden estimates associated with
the information collection requirements.
    261. 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>.
    262. Comments on the collection of information and the associated
burden estimate 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], at the following email address:
[email protected]. Please reference OMB Control No. 1902-0096
and the docket number of this rulemaking in your submission.

V. Regulatory Flexibility Act

    263. The Regulatory Flexibility Act of 1980 (RFA) \504\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA does
not mandate any particular outcome in a rulemaking. It only requires
consideration of alternatives that are less burdensome to small
entities and an agency explanation of why alternatives were rejected.
---------------------------------------------------------------------------

    \504\ 5 U.S.C. 601-612 (2012).
---------------------------------------------------------------------------

    264. The Small Business Administration (SBA) revised its size

standards (effective January 22, 2014) for electric utilities from a
standard based on megawatt hours to a standard based on the number of
employees, including affiliates. Under SBA's standards, some
transmission owners will fall under the following category and
associated size threshold: Electric bulk power transmission and
control, at 500 employees.\505\
---------------------------------------------------------------------------

    \505\ 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121
(Electric Bulk Power Transmission and Control) (2017).
---------------------------------------------------------------------------

    265. The Commission estimates that the total number of public
utility transmission providers that would have to modify the LGIAs and
SGIAs within their currently effective OATTs is 74.\506\ Of these, the
Commission estimates that approximately 27.5 percent are small
entities. The Commission estimates the average cost to each of these
entities would be minimal, requiring on average 10 hours or $765.00.
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.'' \507\ The Commission does not consider the estimated
burden to be a significant economic impact. As a result, the Commission
certifies that the reforms adopted in this final action would not have
a significant economic impact on a substantial number of small
entities.
---------------------------------------------------------------------------

    \506\ The NERC Compliance Registry lists 80 entities that
administer a transmission tariff and provide transmission service.
The Commission identifies only 74 as being subject to the proposed
requirements because six are Canadian entities and are not under the
Commission's jurisdiction.
    \507\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------

    266. The Commission estimates that the total annual number of new
non-synchronous interconnections per year for the first few years of
potential implementation under this rule would be approximately 200,
representing approximately 5,000 MW of installed capacity. For this
analysis, the Commission assumes that all new non-synchronous
interconnections would be small entities.\508\ The Commission estimates
the average total cost to each of these entities would be minimal,
requiring on average approximately $3,300 per MW of installed capacity
for new equipment and software to meet the requirements of this rule,
or an average of $82,500 per entity (this assumes 200 equally sized new
non-synchronous interconnections of 25 MW, actual costs will vary
proportionate to the size of the interconnection).\509\ 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.'' The Commission does not consider the estimated burden to
be a significant economic impact on these entities because the cost is
relatively minimal compared to the average capital cost per MW for wind
and solar PV generation (approximately 0.20 and 0.19 percent of total
capital costs for wind and solar, respectively).\510\ Additionally, the
Commission does not believe that there would be substantial additional
costs for new synchronous generators because synchronous generators
already come equipped with governors that provide the capability to
provide primary frequency response. Finally, the Commission does not
believe that there would be any overlap between entities that are
public utility transmission providers and new non-synchronous
interconnections. Accordingly, because the Commission believes that
this rule would not have a significant economic impact on a substantial
number of small entities that are public utility transmission providers
and would not have a significant economic impact on a substantial
number of small entities that are new non-synchronous interconnections,
the Commission believes that this rule in its entirety would not have a
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \508\ The threshold for solar and wind generation companies to
be defined as small entities is having less than 250 employees. See
13 CFR 121.201, Sector 22 (Utilities).
    \509\ These costs are not relevant to the Paperwork Reduction
Act.
    \510\ LBNL estimates that capital cost per MW of installed wind
capacity is $1,690,000. See LBNL 2015 Wind Market Report (Aug.
2016), https://emp.lbl.gov/sites/all/files/2015-windtechreport.final_.pdf. NREL estimates that the capital cost per
MW of installed solar PV capacity is $1,770,000. See NREL U.S.
Photovoltaic Prices and Cost Breakdowns (Sep. 2015), https://www.nrel.gov/docs/fy15osti/64746.pdf.
---------------------------------------------------------------------------

VI. Environmental Analysis

    267. 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.\511\ As we
stated in the NOPR, the Commission concludes that neither an
Environmental Assessment nor an Environmental Impact Statement is
required for the revisions adopted in 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, classifications,
and services.\512\ The revisions adopted in this final action would
update and clarify the application of the Commission's standard
interconnection requirements to large and small generating facilities.
---------------------------------------------------------------------------

    \511\ Regulations Implementing National Environmental Policy
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987) (cross-
referenced at 41 FERC ] 61,284).
    \512\ 18 CFR 380.4(a)(15) (2017).
---------------------------------------------------------------------------

    268. Therefore, this final action falls within the categorical
exemptions provided in the Commission's regulations, and as a result
neither an Environmental Impact Statement nor an Environmental
Assessment is required.

VII. Document Availability

    269. 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 Standard Time) at 888 First Street NE,
Room 2A, Washington, DC 20426.
    270. 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.
    271. 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].

VIII. Effective Date and Congressional Notification

    272. The final action is effective May 15, 2018. However, as noted
above, the requirements of this final action will apply only to all
newly interconnecting large and small generating facilities that

execute or request the unexecuted filing of an LGIA or SGIA on or after
the effective date of this final action as well as all existing large
and small generating facilities that take any action that requires the
submission of a new interconnection request that results in the filing
of an executed or unexecuted interconnection agreement on or after the
effective date of this final action. The Commission has determined,
with the concurrence of the Administrator of the Office of Information
and Regulatory Affairs of OMB, that this final 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 Senate, House, Government Accountability Office, and Small
Business Administration.

    By the Commission.

    Issued: February 15, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

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

I. Appendix A: List of Substantive NOPR Commenters (RM16-6-000)

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

------------------------------------------------------------------------
AES Companies.....................  AES Corporation/AES Energy Storage/
                                     Dayton Power and Light Company/
                                     Indianapolis Power and Light
                                     Company.
APPA et al........................  American Public Power Association/
                                     Large Public Power Council/
                                     Transmission Access Policy Study
                                     Group.
AWEA..............................  American Wind Energy Association.
API...............................  American Petroleum Institute.
Bonneville........................  Bonneville Power Administration.
Chelan County.....................  Chelan County Public Utility
                                     District.
California Cities.................  City of Anaheim/City of Azusa/City
                                     of Banning/City of Colton/City of
                                     Pasadena/City of Riverside.
EEI...............................  Edison Electric Institute.
Competitive Suppliers.............  Electric Power Supply Association/
                                     Independent Power Producers of New
                                     York/New England Power Generators
                                     Association/Western Power Trading
                                     Forum.
ELCON.............................  Electricity Consumers Resource
                                     Council.
ESA...............................  Energy Storage Association.
First Solar.......................  First Solar, Inc.
Idaho Power.......................  Idaho Power Company.
ISO-RTO Council...................  ISO-RTO Council.
MISO TOs..........................  Midcontinent Independent System
                                     Operator Transmission Owners.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
NERC..............................  North American Electric Reliability
                                     Corporation.
PG&E..............................  Pacific Gas and Electric Company.
Public Interest Organizations.....  Public Interest Organizations.
R Street..........................  R Street Institute.
SDG&E.............................  San Diego Gas & Electric Company.
SoCal Edison......................  Southern California Edison Company.
Sunflower and Mid-Kansas..........  Sunflower Electric Power Corporation
                                     and Mid-Kansas Electric Company,
                                     LLC.
SVP...............................  City of Santa Clara doing business
                                     as Silicon Valley Power.
TVA...............................  Tennessee Valley Authority.
Union of Concerned Scientists.....  Union of Concerned Scientists.
WIRAB.............................  Western Interconnection Regional
                                     Advisory Body.
Xcel..............................  Xcel Energy Services Inc.
------------------------------------------------------------------------

II. Appendix B: List of Substantive Supplemental Commenters (RM16-6-
000)

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

------------------------------------------------------------------------
AES Companies.....................  AES Corporation/AES Energy Storage/
                                     Dayton Power and Light Company/
                                     Indianapolis Power and Light
                                     Company.
APS...............................  Arizona Public Service Company.
Berkshire.........................  Berkshire Hathaway Energy.
CESA..............................  California Energy Storage Alliance.
EEI...............................  Edison Electric Institute.
EPRI..............................  Electric Power Research Institute.
ESA...............................  Energy Storage Association.
Idaho Power.......................  Idaho Power Company.
ISO-RTO Council...................  ISO-RTO Council.
ITC...............................  International Transmission Company.
MCAES.............................  Magnum CAES, LLC.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
NYTOs.............................  New York Transmission Owners.
NERC..............................  North American Electric Reliability
                                     Corporation.
NAGF..............................  North American Generator Forum.
SDG&E.............................  San Diego Gas & Electric Company.
SoCal Edison......................  Southern California Edison Company.
Sunrun............................  Sunrun, Inc.
Tri-State.........................  Tri-State Generation and
                                     Transmission Association, Inc.
WIRAB.............................  Western Interconnection Regional
                                     Advisory Body.
------------------------------------------------------------------------

III. Appendix C: Uniform System of Accounts

    Governor controls and similar electric equipment can be recorded
within the following Uniform System of Accounts account numbers by
function:

Production Plant

a. steam production
    313 Engines and engine-driven generators.
    314 Turbogenerator units.
    315 Accessory electric equipment.
    316 Miscellaneous power plant equipment.
b. nuclear production
    323 Turbogenerator units (Major only).
    324 Accessory electric equipment (Major only).
    325 Miscellaneous power plant equipment (Major only).
c. hydraulic production
    333 Water wheels, turbines and generators.
    334 Accessory electric equipment.
    335 Miscellaneous power plant equipment.
d. other production
    344 Generators.
    345 Accessory electric equipment.
    346 Miscellaneous power plant equipment.

Transmission Plant

    353 Station equipment.

Distribution Plant

    362 Station equipment.

[FR Doc. 2018-03707 Filed 3-5-18; 8:45 am]
 BILLING CODE 6717-01-P


[Federal Register Volume 87, Number 213 (Friday, November 4, 2022)]
[Notices]
[Pages 66695-66696]
[FR Doc No: 2022-24036]

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ENVIRONMENTAL PROTECTION AGENCY

[FRL OP-OFA-042]

Environmental Impact Statements; Notice of Availability

    Responsible Agency: Office of Federal Activities, General
Information<PHONE_NUMBER> or https://www.epa.gov/nepa.

Weekly receipt of Environmental Impact Statements (EIS)
Filed October 24, 2022 10 a.m. EST Through October 31, 2022 10 a.m. EST
Pursuant to 40 CFR 1506.9.

    Notice: Section 309(a) of the Clean Air Act requires that EPA make
public its comments on EISs issued by other Federal agencies. EPA's
comment letters on EISs are available at: https://cdxapps.epa.gov/cdx-enepa-II/public/action/eis/search.

EIS No. 20220157, Final, USFS, CA, Sugar Pine Project Water Right 15375
Extension and Radial Gates Installation, Review Period Ends: 12/05/
2022, Contact: Timothy Cardoza<PHONE_NUMBER>.
EIS No. 20220158, Draft, NNSA, CA, Draft Site-Wide Environmental Impact
Statement for Continued Operation of the Lawrence Livermore National
Laboratory, Comment Period Ends: 01/03/2023, Contact: Ms. Fana
Gebeyehu-Houston<PHONE_NUMBER>.
EIS No. 20220159, Draft, NASA, UT, Mars Sample Return (MSR) Campaign
Programmatic Environmental Impact Statement, Comment Period Ends: 12/
19/2022, Contact: Steve Slaten<PHONE_NUMBER>.

    Dated: October 31, 2022.
Cindy S. Barger,
Director, NEPA Compliance Division, Office of Federal Activities.
[FR Doc. 2022-24036 Filed 11-3-22; 8:45 am]
BILLING CODE 6560-50-P