[Federal Register Volume 83, Number 44 (Tuesday, March 6, 2018)]
[Rules and Regulations]
[Pages 9636-9677]
[FR Doc No: 2018-03707]

Vol. 83

Tuesday,

No. 44

March 6, 2018

Part III

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Essential Reliability Services and the Evolving Bulk-Power System--
Primary Frequency Response; Final Rule

Federal Register / Vol. 83 , No. 44 / Tuesday, March 6, 2018 / Rules
and Regulations

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM16-6-000; Order No. 842]

Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final action.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
modifying the pro forma Large Generator Interconnection Agreement
(LGIA) and pro forma Small Generator Interconnection Agreement (SGIA)
to require 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. These changes are designed to address the
potential reliability impact of the evolving generation resource mix,
and to ensure that the relevant provisions of the pro forma LGIA and
pro forma SGIA are just, reasonable, and not unduly discriminatory or
preferential.

DATES: This final action will become effective May 15, 2018.

FOR FURTHER INFORMATION CONTACT:
Jomo Richardson (Technical Information), Office of Electric
Reliability, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER>, [email protected].
Mark Bennett (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426,<PHONE_NUMBER>, [email protected].

SUPPLEMENTARY INFORMATION:

Order No. 842

Final Action

(Issued February 15, 2018)

Table of Contents

I. Background........................................                  4
    A. Frequency Response............................                  4
    B. Prior Commission Actions......................                  9
    C. Notice of Inquiry.............................                 10
    D. Notice of Proposed Rulemaking.................                 13
    E. Notice of Request for Supplemental Comments...                 16
II. Discussion.......................................                 19
    A. Requirement To Install, Maintain, and Operate                  28
     Equipment Capable of Providing Primary Frequency
     Response........................................
        1. NOPR Proposal.............................                 28
        2. Comments..................................                 29
        3. Commission Determination..................                 33
    B. Including Operating Requirements for Droop and                 40
     Deadband in the Pro Forma LGIA and Pro Forma
     SGIA............................................
        1. NOPR Proposal.............................                 40
        2. Comments..................................                 43
        3. Commission Determination..................                 56
    C. Requirement To Ensure the Timely and Sustained                 86
     Response to Frequency Deviations................
        1. NOPR Proposal.............................                 86
        2. Comments..................................                 88
        3. Commission Determination..................                 94
    D. Proposal Not To Mandate Headroom..............                106
        1. NOPR Proposal.............................                106
        2. Comments..................................                107
        3. Commission Determination..................                109
    E. Proposal Not To Mandate Compensation..........                111
        1. NOPR Proposal.............................                111
        2. Comments..................................                112
        3. Commission Determination..................                119
    F. Application to Existing Generating Facilities                 126
     That Submit New Interconnection Requests That
     Result in an Executed or Unexecuted
     Interconnection Agreement.......................
        1. NOPR Proposal.............................                126
        2. Comments..................................                127
        3. Commission Determination..................                131
    G. Application to Existing Generating Facilities                 135
     That Do Not Submit New Interconnection Requests
     That Result in an Executed or Unexecuted
     Interconnection Agreement.......................
        1. NOPR Proposal.............................                135
        2. Comments..................................                136
        3. Commission Determination..................                142
    H. Requests for Exemption or Special                             147
     Accommodation...................................
        1. Combined Heat and Power Facilities........                147
        2. Electric Storage Resources................                156
        3. Distributed Energy Resources..............                189
        4. Nuclear Generating Facilities.............                197
        5. Wind Generating Facilities................                203
        6. Surplus Interconnection...................                207
        7. Small Generating Facilities...............                210
        8. Requests To Establish a Waiver Process and                224
         Consider Potential Impact on Load and New
         Technology..................................
    I. Regional Flexibility..........................                231
        1. NOPR Proposal.............................                231
        2. Comments..................................                232
        3. Commission Determination..................                233
    J. Miscellaneous Comments........................                235
        1. Uniform System of Accounts................                235
        2. Capability of Load To Provide Primary                     237
         Frequency Response..........................

        3. Primary Frequency Response Obligations and                239
         Pools.......................................
    K. Specific Revisions to the Pro Forma LGIA and                  241
     Pro Forma SGIA..................................
        1. NOPR Proposal.............................                241
        2. Comments..................................                242
        3. Commission Determination..................                243
III. Compliance and Implementation...................                250
IV. Information Collection Statement.................                255
V. Regulatory Flexibility Act........................                262
VI. Environmental Analysis...........................                266
VII. Document Availability...........................                268
VIII. Effective Date and Congressional Notification..                271
I. Appendix A: List of Substantive NOPR Commenters
 (RM16-6-000)
II. Appendix B: List of Substantive Supplemental
 Commenters (RM16-6-000)
III. Appendix C: Uniform System of Accounts

162 FERC ] 61,128

United States of America

Federal Energy Regulatory Commission

    Before Commissioners: Kevin J. McIntyre, Chairman; Cheryl A.
LaFleur, Neil Chatterjee, Robert F. Powelson, and Richard Glick.

Essential Reliability Services and the Evolving Bulk-Power System--
Primary Frequency Response--Docket No. RM16-6-000

Order No. 842

Final Action

(Issued February 15, 2018)

    1. In this final action, the Commission modifies the pro forma
Large Generator Interconnection Agreement (LGIA) and the pro forma
Small Generator Interconnection Agreement (SGIA), pursuant to its
authority under section 206 of the Federal Power Act (FPA), to ensure
that rates, terms and conditions of jurisdictional service remain just
and reasonable and not unduly discriminatory or preferential.\1\ The
modifications require new large and small generating facilities,
including both synchronous and non-synchronous, interconnecting through
a LGIA or SGIA to install, maintain, and operate equipment capable of
providing primary frequency response as a condition of interconnection.
The Commission also establishes certain uniform minimum operating
requirements in the pro forma LGIA and pro forma SGIA, including
maximum droop and deadband parameters and provisions for timely and
sustained response.
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    \1\ 16 U.S.C. 824e.
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    2. These requirements apply to newly interconnecting generation
facilities that execute, or request the unexecuted filing of, an LGIA
or SGIA on or after the effective date of this final action. These
requirements also apply to 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. These requirements do not apply to existing
generating facilities,\2\ a subset of combined heat and power (CHP)
facilities, or generating facilities regulated by the Nuclear
Regulatory Commission (NRC). In addition, the Commission does not
impose a headroom requirement for new generating facilities, and does
not mandate that new generating facilities receive compensation for
complying with the primary frequency response requirements.
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    \2\ As discussed below in Section II.G, we will not impose
primary frequency response requirements on existing generating
facilities that do not submit new interconnection requests that
result in an executed or unexecuted interconnection agreement at
this time.
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    3. The modifications address the Commission's concerns that the
existing pro forma LGIA contains limited primary frequency response
requirements that apply only to synchronous generating facilities and
do not account for recent technological advancements that now enable
new non-synchronous generating facilities to have primary frequency
response capabilities. Further, the Commission believes that it is
unduly discriminatory or preferential to impose primary frequency
response requirements only on new large generating facilities but not
on new small generating facilities. The reforms adopted here impose
comparable primary frequency response requirements on both new large
and small generating facilities.

I. Background

A. Frequency Response

    4. Reliable operation of an Interconnection \3\ depends on
maintaining frequency within predetermined boundaries above and below a
scheduled value, which is 60 Hertz (Hz) in North America. Changes in
frequency are caused by changes in the balance between load and
generation, such as the sudden loss of a large generator or a large
amount of load. If frequency deviates too far above or below its
scheduled value, it could potentially result in under frequency load
shedding (UFLS), generation tripping, or cascading outages.\4\
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    \3\ An Interconnection is a geographic area in which the
operation of the electric system is synchronized. In the continental
United States, there are three Interconnections, namely, the
Eastern, Texas, and Western Interconnections.
    \4\ UFLS is designed to be activated in extreme conditions to
stabilize the balance between generation and load. Under frequency
protection schemes are drastic measures employed if system frequency
falls below a specified value. See Automatic Underfrequency Load
Shedding and Load Shedding Plans Reliability Standards, Notice of
Proposed Rulemaking, 76 FR 66220 (Oct. 26, 2011), FERC Stats. &
Regs. ] 32,682, at PP 4-10 (2011).
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    5. Mitigation of frequency deviations after the sudden loss of
generation or load is driven by three primary factors: inertial
response, primary frequency response, and secondary frequency
response.\5\ Primary frequency response actions begin within seconds
after system frequency changes and are mostly provided by the automatic
and autonomous actions (i.e., outside of system operator control) of
turbine-governors, while some response is provided by frequency
responsive loads.\6\ Primary frequency response actions are intended to
arrest abnormal frequency deviations and ensure that

system frequency remains within acceptable bounds. An important goal
for system planners and operators is for the frequency nadir,\7\ during
large disturbances, to remain above the first stage of UFLS set points
within an Interconnection.
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    \5\ In the Notice of Inquiry issued in Docket No. RM16-6-000 on
February 8, 2016, the Commission provided detailed discussion of how
inertia, primary frequency response, and secondary frequency
response interact to mitigate frequency deviations. Essential
Reliability Services and the Evolving Bulk-Power System--Primary
Frequency Response, 154 FERC ] 61,117, at PP 3-7 (2016) (NOI). See
also Use of Frequency Response Metrics to Assess the Planning and
Operating Requirements for Reliable Integration of Variable
Renewable Generation, Lawrence Berkeley National Laboratory, at 13-
14 (Dec. 2010), http://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf
(LBNL 2010 Report).
    \6\ NOI, 154 FERC ] 61,117 at P 6. The Commission also noted
that regulation service is different than primary frequency response
because generating facilities that provide regulation respond to
automatic generation control signals and regulation service is
centrally coordinated by the system operator, whereas primary
frequency response service, in contrast, is autonomous and is not
centrally coordinated. Schedule 3 of the pro forma Open Access
Transmission Tariff (OATT) bundles these different services
together. See id. n.66.
    \7\ The point at which the frequency decline is arrested
(following the sudden loss of generation) is called the frequency
nadir, and represents the point at which the net primary frequency
response (real power) output from all generating units and the
decrease in power consumed by the load within an Interconnection
matches the net initial loss of generation (in megawatts (MW)).
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    6. Frequency response is a measure of an Interconnection's ability
to arrest and stabilize frequency deviations following the sudden loss
of generation or load, and is affected by the collective responses of
generation and load throughout the Interconnection. When considered in
aggregate, the primary frequency response provided by generators within
an Interconnection has a significant impact on the overall frequency
response. Reliability Standard BAL-003-1.1 defines the amount of
frequency response needed from balancing authorities \8\ to maintain
Interconnection frequency within predefined bounds and includes
requirements for the measurement and provision of frequency
response.\9\ While Reliability Standard BAL-003-1.1 establishes
requirements for balancing authorities, it does not include any
requirements applicable to individual generator owners or
operators.\10\
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    \8\ NERC's Glossary of Terms defines a balancing authority as
``(t)he responsible entity that integrates resource plans ahead of
time, maintains load-interchange-generation balance within a
balancing authority area, and supports Interconnection frequency in
real time.'' NERC's Glossary of Terms is available at: http://www.nerc.com/files/glossary_of_terms.pdf.
    \9\ Frequency Response and Frequency Bias Setting Reliability
Standard, Order No. 794, 146 FERC ] 61,024 (2014).
    \10\ The Commission has also accepted Regional Reliability
Standard BAL-001-TRE-01 (Primary Frequency Response in the ERCOT
Region) as mandatory and enforceable, which does establish
requirements for generator owners and operators with respect to
governor control settings and the provision of primary frequency
response within the Electric Reliability Council of Texas (ERCOT)
region. North American Electric Reliability Corporation, 146 FERC ]
61,025 (2014).
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    7. Unless otherwise required by tariffs or interconnection
agreements, generator owners and operators can independently decide
whether to configure their generating facilities to provide primary
frequency response.\11\ The magnitude and duration of a generating
facility's response to frequency deviations is generally determined by
the settings of the facility's governor \12\ (or equivalent controls)
and other plant-level (e.g., ``outer-loop'') control systems.\13\ In
particular, the governor's droop and deadband settings have a
significant impact on the unit's provision of primary frequency
response. In addition, plant-level controls, unless properly
configured, can override or nullify a generator's governor response and
return the unit to operate at a scheduled pre-disturbance megawatt set-
point.\14\ In 2010, NERC conducted a survey of generator owners and
operators and found that only approximately 30 percent of generating
facilities in the Eastern Interconnection provided primary frequency
response, and that only approximately 10 percent of generating
facilities provided sustained primary frequency response.\15\ This
suggests that many generating facilities within the Eastern
Interconnection disable or otherwise set their governors or plant-level
controls such that they provide little to no primary frequency
response.\16\
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    \11\ See NOI, 154 FERC ] 61,117 at PP 18-19.
    \12\ A governor is an electronic or mechanical device that
implements primary frequency response on a generating facility via a
droop parameter. Droop refers to the variation in real power (MW)
output due to variations in system frequency and is typically
expressed as a percentage (e.g., 5 percent droop). Droop reflects
the amount of frequency change from nominal (e.g., 5 percent of 60
Hz is 3 Hz) that is necessary to cause the main prime mover control
mechanism of a generating facility to move from fully closed to
fully open. A governor also has a deadband parameter which
represents a minimum frequency deviation (e.g., 0.036
Hz) from nominal system frequency (i.e., 60 Hz in North America)
that must be exceeded in order for the generating facility to
provide primary frequency response.
    \13\ These controls are known as plant-level or outer-loop
controls to distinguish them from more direct, lower-level control
of the generator operations.
    \14\ For more discussion on ``premature withdrawal'' of primary
frequency response, see NOI, 154 FERC ] 61,117 at PP 49-50.
    \15\ See NERC, Frequency Response Initiative Report: The
Reliability Role of Frequency Response (Oct. 2012), http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf
(NERC Frequency Response Initiative Report) at 95. For the purposes
of this final action, as indicated below in the revised pro forma
language in Section K, sustained response refers to a generating
facility responding to an abnormal frequency deviation outside of
the deadband parameter, and holding (i.e., not prematurely
withdrawing) the response until system frequency returns to a value
that is within the deadband.
    \16\ However, as noted below, some commenters note that nuclear
generating facilities are restricted by their NRC operating licenses
regarding the provision of primary frequency response.
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    8. Declining frequency response performance has been an industry
concern for many years. NERC, in conjunction with the Electric Power
Research Institute (EPRI), initiated its first examination of declining
frequency response and governor response in 1991.\17\ More recently, as
noted in the NOI, while the three U.S. Interconnections currently
exhibit adequate frequency response performance above their
Interconnection Frequency Response Obligations,\18\ there has been a
decline in the frequency response performance of the Western and
Eastern Interconnections from historic values.\19\
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    \17\ NERC Frequency Response Initiative Report at 22.
    \18\ The Interconnection Frequency Response Obligations are
established by NERC and are designed to require sufficient frequency
response for each Interconnection (i.e., the Eastern, ERCOT, Quebec,
and Western Interconnections) to arrest frequency declines even for
severe, but possible, contingencies.
    \19\ NOI, 154 FERC ] 61,117 at P 20.
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B. Prior Commission Actions

    9. In Order Nos. 2003 \20\ and 2006,\21\ the Commission adopted
standard procedures for the interconnection of large and small
generating facilities, including the development of standardized pro
forma generator interconnection agreements and procedures. The
Commission required public utility transmission providers \22\ to file
revised OATTs containing these standardized provisions, and use the
LGIA and SGIA to provide non-discriminatory interconnection service to
Large Generators (i.e., generating facilities having a capacity of more
than 20 MW) and Small Generators (i.e., generators having a capacity of
no more than 20 MW). The pro forma LGIA and pro forma SGIA have since
been revised through various subsequent proceedings.\23\
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    \20\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
    \21\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ]
31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs. ]
31,196 (2005), order granting clarification, Order No. 2006-B, FERC
Stats. & Regs. ] 31,221 (2006).
    \22\ 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)
(2012). 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. See Order No. 2003,
FERC Stats. & Regs. ] 31,146 at PP 840-845.
    \23\ E.g., Small Generator Interconnection Agreements and
Procedures, Order No. 792, 145 FERC ] 61,159 (2013), clarifying,
Order No. 792-A, 146 FERC ] 61,214 (2014); Reactive Power
Requirements for Non-Synchronous Generation, Order No. 827, FERC
Stats. & Regs. ] 31,385 (2016) (cross-referenced at 155 FERC ]
61,277) (2016); Requirements for Frequency and Voltage Ride Through
Capability of Small Generating Facilities, Order No. 828, 156 FERC ]
61,062 (2016).

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C. Notice of Inquiry

    10. On February 18, 2016, the Commission issued the NOI to explore
issues regarding essential reliability services and the evolving Bulk-
Power System.\24\ In particular, the Commission asked a broad range of
questions on the need for reform of its requirements regarding the
provision of and compensation for primary frequency response. The
Commission explained that there is a significant risk that, as
conventional synchronous generating facilities retire or are displaced
by increased numbers of variable energy resources (VERs),\25\ which
typically do not contribute to system inertia \26\ or have primary
frequency response capabilities, the net amount of frequency responsive
generation online will be reduced.\27\
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    \24\ NOI, 81 FR 9182 (Feb. 24, 2016), 154 FERC ] 61,117.
    \25\ The term VER is defined as a device for the production of
electricity that is characterized by an energy source that: (1) Is
renewable; (2) cannot be stored by the facility owner or operator;
and (3) has variability that is beyond the control of the facility
owner or operator. See, e.g., Integration of Variable Energy
Resources, Order No. 764, FERC Stats. & Regs. ] 31,331 at P 210,
order on reh'g and clarification, Order No. 764-A, 141 FERC ] 61,232
(2012), order on clarification and reh'g, Order No. 764-B, 144 FERC
] 61,222 (2013).
    \26\ Inertial response, or system inertia, involves the release
or absorption of kinetic energy by the rotating masses of online
generation and load within an Interconnection, and is the result of
the coupling between the rotating masses of synchronous generation
and load and the electric system. See NOI, 154 FERC ] 61,117 at PP
3-7 for a more detailed discussion of how inertia, primary frequency
response, and secondary frequency response interact to mitigate
frequency deviations.
    \27\ NOI, 154 FERC ] 61,117 at P 12.
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    11. In the NOI, the Commission also explained that these
developments and their potential impacts could challenge system
operators in maintaining system frequency within acceptable bounds
following system disturbances.\28\ Further, the Commission explained
that Reliability Standard BAL-003-1.1 and the pro forma LGIA and pro
forma SGIA do not specifically address a generator's ability to provide
frequency response.\29\ The Commission noted, however, that while in
previous years many non-synchronous generating facilities \30\ were not
designed with primary frequency response capabilities, the technology
now exists for new non-synchronous generating facilities to install
primary frequency response capability.\31\
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    \28\ Id. P 14.
    \29\ Id. P 41.
    \30\ Non-synchronous generating facilities are ``connected to
the bulk power system through power electronics, but do not produce
power at system frequency (60 Hz).'' They ``do not operate in the
same way as traditional generators and respond differently to
network disturbances.'' PJM Interconnection, L.L.C., 151 FERC ]
61,097, at P 1 n.3 (2015) (citing Interconnection for Wind Energy,
Order No. 661, FERC Stats. & Regs. ] 31,198, at P 3 n.4 (2005)).
Wind and solar photovoltaic generating facilities as well as
electric storage resources are examples of non-synchronous
generating facilities.
    \31\ NOI, 154 FERC ] 61,117 at P 43.
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    12. Accordingly, the Commission requested comments on three main
sets of issues. First, the Commission sought comment on whether
amendments to the pro forma LGIA and pro forma SGIA are warranted to
require all new generating facilities, both synchronous and non-
synchronous, to have primary frequency response capabilities as a
precondition of interconnection.\32\ Second, the Commission sought
comment on the performance of existing generating facilities and
whether primary frequency response requirements for these facilities
are warranted.\33\ Finally, the Commission sought comment on
compensation for primary frequency response.\34\
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    \32\ Id. PP 2 and 44-45.
    \33\ Id. PP 2, 46, and 52.
    \34\ Id. PP 2, 53-54.
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D. Notice of Proposed Rulemaking

    13. On November 17, 2016, the Commission issued a Notice of
Proposed Rulemaking that proposed to revise the pro forma LGIA and the
pro forma SGIA to require all newly interconnecting large and small
generating facilities, both synchronous and non-synchronous, to install
and enable primary frequency response capability as a condition of
interconnection.\35\ The Commission also proposed to establish certain
operating requirements in the pro forma LGIA and pro forma SGIA,
including maximum droop and deadband parameters, and provisions for
timely and sustained response.
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    \35\ Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response, Notice of Proposed Rulemaking,
81 FR 85176 (Nov. 25, 2016), 157 FERC ] 61,122 (2016) (NOPR).
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    14. The Commission sought comment on the proposed: (1) Requirements
for new large and small generating facilities to install, maintain, and
operate a governor or equivalent controls; (2) requirements for droop
and deadband settings of 5 percent and 0.036 Hz,
respectively; (3) requirements for timely and sustained response, and
in particular whether the proposed requirements will be sufficient to
prevent plant-level controls from inhibiting primary frequency
response; (4) requirement for droop parameters to be based on nameplate
capability with a linear operating range of 59 to 61 Hz; and (5)
exemptions for new nuclear units. The Commission also sought comment on
its proposal to not impose a generic headroom requirement or mandate
compensation related to the proposed reforms.
    15. Twenty-eight entities submitted comments in response to the
NOPR and are listed in Appendix A to this final action.

E. Notice of Request for Supplemental Comments

    16. On August 18, 2017, the Commission issued a Notice of Request
for Supplemental Comments (Supplemental Notice) to augment the record
on the potential impacts of the NOPR proposals on electric storage
resources \36\ and small generating facilities.\37\ In particular, the
Commission stated that the NOPR did not contain any special
consideration or provisions for electric storage resources, and that
some commenters raised concerns that, by failing to address electric
storage resources' unique technical attributes, the proposed
requirements could pose an unduly discriminatory burden on electric
storage resources.\38\ In response to commenters' concerns, the
Commission asked several questions to augment the record on possible
impacts to electric storage facilities.\39\
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    \36\ For the purposes of this final action, we define an
electric storage resource as a resource capable of receiving
electric energy from the grid and storing it for later injection of
electric energy back to the grid. This definition is also used in a
concurrently-issued Final Rule, published elsewhere in this issue of
the Federal Register, concerning electric storage resources entitled
Electric Storage Participation in Markets Operated by Regional
Transmission Organizations and Independent System Operators, 162
FERC ] 61,127 (2018).
    \37\ Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response, Notice of Request for
Supplemental Comments, 82 FR 40081 (Aug. 24, 2017), 160 FERC ]
61,011 (2017).
    \38\ Id. P 4.
    \39\ Id. P 6.
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    17. In addition, the Commission stated that the NOPR proposed that
small generating facilities be subject to new primary frequency
response requirements in the pro forma SGIA, and that some commenters
raised concerns that small generating facilities could face
disproportionate costs to install primary frequency response
capability,\40\ while other commenters requested that the Commission
consider adopting a size limitation.\41\ In response to commenters'
concerns, the Commission asked several questions to augment the record
on small generating facilities.\42\
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    \40\ Id. P 8.
    \41\ Id. P 9.
    \42\ Id. P 10.
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    18. Twenty entities submitted comments in response to the notice of

request for supplemental comments and are listed in Appendix B to this
final action.

II. Discussion

    19. For the reasons discussed below, the Commission adopts the NOPR
proposal and will require newly interconnecting large and small
generating facilities that interconnect pursuant to the pro forma LGIA
or pro forma SGIA, to install, maintain, and operate a functioning
governor or equivalent controls capable of providing primary frequency
response. The reforms adopted here build upon Order Nos. 2003 and 2006
by accounting for the effect upon primary frequency response from the
ongoing changes to the nation's generation resource mix, including
significant retirements of conventional generating facilities and an
increasing proportion of VERs interconnecting to the Bulk-Power
System.\43\ Another important consideration is that the frequency
response performance of the Eastern and Western Interconnections, while
currently adequate, has significantly declined from historic
values.\44\ NERC has found that ``increasing levels of non-synchronous
resources installed without controls that enable frequency response
capability, coupled with retirement of conventional generating
facilities that have traditionally provided primary frequency response,
have contributed to the decline in primary frequency response.'' \45\
Finally, the record in this proceeding indicates that VER equipment
manufacturers have made significant technological advancements in
developing primary frequency response capability for VERs, and that the
costs of this capability have declined over time.\46\ For all of these
reasons, we find that the pro forma LGIA and pro forma SGIA are no
longer just and reasonable, and are unduly discriminatory or
preferential, and thus need to be revised to ensure that all newly
interconnecting large and small generating facilities have primary
frequency response capability as a condition of interconnection.\47\
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    \43\ Section 215(a)(1) of the FPA, 16 U.S.C. 824o(a)(1) (2012)
defines ``Bulk-Power System'' as those ``facilities and control
systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof) [and] electric energy
from generating facilities needed to maintain transmission system
reliability.'' The term does not include facilities used in the
local distribution of electric energy. See also Mandatory
Reliability Standards for the Bulk-Power System, Order No. 693, FERC
Stats. & Regs. ] 31,242, at P 76 (cross-referenced at 118 FERC ]
61,218), order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007).
    \44\ See NOPR, 157 FERC ] 61,122 at P 36 (citing NERC Frequency
Response Initiative Industry Advisory--Generator Governor Frequency
Response, at slide 10 (Apr. 2015), http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. See
also NERC Frequency Response Initiative Report at 22, and LBNL 2010
Report at xiv-xv).
    \45\ NERC Comments at 5. NERC's Essential Reliability Services
Task Force has determined that primary frequency response is an
``essential reliability service.'' Essential reliability services
are referred to as elemental reliability building blocks from
resources (generation and load) that are necessary to maintain the
reliability of the Bulk-Power System. See Essential Reliability
Services Task Force Scope Document, at 1 (Apr. 2014), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
    \46\ NOPR, 157 FERC ] 61,122 at PP 28, 36.
    \47\ 16 U.S.C. 824e. The Commission routinely evaluates the
effectiveness of its regulations and policies in light of changing
industry conditions to determine if changes in these conditions and
policies are necessary. See, e.g., Order No. 764, FERC Stats. &
Regs. ] 31,331.
---------------------------------------------------------------------------

    20. We find that the current requirements for governor controls in
the pro forma LGIA do not reflect NERC's currently recommended
operating practices or recent advances in technology for non-
synchronous generating facilities, as discussed below.
    21. First, Article <IP_ADDRESS> of the pro forma LGIA does not address
the settings of governors or equivalent controls (i.e., deadband and
droop), nor does Article <IP_ADDRESS> address plant-level controls, which if
not properly coordinated on a generating facility, can lead to the
premature withdrawal of primary frequency response during disturbances.
Furthermore, the substantial body of knowledge regarding the operation
of generator governors and plant control systems amassed by NERC and
industry stakeholders since the pro forma LGIA was promulgated under
Order No. 2003 raises concerns that Article <IP_ADDRESS> of the pro forma
LGIA allows too much discretion for generator owners and operators. For
example, in 2012, NERC found that a number of generators implemented
deadband settings that were so wide as to effectively disable
themselves from providing primary frequency response, and also that
many generators provide frequency response in the wrong direction
during a disturbance.\48\ In addition, in 2015, NERC observed that: (1)
For many conventional steam plants, deadband settings exceeded 0.036 Hz; (2) several generating facilities failed to sustain
primary frequency response; and (3) the vast majority of the gas
turbine fleet was not frequency responsive.\49\
---------------------------------------------------------------------------

    \48\ NERC Frequency Response Initiative Report at 92, 96-97.
    \49\ NOI, 154 FERC ] 61,117 at P 50 (citing NERC Generator
Governor Frequency Response Advisory--Webinar Questions and Answers
at 1 (April 2015), http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_QandA_April_2015.pdf.).

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

    22. Second, existing Article <IP_ADDRESS> of the pro forma LGIA states
that ``speed governors,'' if installed, must be operated in automatic
mode. However, instead of utilizing traditional speed governors to
implement primary frequency response capability, many new non-
synchronous generating facilities interconnecting to the grid, such as
wind, solar, and electric storage resources, utilize enhanced inverters
and other plant control technology that can be designed to include
primary frequency response capability.\50\ We find that due to these
recent technological advancements that allow new large non-synchronous
generating facilities to install primary frequency response capability
at low cost, as well as the expected overall increase of the proportion
of the resource mix that are non-synchronous generating facilities, it
is unduly discriminatory and preferential to only require synchronous
generators to provide primary frequency response. The references to
``speed governors'' in existing Article <IP_ADDRESS> of the pro forma LGIA,
which are only applicable to large synchronous generating facilities,
are outdated and should be expanded to include both synchronous and
non-synchronous generators.
---------------------------------------------------------------------------

    \50\ See Electric Power Research Institute, Recommended Settings
for Voltage and Frequency Ride-Through of Distributed Energy
Resources at 27(May 2015), http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002006203. See also National
Renewable Energy Labs (NREL), Advanced Grid-Friendly Controls
Demonstration Project for Utility-Scale PV Power Plants, at 1-2
(Jan. 2016), http://www.nrel.gov/docs/fy16osti/65368.pdf.
---------------------------------------------------------------------------

    23. Investigation by various NERC task forces and subcommittees has
led to a voluntary NERC Primary Frequency Control Guideline that
includes recommended droop and deadband settings for generating
facilities within all three U.S. Interconnections.\51\ However, as
noted in the NOPR, the pro forma LGIA and pro forma SGIA do not
currently reflect these updated recommended practices by NERC for
governor and plant control system settings of generating
facilities.\52\
---------------------------------------------------------------------------

    \51\ See NERC's Primary Frequency Control Guideline.
    \52\ NOPR, 157 FERC ] 61,122 at P 39.
---------------------------------------------------------------------------

    24. We also find that revisions to the pro forma LGIA and pro forma
SGIA are necessary to provide for the continued reliable operation of
the Bulk-Power System by addressing the potential adverse impacts on
primary frequency response of the nation's evolving generation resource
mix described in the NOI.\53\ As noted in the NOPR,

NERC's Essential Reliability Services Task Force concluded that primary
frequency response capability should be required of all new generating
facilities.\54\ However, the pro forma LGIA and the pro forma SGIA do
not currently require generating facilities to install such capability.
---------------------------------------------------------------------------

    \53\ NOI, 154 FERC ] 61,117 at PP 13-17 (citing to the Essential
Reliability Services Task Force Measures Report at iv).
    \54\ NOPR, 157 FERC ] 61,122 at P 15.
---------------------------------------------------------------------------

    25. Further, the limited references to primary frequency response
in the Commission's requirements apply only to large generating
facilities. Based on the absence of a technical or economic basis for
the different requirements imposed on small and large generating
facilities, and the significant technological advancements that
manufacturers have made in developing primary frequency response
capability for VERs, we find that the absence of any similar provisions
in the current pro forma SGIA is unduly discriminatory or preferential.
    26. The Commission has previously acted under FPA section 206 to
remove inconsistencies between the pro forma LGIA and pro forma SGIA
when there is no economic or technical basis for treating large and
small generating facilities differently.\55\ As discussed more fully
below in Section II.H.7, the record developed in this proceeding
indicates that small generating facilities are capable of installing
and enabling governors or equivalent controls at a low cost and in a
manner comparable to large generating facilities.\56\ Given these low-
cost technological advances, we do not anticipate that these additional
requirements added to the pro forma SGIA will present a barrier to
entry for small generating facilities. Thus, in light of the need for
additional primary frequency response capability and an increasingly
large market penetration of small generating facilities, we believe
that there is a need to add these requirements to the pro forma SGIA to
help ensure adequate primary frequency response capability.
---------------------------------------------------------------------------

    \55\ 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).
    \56\ See, e.g., IEEE-P1547 Working Group NOI Comments at 1, 5,
and 7; ISO-RTO Council Supplemental Comments at 7; SoCal Edison
Supplemental Comments at 3; WIRAB Supplemental Comments at 7.
Moreover, the Commission notes that other commenters stated costs of
installing primary frequency response capability are generally low,
but did not differentiate between small and large generating
facilities. See, e.g., APPA, et al. Comments at 6; California Cities
Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at
3-5; SoCal Edison Comments at 2.
---------------------------------------------------------------------------

    27. Accordingly, we find that revising the pro forma LGIA and pro
forma SGIA to require all new generating facilities to install,
maintain, and operate a functioning governor or equivalent controls,
consistent with the exceptions and operating requirements described
below, is just and reasonable. Doing so will help to ensure adequate
primary frequency response capability as the generation resource mix
continues to evolve, ensure fair and consistent treatment for all types
of generating facilities, help balancing authorities meet their
frequency response obligations pursuant to Reliability Standard BAL-
003-1.1, and help improve reliability, particularly during system
restoration and islanding situations.\57\
---------------------------------------------------------------------------

    \57\ NOPR, 157 FERC ] 61,122 at P 43.
---------------------------------------------------------------------------

A. Requirement To Install, Maintain, and Operate Equipment Capable of
Providing Primary Frequency Response

1. NOPR Proposal
    28. In the NOPR, the Commission proposed to revise the pro forma
LGIA and pro forma SGIA to include requirements for new 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.\58\ In
particular, the Commission explained that the proposed revisions would
require new large and small generating facilities to install, maintain,
and operate a functioning governor or equivalent controls, which the
Commission proposed to define as 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
generating facility's real power output in accordance with the proposed
maximum droop and deadband parameters and in the direction needed to
correct frequency deviations.\59\
---------------------------------------------------------------------------

    \58\ Id. P 44.
    \59\ Id. P 47.
---------------------------------------------------------------------------

2. Comments
    29. The proposed requirement for new generating facilities to
install the necessary equipment for primary frequency response
capability as a condition of interconnection received broad support
from commenters.\60\ For example, APPA et al. state that requiring
newly interconnecting generating facilities to install governors or
equivalent control devices is a relatively low-cost way to prevent the
erosion of the Interconnections' collective frequency response
capability as the generation resource mix evolves.\61\ APPA et al.
state that primary frequency response capability should be a standard
feature and part of the ``rules of the road'' for all new generating
facilities, similar to how all new cars come equipped with anti-lock
brakes.\62\ Bonneville asserts that the trend of declining frequency
response capability will continue with a changing generation resource
mix (namely, the integration of large amounts of VERs), unless
provisions are put in place to ensure that adequate primary frequency
response capability is available in the future.\63\ As a result,
Bonneville believes that it is necessary to require newly
interconnecting generating facilities to have primary frequency
response capability.\64\ EEI states that now that the technology is
available and economical for non-synchronous generation facilities, it
supports the proposed requirement for these facilities to install the
equipment needed to provide primary frequency response.\65\
---------------------------------------------------------------------------

    \60\ APPA et al., Bonneville, California Cities, EEI, ESA,
Competitive Suppliers, First Solar, Idaho Power (for generating
facilities larger than 10 MW), ISO-RTO Council, MISO TOs, NERC,
PG&E, SoCal Edison, SVP, Tri-State, Xcel, and WIRAB support the
requirement for new generating facilities to install governors or
equivalent controls. In addition, AWEA states that it does not
oppose a primary frequency response capability requirement.
    \61\ APPA et al. Comments at 6.
    \62\ Id.
    \63\ Bonneville Comments at 2.
    \64\ Id.
    \65\ EEI Comments at 2.
---------------------------------------------------------------------------

    30. NERC states that it has determined that increasing levels of
non-synchronous generating facilities installed without controls that
enable frequency response capability, coupled with retirement of
conventional generating facilities that have traditionally provided
primary frequency response, has contributed to the decline in primary
frequency response.\66\ NERC further states that a changing generation
resource mix will further alter the dispatch of generating facilities,
potentially resulting in operating conditions where frequency response
capability could be diminished unless a sufficient amount of frequency
responsive capacity is included in the dispatch.\67\ NERC asserts that
the NOPR's proposed revisions would apply measurable, clear
requirements to newly interconnecting synchronous and non-synchronous
generating facilities.\68\ Tri-State comments that primary frequency
response requirements for all generating facilities are necessary to
address the

decline in frequency response and are in the best interest of
industry.\69\ ISO-RTO Council adds that a number of Regional
Transmission Operators (RTOs) and Independent System Operators (ISOs)
have, for several years, had similar requirements to those proposed in
the NOPR, and as a result, the Commission's proposal does not create
significant burdens as it merely extends these existing ``best
practices'' nationwide.\70\ SVP states that the NOPR proposals should
not create a major hardship in terms of costs or other burdens related
to installing frequency response capability.\71\ SoCal Edison states
that there is neither a technological nor an economic reason not to
require primary frequency response capability of small and/or non-
synchronous generating facilities.\72\
---------------------------------------------------------------------------

    \66\ NERC Comments at 5.
    \67\ Id.
    \68\ Id.
    \69\ Tri-State Supplemental Comments at 3.
    \70\ ISO-RTO Council Comments at 2.
    \71\ SVP Comments at 2.
    \72\ SoCal Edison Comments at 2.
---------------------------------------------------------------------------

    31. On the other hand, some commenters do not support a requirement
for new generating facilities to install, maintain, and operate primary
frequency response capability as a condition of interconnection.\73\
For example, API states that primary frequency response operation may
not be required from all generating facilities since it is possible for
balancing authorities to have a sufficient number of existing
generating facilities with primary frequency response capability.\74\
APS argues that more time is needed to measure and understand the
effect of Reliability Standard BAL-003-1.1 on frequency response before
mandating primary frequency response capability.\75\ Chelan County adds
that while it may be true that it is more cost effective to install
primary frequency response capability during a generating facility's
initial construction (as opposed to retrofitting an already-existing
generating facility) and the costs of doing so may be nominal, the
Commission should not require generating facilities to provide primary
frequency response as a condition of interconnection.\76\ NRECA asserts
that the proposal could have adverse impacts on deployment of non-
traditional generation sources without conferring reliability benefits
that warrant such risks.\77\ Therefore, NRECA asserts that if the
Commission proceeds to require primary frequency response capability as
a condition of interconnection, then the Commission should provide for
flexibility to balance the reliability needs with possible costs and
the desire to encourage new generating facilities by: (1) Considering a
size threshold, whereby new generators under a certain size are not
required to have primary frequency response capability; (2)
establishing penetration level thresholds for primary frequency
response requirements; or (3) allowing for a waiver process.\78\
---------------------------------------------------------------------------

    \73\ See, e.g., API Comments at 2; APS Supplemental Comments at
12; Chelan County Comments at 1; NRECA Comments at 2; Public
Interest Organizations Comments at 4; R Street Comments at 2; SDG&E
Comments at 1; Sunflower and Mid-Kansas Comments at 2.
    \74\ API Comments at 4.
    \75\ APS Supplemental Comments at 12.
    \76\ Chelan County Comments at 1.
    \77\ NRECA Comments at 6.
    \78\ Id. at 8-9.
---------------------------------------------------------------------------

    32. In addition, some of these commenters request that the
Commission reconsider its proposal to mandate the installation of
specific equipment on all new generating facilities (or the operation
of such equipment as proposed in the NOPR) as a condition of
interconnection, and to instead direct market-based or cost-based
approaches to ensure adequate levels of primary frequency response.\79\
---------------------------------------------------------------------------

    \79\ See, e.g., API Comments at 2; Chelan County Comments at 1;
Public Interest Organizations Comments at 4; R Street Comments at 2-
3; SDG&E Comments at 1, 3-4.
---------------------------------------------------------------------------

3. Commission Determination
    33. We adopt the NOPR proposal to revise the pro forma LGIA and pro
forma SGIA to include requirements for new 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, with certain exemptions and special
accommodations as discussed below in Section II.H.
    34. We adopt the NOPR proposal to define ``functioning governor or
equivalent controls'' as 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
generating facility's real power output in accordance with maximum
droop and deadband parameters and in the direction needed to correct
frequency deviations.\80\
---------------------------------------------------------------------------

    \80\ NOPR, 157 FERC ] 61,122 at P 47.
---------------------------------------------------------------------------

    35. The proposal to require new generating facilities to install
equipment capable of providing primary frequency response received
broad support from commenters.\81\ We find compelling these commenters'
observations that requiring newly interconnecting generating facilities
to install governors or equivalent control devices is a low cost way to
address the erosion of the Interconnections' collective frequency
response capability as the generation resource mix evolves. As
assessments by NERC, the Essential Reliability Services Task Force, and
others confirm, ongoing changes to the generation resource mix are
altering the composition and dispatch of generating facilities across
the daily and seasonal demand spectrum. The resulting operating
conditions have affected frequency response capability and the amount
of frequency responsive capacity online at any given moment. We believe
that the revisions to the pro forma LGIA and pro forma SGIA adopted
here will address this problem by providing that the future generation
resource mix has frequency responsive capacity available for dispatch
by system operators to maintain system reliability.
---------------------------------------------------------------------------

    \81\ APPA et al., Bonneville, California Cities, EEI, ESA,
Competitive Suppliers, First Solar, Idaho Power (for generating
facilities larger than 10 MW), ISO-RTO Council, MISO TOs, NERC,
PG&E, SoCal Edison, SVP, Tri-State, Xcel, and WIRAB support the
requirement for new generating facilities to install governors or
equivalent controls.
---------------------------------------------------------------------------

    36. We acknowledge that some commenters do not support a
requirement for all newly interconnecting generating facilities to
install, maintain, and operate governors or equivalent controls.\82\
Some of these commenters only support a requirement for newly
interconnecting generating facilities to install primary frequency
response capability as a condition of interconnection, but do not
support including the proposed operating requirements in the pro forma
LGIA and pro forma SGIA.\83\ These commenters either advocate for
regional flexibility (i.e., allowing the transmission provider or the
balancing authority to establish regional requirements) or request
exemption or special accommodation of the requirements for particular
technology types (e.g., electric storage resources and CHP facilities).
Comments that request regional flexibility for individual transmission
providers or balancing authorities to establish operating requirements
are addressed below in Section II.B. Comments that request a special
accommodation for certain types of generating facilities, including but
not limited to electric storage and CHP facilities are addressed below
in Section II.H.
---------------------------------------------------------------------------

    \82\ See, e.g., API Comments at 2; APS Supplemental Comments at
12; Chelan County Comments at 1; NRECA Comments at 2; Public
Interest Organizations Comments at 4; R Street Comments at 2; SDG&E
Comments at 1; Sunflower and Mid-Kansas Comments at 2.
    \83\ See, e.g., AES Companies Comments at 6; EEI Comments at 8;
MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel
Comments at 7.

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

    37. Rather than uniform requirements in the pro forma LGIA and pro
forma SGIA, some commenters prefer market-based or cost-based
compensation mechanisms to ensure sufficient primary frequency response
capability, and urge the Commission to consider the economic impacts of
the proposed requirements on load. Comments related to compensation are
addressed below in Section II.E. Comments related to the impacts on
load are addressed below in Section II.H.8.
    38. Finally, some commenters assert that the Commission should: (1)
Consider a size threshold; (2) establish penetration level thresholds
for primary frequency response requirements; (3) allow for a waiver
process; and (4) establish primary frequency response pools. These
comments are addressed below in Sections II.H and II.J.
    39. Accordingly, as a result of this final action, new large and
small generating facilities, will be required to install, maintain, and
operate a functioning governor or equivalent controls with certain
exemptions or accommodations for nuclear generating facilities,
electric storage facilities, and combined heat and power facilities as
discussed below.

B. Including Operating Requirements for Droop and Deadband in the Pro
Forma LGIA and Pro Forma SGIA

1. NOPR Proposal
    40. In the NOPR, the Commission proposed to include minimum
operating requirements for droop and deadband for governors or
equivalent controls.\84\ In particular, the Commission proposed to
require new generating facilities to install, maintain, and operate
governor or equivalent controls with the ability to operate with a
maximum 5 percent droop and 0.036 Hz deadband parameter,
consistent with NERC's recommended guidance.\85\
---------------------------------------------------------------------------

    \84\ NOPR, 157 FERC ] 61,122 at P 48.
    \85\ Id.
---------------------------------------------------------------------------

    41. The Commission also proposed to require the droop parameter to
be based on the nameplate capability of the generating facility and
linear in operating range between 59 and 61 Hz.\86\ The Commission
explained that this provision is reasonable because it would allow for
new generating facilities that remain connected during frequency
deviations (and have operating capability, e.g., headroom; \87\ or
floor-room \88\ at the time of the disturbance) to provide a
proportional response within this range of frequencies.\89\
---------------------------------------------------------------------------

    \86\ Id. P 50.
    \87\ For the purposes of this final action, headroom refers to
the difference between the current operating point of a generating
facility and its maximum operating capability, and represents the
potential amount of additional energy that can be provided by the
generating facility in real-time. See NOPR, 157 FERC ] 61,122 at
n.27.
    \88\ For the purposes of this final action, floor-room refers to
the difference between the current operating point of a generating
facility and its minimum operating capability, and represents the
potential amount of additional energy that can be withdrawn by the
generating facility in real-time. Stated differently, a generating
facility with floor-room will have the capability to reduce its MW
output in response to a frequency deviation.
    \89\ See NOPR, 157 FERC ] 61,122 at P 50.
---------------------------------------------------------------------------

    42. The Commission also proposed that if the interconnection
customer \90\ disables its governor or equivalent controls for any
reason, it shall notify the transmission provider's system operator, or
its designated representative, and shall make Reasonable Efforts \91\
to return the governor or equivalent controls to service as soon as
practicable.\92\ In addition, the Commission proposed that the
interconnection customer must provide the status and settings of the
governor or equivalent controls to the transmission provider upon
request.\93\
---------------------------------------------------------------------------

    \90\ The phrase ``interconnection customer'' shall have the
meaning given it in the definitional sections of the pro forma LGIA
and pro forma SGIA.
    \91\ The pro forma LGIA and pro forma SGIA state that reasonable
efforts ``shall mean, with respect to an action required to be
attempted or taken by a Party under the Standard Large Generator
Interconnection Agreement, efforts that are timely and consistent
with Good Utility Practice and are otherwise substantially
equivalent to those a Party would use to protect its own
interests.'' Pro forma LGIA Art. 1 (Definitions). Pro forma SGIA
Attachment 1 (Glossary of Terms).
    \92\ NOPR, 157 FERC ] 61,122 at P 52, proposed Section 9.6.4 of
the pro forma LGIA and Section 1.8.4 of the pro forma SGIA.
    \93\ Proposed Section <IP_ADDRESS> of the pro forma LGIA and <IP_ADDRESS>
of the pro forma SGIA.
---------------------------------------------------------------------------

2. Comments
a. Whether To Include Operating Requirements for Primary Frequency
Response in the Pro Forma LGIA and Pro Forma SGIA
    43. Several commenters support the NOPR proposal to include
operating requirements (i.e., droop, deadband, and timely and sustained
response) in the pro forma LGIA and pro forma SGIA,\94\ while other
commenters either object to specific, uniform governor control setting
requirements, prefer a market-based approach, or seek limited or full
exemptions based on unique operating characteristics.\95\ Several
commenters agree that a maximum 5 percent droop and 0.036
Hz deadband for newly interconnecting generating facilities is
technically feasible.\96\
---------------------------------------------------------------------------

    \94\ APPA et al., AWEA, Bonneville, California Cities,
Competitive Suppliers, First Solar, Idaho Power (for generating
facilities larger than 10 MW), ISO-RTO Council, NERC, PG&E, SVP, and
WIRAB state that they either support or do not object to the
inclusion of the proposed operating requirements in the pro forma
LGIA and pro forma SGIA.
    \95\ AES Companies; API; EEI; ELCON; ESA; MISO TOs; R St.
Institute; SoCal Edison; NRECA; and Xcel.
    \96\ See, e.g., AWEA Comments at 4; Bonneville Comments at 3;
ISO-RTO Council Comments at 4-5; NERC Comments at 6; NRECA Comments
at 2-3.
---------------------------------------------------------------------------

    44. Among those supporting the proposed operating requirements,
NERC asserts that the ``proposed minimum operating conditions should
help ensure that frequency response capability is installed as well as
available and ready to respond, regardless of the mix of resources in
the dispatch,'' and ``should lead to tighter control and frequency
stability.'' \97\ ISO-RTO Council states that, absent unique local
requirements such as lower and more responsive droop values in some
remote areas of the grid, NERC's guidelines provide a sound baseline
and are consistent with current requirements in some regions, including
ISO New England, Inc. (ISO-NE), New York Independent System Operator,
Inc. (NYISO), and PJM Interconnection, L.L.C. (PJM).\98\ While it
supports the NOPR proposal, WIRAB also notes the relevance of regional
differences, and recommends that the Commission ensure that NERC and
the Regional Entities continue to monitor frequency response capability
in each region and develop best practices that highlight regional
differences in the electricity resource mix and the need for primary
frequency response.\99\ Further, WIRAB suggests that NERC and the
Regional Entities periodically reevaluate the required maximum droop
and deadband settings.\100\
---------------------------------------------------------------------------

    \97\ NERC Comments at 5.
    \98\ ISO-RTO Council Comments at 4-5.
    \99\ WIRAB Comments at 3.
    \100\ Id.
---------------------------------------------------------------------------

    45. While it disagrees with a general mandate for primary frequency
response capability, in the event the Commission proceeds with a
requirement for new generating facilities to install primary frequency
response capability, NRECA supports the specific proposed operating
requirements.\101\
---------------------------------------------------------------------------

    \101\ NRECA Comments at 2.
---------------------------------------------------------------------------

    46. Some commenters express concern that uniform, specific governor
control settings in the pro forma LGIA and pro forma SGIA may fail to
account for regional differences and unique operating characteristics
of certain generating facilities and resource types, and could add
unnecessary costs. These commenters assert that the pro forma LGIA and
pro forma SGIA should only obligate new generating facilities to
install and maintain governors or equivalent controls, and not
establish specific operating requirements that

must be used.\102\ While supporting revisions to the pro forma LGIA and
pro forma SGIA to obligate newly interconnecting generators to install
governors or equivalent controls to provide primary frequency response,
EEI opposes including operating requirements. EEI asserts that tariffs,
rather than interconnection agreements, are a more effective means of
establishing operating requirements, since there are significant
differences among generating facility types and interconnections as
well as cost considerations, and because interconnection agreements
``do not provide the necessary controls to ensure compliance.'' \103\
EEI further states that operating requirements for new generating
facilities are better determined by individual balancing authorities on
an as-needed basis or through voluntary guidance from NERC.\104\ EEI
also requests that, rather than mandating specific operating
requirements, the Commission conduct a series of regional technical
conferences to ``allow for a more holistic evaluation of all [essential
reliability services]'' \105\ and provides details regarding the
proposed focus and scope of such conferences.\106\
---------------------------------------------------------------------------

    \102\ See, e.g., AES Companies Comments at 6; EEI Comments at 8;
MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel
Comments at 7.
    \103\ EEI Comments at 9, 11.
    \104\ Id. at 11-12.
    \105\ Id. at 12.
    \106\ Id. at 4, n.5.
---------------------------------------------------------------------------

    47. MISO TOs object to ``rigid standards that do not allow for
changes in technology or in the applicable NERC standards or
guidelines.'' \107\ Rather, MISO TOs contend that flexibility can be
achieved through a generic requirement for appropriate settings
consistent with good utility practices. MISO TOs believe this approach
would minimize the need to modify the pro forma LGIA and pro forma SGIA
and expedite the implementation of needed changes for primary frequency
response.\108\ AES Companies also oppose the proposed operating
requirement for droop and deadband settings, and believe that this
requirement should not be a uniform standard that is applied to all new
generating facilities.\109\ AES Companies assert that NERC provides a
primary frequency control guideline rather than a Reliability Standard
because the guideline may need to differ based on the type of
generating facility.\110\
---------------------------------------------------------------------------

    \107\ MISO TOs Comments at 9.
    \108\ Id. at 11.
    \109\ AES Companies Comments at 6.
    \110\ Id.
---------------------------------------------------------------------------

    48. While it generally agrees with the specific proposed droop and
deadband settings, NRECA supports allowing flexibility in the
requirements ``to the extent new generating facilities have differing
operating, technical or other characteristics which make compliance
with these standardized requirements unduly burdensome or impossible.''
\111\ APS, MISO TOs, SoCal Edison, Xcel and NYTOs add that the
Commission should defer to balancing authorities or transmission
providers to establish specified operating requirements for governor or
equivalent controls.\112\ Xcel states that regional system differences
could justify different primary frequency response standards.\113\
While the Commission should require that primary frequency response
capabilities be installed on all new facilities, any final action
should be flexible enough to allow for regional differences.\114\
---------------------------------------------------------------------------

    \111\ NRECA Comments at 3.
    \112\ APS Supplemental Comments at 5-6; MISO TOs Comments at 2;
SoCal Edison Comments at 3; Xcel Comments at 7; NYTOs Supplemental
Comments at 3-4.
    \113\ Xcel Comments at 7.
    \114\ Id.
---------------------------------------------------------------------------

    49. Some commenters that oppose including the proposed operating
requirements in the pro forma LGIA and pro forma SGIA state that
market-based procurement of primary frequency response service (in
regions of the country with organized markets) would better ensure that
the right amount and quality of primary frequency response service is
available at a lower cost to consumers.\115\ Also, NRECA is concerned
that the costs of the Commission's proposal could outweigh the
reliability benefits and delay the development of the types of
alternative technologies supported by the Commission.\116\
---------------------------------------------------------------------------

    \115\ See, e.g., AES Companies Comments at 9; API Comments at 4;
ELCON Supplemental Comments at 12, in support of R St Institute's
Comments; Public Interest Organizations Comments at 2; R St
Institute Comments at 4; SDG&E Comments at 5-6.
    \116\ NRECA Comments at 3.
---------------------------------------------------------------------------

b. Whether To Incorporate a Reference to a Future NERC Reliability
Standard in the Pro Forma LGIA and Pro Forma SGIA
    50. ISO-RTO Council asserts that revisions to the pro forma LGIA
and pro forma SGIA should account for the possibility that NERC may
develop a reliability standard with more stringent specific droop and
deadband parameters, and as a result, the pro forma LGIA and pro forma
SGIA should be written to allow for this eventuality without a need to
amend the pro forma agreements.\117\ ISO-RTO Council asserts that a
possible future reliability standard with more stringent droop and
deadband parameters should supersede the pro forma interconnection
requirements.\118\ Specifically, ISO-RTO Council recommends that the
Commission require new generating facilities to comply with the more
stringent of the following requirements: (1) A maximum 5 percent droop
and 0.036 Hz deadband parameter and a droop parameter to be
based on the nameplate capability of the unit and linear in operating
range between 59 to 61 Hz as proposed in the NOPR; or (2) an approved
NERC Reliability Standard providing for more stringent parameters.\119\
---------------------------------------------------------------------------

    \117\ ISO-RTO Council Comments at 5.
    \118\ Id.
    \119\ Id. at 5-6.
---------------------------------------------------------------------------

c. Requirements for Droop and Deadband
    51. Some commenters question the NOPR proposal to base a generating
facility's droop parameter on its nameplate capacity. EEI asserts that
the proposal is problematic because the mandated response from
generating facilities is based on MW and Reactive Curves, and not mega
volt-ampere (MVA) nameplate ratings.\120\ Similarly, ISO-RTO Council
urges the Commission to consider that nameplate capability of a unit
may not be consistent with the rated capacity of a generating facility
for purposes of obtaining interconnection service or for participation
in an organized market.\121\ In addition, ISO-RTO Council believes that
the Commission should clarify that efficiency improvements to a
resource increasing its output (e.g., duct burners that allow for
increased output from a steam generator) should be considered when
calculating a generating unit's droop parameter.\122\
---------------------------------------------------------------------------

    \120\ EEI Comments at 14.
    \121\ ISO-RTO Council Comments at 6.
    \122\ Id.
---------------------------------------------------------------------------

    52. While it supports the NOPR proposal for the droop parameter to
be linear in the operating range between 59 to 61 Hz, WIRAB recommends
that the Commission allow generating facilities to use faster, non-
linear settings over the proposed linear operating range.\123\ WIRAB
explains that a linear setting over the proposed operating range will
result in a 5 percent droop across the entire range, but that non-
linear droop parameters may lead to faster responses.\124\ More
specifically, WIRAB explains that rather than a linear 5 percent droop
across the entire operating range, ``nonlinear or

piecewise droop parameters,'' such as a 5 percent droop between 60.036
and 61.000 Hz and a 3 percent droop between 59.964 and 59.000 Hz, ``may
help to restore system frequency to normal faster and improve system
resiliency.'' \125\ On the other hand, EEI recommends that the
Commission not include in the pro forma interconnection agreements the
proposed requirement for the droop characteristic to be linear in the
operating between 59 to 61 Hz.\126\ In support of its position, EEI
contends that: (1) The proposed frequency range includes the deadband,
where governors do not operate; and (2) actual generating facility
response to frequency deviations may not be linear.\127\
---------------------------------------------------------------------------

    \123\ WIRAB Comments at 7.
    \124\ Id.
    \125\ Id.
    \126\ EEI Comments at 14-15, 17.
    \127\ Id. at 14.
---------------------------------------------------------------------------

    53. Regarding deadband parameters, NERC suggests that the
Commission consider replacing the proposed requirements with the NERC
Primary Frequency Control Guideline's recommendation \128\ concerning
the implementation of the deadband within the droop curve.\129\
Specifically, NERC recommends that deadbands should be implemented
without a step to the droop curve, i.e., once frequency deviates
outside the deadband, then change in the generating facility's MW
output starts from zero and then proportionally increases with the
input signal (i.e., frequency).\130\
---------------------------------------------------------------------------

    \128\ NERC Primary Frequency Control Guideline at 6.
    \129\ NERC Comments at 6.
    \130\ Id.
---------------------------------------------------------------------------

d. Requirements for the Status and Settings of the Governor or
Equivalent Controls
    54. NERC recommends that the Commission require the interconnection
customer to provide the status and settings of the governor or
equivalent controls and plant level controls not only to the
transmission provider (or its designated system operator) but also to
the relevant balancing authority upon request, and notify the balancing
authority when it needs to take the governor or equivalent controls and
plant level controls out of service.\131\ In support, NERC asserts
that, as the entity with a compliance obligation under Reliability
Standard BAL-003-1.1 for providing frequency response, the balancing
authority needs to know the status and settings of the governor or
equivalent controls and plant level controls in order to assess whether
there is an appropriate amount of frequency response available.\132\
NERC explains that providing this information to the balancing
authority would support efforts to help ensure sufficient frequency
response and compliance with Reliability Standard BAL-003-1.1.\133\
---------------------------------------------------------------------------

    \131\ Id.
    \132\ Id. at 6-7.
    \133\ Id.
---------------------------------------------------------------------------

    55. Regarding the disabling of an interconnection customer's
governor or equivalent controls, Bonneville asserts that the proposed
revisions to the pro forma LGIA and pro forma SGIA appear to give the
interconnection customer complete discretion to take its governor or
equivalent controls out of service, provided it gives the transmission
provider notice.\134\ To ensure the availability of frequency response
when the balancing authority needs it, Bonneville suggests that such
discretion be limited to operational constraints, ``including, but not
limited to, ambient temperature limitations, outages of mechanical
equipment, or regulatory requirements.'' \135\
---------------------------------------------------------------------------

    \134\ Bonneville Comments at 4.
    \135\ Id. at 4-5.
---------------------------------------------------------------------------

3. Commission Determination
a. Whether To Include Operating Requirements for Primary Frequency
Response in the Pro Forma LGIA and Pro Forma SGIA
    56. We disagree with commenters that argue the Commission should
not establish minimum uniform operating requirements for primary
frequency response.\136\ Instead, we find that the establishment of
minimum uniform operating requirements for all newly interconnecting
generating facilities is preferable to the fragmented and inconsistent
primary frequency response settings currently in place throughout the
Eastern and Western Interconnections.\137\ Assessments by NERC's
Essential Reliability Services Task Force demonstrate that a lack of
uniform, mandatory primary frequency response requirements has created
the opportunity for generator owners/operators to implement operating
settings that undermine the purpose and intent of Article <IP_ADDRESS> of
the pro forma LGIA to promote and ensure the adequate provision of
primary frequency response.\138\ Article <IP_ADDRESS> of the pro forma LGIA
requires a generating facility to operate its speed governors and
voltage regulators in automatic operation mode when the facility is
capable of such operation. Further, as the Commission observed in the
NOPR, ``[w]hile technological advancements have enabled wind and solar
generating facilities to now have the ability to provide primary
frequency response, this functionality has not historically been a
standard feature that was included and enabled on non-synchronous
generating facilities.'' \139\ Nothing in the record indicates that the
Commission's observation was incorrect.
---------------------------------------------------------------------------

    \136\ See, e.g., AES Companies Comments at 6; EEI Comments at 8;
MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel
Comments at 7.
    \137\ The ERCOT Interconnection has uniform minimum requirements
for primary frequency response, as generating facilities in Texas
Reliability Entity Inc. are required to comply with the requirements
of Regional Reliability Standard BAL-001-TRE-01.
    \138\ See NOPR, 157 FERC ] 61,122 at P 8. There, the NOPR
explains that a 2010 NERC survey found that ``only approximately 30
percent of generators in the Eastern Interconnection provided
primary frequency response, and that only approximately 10 percent
of generators provided sustained primary frequency response. This
suggests that many generators within the Interconnection disable or
otherwise set their governors or outer-loop controls such that they
provide little to no primary frequency response.''
    \139\ Id. P 13.
---------------------------------------------------------------------------

    57. We believe it is necessary to make these changes to the pro
forma LGIA and pro forma SGIA now in order to ensure that the future
generation mix will be capable of providing primary frequency response,
and to arrest the general long-term declining trend for this essential
reliability service. Adopting these requirements now is more prudent
than waiting until the lack of primary frequency response undermines
grid reliability, a point acknowledged by NERC's Essential Reliability
Services Task Force.
    58. Accordingly, we find that it is just and reasonable to include
the proposed operating requirements of a maximum droop setting of 5
percent and deadband setting of 0.036 Hz for primary
frequency response in the pro forma LGIA and pro forma SGIA. We
acknowledge that the needs of individual regions and balancing
authority areas may warrant the adoption of different operating
requirements in the future.\140\ Therefore, the operating requirements
for the pro forma LGIA and pro forma SGIA we adopt here are minimum
interconnection requirements for new generating facilities based on the

Primary Frequency Control Guideline developed by NERC through a broad-
based stakeholder process.\141\ NERC's Primary Frequency Control
Guideline ``reflect[s] the most advanced set of continent-wide best
practices and information available in support of frequency response
capability.'' \142\
---------------------------------------------------------------------------

    \140\ See, e.g., Order No. 827, FERC Stats. & Regs. 31,385
(``Due to technological advancements, the cost of providing reactive
power no longer represents an obstacle to the development of wind
generation.''). See also Order No. 828, 156 FERC ] 61,062 at P 8
(modifying the pro forma SGIA to require interconnecting small
generating facilities to ride through abnormal frequency and voltage
events and not disconnect during such events because ``the impact of
small generating facilities on the grid has changed.'').
    \141\ The Preamble to NERC's Primary Frequency Control Guideline
states that ``[t]hese guidelines are coordinated by the technical
committees and include the collective experience, expertise and
judgment of the industry. The objective of this reliability
guideline is to distribute key best practices and information on
specific issues critical to maintaining the highest levels of BES
reliability.'' See NERC Primary Frequency Control Guideline at 1.
    \142\ NERC Comments at 6.
---------------------------------------------------------------------------

    59. We disagree with the view of NRECA that this action is
premature because, at present, primary frequency response at the
Interconnection level may be acceptable.\143\ Rather, we find, as
stated by NERC, that increasing levels of generating facilities without
primary frequency response capability, combined with the retirement of
those generating facilities that have traditionally provided primary
frequency response, ``has contributed to the decline in primary
frequency response.'' \144\ Further, we agree with NERC's Essential
Reliability Services Task Force, which concluded that it is prudent and
necessary to ensure that the future generation mix includes primary
frequency response capabilities and recommends that all new generators
support the capability to manage frequency.\145\
---------------------------------------------------------------------------

    \143\ NRECA Comments at 7.
    \144\ NERC Comments at 5.
    \145\ Essential Reliability Services Task Force Measures Report
at vi.
---------------------------------------------------------------------------

    60. AES Companies and MISO TOs contend that NERC ``provides
guidelines rather than standards because these guidelines may need to
differ based on the type of resource,'' \146\ and that NERC's Primary
Frequency Control Guideline was adopted rather than a Reliability
Standard because ``there are many current and anticipated reasons to
deviate from'' the Guideline.\147\ We disagree and are persuaded
instead by NERC and other commenters that minimum requirements are
needed.\148\
---------------------------------------------------------------------------

    \146\ AES Comments at 6.
    \147\ MISO TOs Comments at 11.
    \148\ See, e.g., Bonneville Comments at 3; NERC Comments at 5;
ISO-RTO Council Comments at 4-5.
---------------------------------------------------------------------------

    61. We find ample support in the record to support this approach.
For example, in its comments on the NOPR, NERC states that ``the
Commission's proposed revisions to the pro forma interconnection
agreements are consistent with the results of recent NERC reliability
assessment recommendations.'' \149\ Further, NERC supports the
Commission's proposal, stating that ``the NOPR's proposed minimum
operating conditions should help ensure that frequency response
capability is installed as well as available and ready to respond,
regardless of the mix of resources in the dispatch'' and notes its
support for including the proposed droop and deadband settings in the
pro forma LGIA and pro forma SGIA.\150\
---------------------------------------------------------------------------

    \149\ NERC Comments at 5.
    \150\ Id. at 5-6.
---------------------------------------------------------------------------

    62. We disagree with EEI's assertion that the primary frequency
response operating requirements should not be included in the pro forma
LGIA and pro forma SGIA because the pro forma interconnection
agreements lack ``the necessary controls to ensure compliance.'' \151\
While this final action does not establish specific compliance
procedures for new generating facilities, transmission providers are
not prohibited from proposing such procedures in a FPA section 205
filing.\152\ Also, the pro forma LGIA and pro forma SGIA contain
Commission-approved directives that are legally enforceable
obligations.\153\ In any event, EEI's suggestion that transmission
providers would neither detect nor address possible interconnection
customer non-compliance with the new operating requirements is
speculative and without support in the record.
---------------------------------------------------------------------------

    \151\ EEI Comments at 11.
    \152\ 16 U.S.C. 824d (2012).
    \153\ See NSTAR Elec. & Gas Corp. v. FERC, 481 F.3d 794, 800
(D.C. Cir. 2007).
---------------------------------------------------------------------------

    63. EEI, MISO TOs, and SoCal Edison request that the Commission not
include the proposed operating requirements in the pro forma LGIA and
pro forma SGIA, but instead defer to transmission providers or
balancing authorities to establish operating requirements addressing
reliability needs identified in regional studies.\154\ For the reasons
discussed above, we find that it is prudent to establish minimum
uniform operating requirements as the foundational element of a
framework for ensuring the adequacy and timeliness of primary frequency
response. However, as noted immediately below and discussed in more
detail in Section II.I below, the Commission establishes, with an
addition and clarification, methods for proposing variations to this
final action.\155\
---------------------------------------------------------------------------

    \154\ EEI Comments at 12; MISO TOs Comments at 9; SoCal Edison
Comments at 3.
    \155\ See P 233 below, describing the following variation
methods: (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.
---------------------------------------------------------------------------

    64. While we are establishing uniform operating requirements, we
also note that there is flexibility built into both the requirements
themselves and the Commission's processes. First, we clarify that the
requirements we adopt herein are minimum requirements. Thus, if an
interconnection customer wishes to implement more stringent deadband
and droop settings, it may do so.\156\ Second, as also discussed in the
next section, we have clarified the final action to allow for the
possibility of a NERC Reliability Standard that has more stringent
parameters than the requirements adopted here. Third, as discussed in
Section II.I below, we continue the Commission's historic practice of
allowing RTOs/ISOs to propose independent entity variations, as well as
permitting other transmission providers to propose changes that are
``consistent with or superior to'' the pro forma language. Finally, in
the event of a unique circumstance affecting specific resources, the
transmission provider may file a non-conforming LGIA or SGIA, or the
interconnection customer may request that the transmission provider
file an unexecuted LGIA or SGIA.
---------------------------------------------------------------------------

    \156\ See NOPR, 157 FERC ] 61,122 at P 8 (``The Commission notes
that these proposed requirements are minimum requirements;
therefore, if a new generating facility elects, in coordination with
its transmission provider, to operate in a more responsive mode by
using lower droop or tighter deadband settings, nothing in these
requirements would prohibit it from doing so'').
---------------------------------------------------------------------------

    65. Regarding EEI's request to conduct regional conferences, we do
not believe that they are necessary at this time since: (1) The
Commission has determined that minimum operating requirements are
appropriate to include in the pro forma LGIA and pro forma SGIA; and
(2) EEI's request to focus on other essential reliability services
besides primary frequency response is beyond the scope of this
proceeding.
    66. Comments that reference compensation in lieu of including
uniform operating requirements in the pro forma LGIA and pro forma SGIA
are addressed below in Section II.E.
b. Whether To Include a Reference to a Future NERC Reliability Standard
in the Pro Forma LGIA and Pro Forma SGIA
    67. The Commission is persuaded by ISO-RTO Council's request to
include in the pro forma LGIA and pro forma SGIA provisions that
address any future NERC Reliability Standard that provides for more
stringent parameters. The Commission agrees that the pro forma LGIA and
pro forma SGIA (as applied to newly interconnecting generation
facilities) should be written to allow for

the adoption of a future Reliability Standard with stricter operating
requirements (droop and deadband parameters) without a need to further
amend interconnection agreements.
    68. Accordingly, as discussed below, we are modifying the NOPR
proposal to allow for the possibility of a future NERC Reliability
Standard that includes equivalent or more stringent operating
requirements for droop, deadband, and/or timely and sustained response
that would supersede the operating requirements for droop, deadband,
and timely and sustained response adopted in this final action. We
believe this approach will provide for the harmonization of the
reliability-related provisions of the pro forma LGIA and pro forma SGIA
with any future Reliability Standard, and will avoid potential
conflicts between Reliability Standards and tariff provisions.\157\
---------------------------------------------------------------------------

    \157\ See 18 CFR 39.6 (2017). This regulation requires the
Commission to issue an order within 60 days, unless it otherwise
orders, following notification of a conflict between a Reliability
Standard and any function, rule, order, tariff, rate schedule or
agreement accepted, approved, or ordered by the Commission. If the
Commission determines a conflict exists it will either direct the
Transmission Organization to file a modification of the function,
rule, order, tariff, rate schedule or agreement under FPA section
206 or the Electric Reliability Organization to file a modification
to the conflicting Reliability Standard.
---------------------------------------------------------------------------

    69. We clarify that interconnection customers that are required to
comply with this final action will be required to do so until such time
as the Commission approves a NERC Reliability Standard with equivalent
or more stringent parameters.\158\ If the Commission approves such a
NERC Reliability Standard, interconnection customers subject to this
final action will be required to comply with the operating requirements
of the Reliability Standard if it applies to them. However,
interconnection customers that are not Applicable Entities of the
Reliability Standard will continue to be required to comply with the
operating requirements contained within the pro forma LGIA and pro
forma SGIA as adopted in this final action.
---------------------------------------------------------------------------

    \158\ For example, such a Reliability Standard may have
requirements for tighter droop (maximum 4 percent droop) and/or
deadband settings (e.g., 0.017 Hz).
---------------------------------------------------------------------------

c. Requirements for Droop and Deadband
    70. We adopt the NOPR proposal to require newly interconnecting
generating facilities to install, maintain, and operate a governor or
equivalent with a maximum 5 percent droop and 0.036 Hz
deadband and for the droop characteristic to be based on the nameplate
capacity.
    71. As a threshold matter for this requirement, we clarify the term
``nameplate capacity.'' Some commenters raise concerns with the
proposal to base the droop parameter on the nameplate capacity of a
generating facility.\159\ EEI asserts that basing droop characteristics
on nameplate capacity is problematic since ``resource response is based
on MW and Reactive curves, and not MVA nameplate ratings.'' \160\ In
response to this concern, we clarify that the use of the term
``nameplate capacity'' refers to the maximum MW rating of the facility
as defined by the Energy Information Administration (EIA).\161\ We note
that EIA's definition of ``nameplate capacity'' utilizes units of MWs,
not MVAs as suggested by EEI. In response to ISO-RTO Council's request
for clarification on whether efficiency improvements to a generating
facility that increase its output should be factored into the
calculation of the droop parameter,\162\ we clarify that if a
modification to a generating facility causes its nameplate capacity to
increase or decrease, then droop parameter should be based on the
updated nameplate capacity value.
---------------------------------------------------------------------------

    \159\ EEI Comments at 14; ESA Comments at 3-4.
    \160\ EEI Comments at 14.
    \161\ EIA defines nameplate capacity as ``[t]he maximum rated
output of a generator, prime mover, or other electric power
production equipment under specific conditions designated by the
manufacturer. Installed generator nameplate capacity is commonly
expressed in MW and is usually indicated on a nameplate physically
attached to the generator.'' See EIA Glossary, https://www.eia.gov/tools/glossary/index.php?id=G.
    \162\ ISO-RTO Council Comments at 6.
---------------------------------------------------------------------------

    72. The droop parameter is historically based on the percent change
in frequency that would cause a 100 percent change in valve or gate
position. This has been translated to the percent change in frequency
that would cause a 100 percent change in power output, where a 100
percent change in power output is equivalent to the generator's
nameplate capacity. The droop parameter also represents the slope of
the MW response in proportion to the frequency deviation.
    73. By requiring the droop parameter to be based on nameplate
capacity, the Commission intends for a generating facility's expected
MW response to frequency deviations to be a percentage of its nameplate
capacity, and proportional to the magnitude of the frequency deviation.
In particular, the magnitude of a generating facility's MW response to
a frequency deviation will depend both on its nameplate capacity and on
the magnitude of the frequency deviation. Generating facilities with
larger nameplate capacities will provide more MW of primary frequency
response per Hz of Interconnection frequency error compared to
generating facilities with an equivalent percent droop parameter that
have lower nameplate capacities. Accordingly, nameplate capacity is the
``basis'' of the droop parameter since this value will be used to
calculate the expected proportional MW response to frequency
deviations.
    74. ISO-RTO Council points out that the nameplate capacity of a
generating facility may not be consistent with its rated capacity for
the purposes of obtaining interconnection service or for participation
in an organized market. In addition, we recognize that during some
operating conditions, the maximum steady state operating limit (e.g.,
maximum sustainable MW limit) of a generating facility may be less than
its nameplate capacity. Therefore, we clarify that for the purposes of
calculating the expected amount of primary frequency response that is
provided in response to frequency deviations, the calculation should
still be based on a generating facility's full nameplate capacity even
if the level of requested interconnection service or the steady state
operating limit is below that nameplate capacity. We find that this
approach is consistent with EPRI's statement that the droop setting is
historically based on the percent change in frequency that would cause
a 100 percent change in power output (where a 100 percent change in
power output is equivalent to the nameplate capacity).\163\ As an
example, in the case of a generating facility with a 5 percent droop,
as the Interconnection's frequency error changes from 0 to 3 Hz and as
the system frequency transitions outside of the deadband parameter, the
expected change in the generating facility's MW output should range
from 0 MW to full nameplate capacity.
---------------------------------------------------------------------------

    \163\ EPRI Supplemental Comments at 5.
---------------------------------------------------------------------------

    75. We clarify that this final action will not require a generating
facility that responds to frequency deviations to provide and sustain a
value of primary frequency response that causes its MW output to exceed
its maximum steady state operating limit.\164\ For example, under-
frequency conditions outside of the deadband parameter would result in
an automatic increase in the generating facility's MW output. However,
if the calculated incremental MW value that would be provided as
primary

frequency response per the droop parameter would cause the generating
facility to exceed its maximum steady state operating limit, the
interconnection customer would be permitted to limit the increase in
the generating facility's MW output such that its MW output (after
primary frequency response has been provided) does not exceed its
maximum steady state operating limit, since doing so may cause
facility-level reliability concerns. Should a generating facility's
maximum operating limit per its interconnection agreement be less than
its nameplate capacity, nothing in this final action would require an
interconnection customer to violate the terms of its interconnection
agreement. In such a situation, an interconnection customer would be
permitted to limit the increase in the generating facility's MW output
such that its MW output does not exceed the maximum operating limit as
described in the interconnection agreement.
---------------------------------------------------------------------------

    \164\ For example, a generating facility's maximum steady state
operating limit may be capped at the MW level of interconnection
service requested. Or, during certain periods of an operating year,
ambient temperature conditions reduce the maximum sustainable MW
output level to below nameplate capacity.
---------------------------------------------------------------------------

    76. Similarly, over-frequency conditions would result in an
automatic reduction in a generating facility's MW output. However, if
the calculated value of primary frequency response would cause the
facility's MW output to drop below its minimum operating MW limit, an
interconnection customer will be permitted to limit the decrease in the
facility's MW output such that the facility does not operate below its
minimum steady state operating limit.
    77. In addition, we are persuaded by NERC's suggestion to require
the deadband parameter to be implemented without a step to the droop
curve. We note that NERC's Primary Frequency Control Guideline
references a 2013 IEEE Power & Energy Society (IEEE-PES) Technical
Report stating that a droop curve (with a deadband) can be implemented
in a generator governor in two possible ways: ``Stepped'' or ``non-
stepped.'' \165\ In its report, IEEE-PES points out that these two
methodologies of implementing the deadband parameter can potentially
have significantly different results in the response of a generating
facility's governor control system to changes in system frequency.\166\
According to IEEE-PES, if the deadband is implemented under the stepped
approach, as soon as system frequency transitions outside of the
deadband parameter (e.g., 0.036 Hz), the generating
facility will experience a sudden spike (increase or decrease) in its
MW output, which IEEE-PES warns can be undesirable.\167\ To account for
this issue, NERC recommends in its Primary Frequency Control Guideline
\168\ and its comments to the NOPR \169\ that the deadband should be
implemented without a step to the droop curve. Under the non-stepped
approach of implementing the deadband parameter, once frequency
transitions outside of the deadband, the incremental change in the
generating facility's MW output will start from zero and then increase
linearly to the generating facility's nameplate capacity and in
proportion to the Interconnection's frequency error.\170\
---------------------------------------------------------------------------

    \165\ NERC Primary Frequency Control Guideline at 6, referencing
Dynamic Models for Turbine-Governors in Power System Studies at
Appendix B: Deadband, IEEE-PES (Jan 2013), http://sites.ieee.org/fw-pes/files/2013/01/PES_TR1.pdf (IEEE-PES Report).
    \166\ IEEE-PES Report at Appendix B.
    \167\ Id.
    \168\ NERC Primary Frequency Control Guideline at 6.
    \169\ NERC Comments at 6.
    \170\ Id.
---------------------------------------------------------------------------

    78. In consideration of this additional information, we agree with
NERC and modify the NOPR proposal to require the deadband parameter to
be implemented without a step. Accordingly, we are requiring the droop
curve to be implemented in a manner such that as frequency transitions
outside of the deadband (both for under-frequency and over-frequency
conditions), the generating facility's expected MW response should
start from 0 MW and increase linearly to the nameplate capacity of the
generating facility, as the Interconnection's frequency error changes
from 0 Hz to the generating facility's percentage droop multiplied by
60 Hz (e.g., in the case of a 5 percent droop, this would be 3 Hz).
    79. In response to EEI's concerns that: (1) The proposed frequency
range of 59 to 61 Hz includes the deadband where governors do not
operate; and (2) not all generating facilities respond in a linear
manner, we are modifying the NOPR proposal and adopt in this final
action that the droop parameter should be linear in the range of
frequencies between 59 to 61 Hz that are outside of the deadband
parameter. This is because the range of frequency values within the
deadband do not trigger the operation of the governor or equivalent
controls, and the slope of the droop curve that relates change in
frequency to change in MW output should only apply to the range of
frequencies outside of the deadband, i.e., those frequencies where the
generating facility's MW output is expected to change in proportion to
frequency deviations. Regarding EEI's concern that not all generating
facilities respond in a linear manner, we acknowledge that non-linear
responses can and may occur. However, we believe that the existence of
non-linear responses will not undermine the effectiveness of this final
action. We expect that interconnection customers will take Reasonable
Efforts to maximize and ensure their ability to provide a linear
response in accordance with the droop parameter.
    80. While we agree with WIRAB that the use of non-linear or
piecewise droop parameters may lead to faster responses, we decline to
adopt WIRAB's request to, on a generic basis, require prospective
interconnection customers to implement non-linear or piecewise droop
curves. While we require the droop curve to be linear (e.g., 5 percent)
in the range of frequencies outside of the deadband between 59 to 61 Hz
(i.e., the response for both under-frequency and over-frequency
conditions should be based on a maximum 5 percent droop), consistent
with the NOPR proposal, we find that nothing in these requirements
prohibit the implementation of asymmetrical droop settings (i.e.,
different droop settings for under-frequency and over-frequency
conditions), provided that each segment has a percent droop value of no
more than 5 percent.\171\ For example, our requirements would not
prohibit the implementation of a droop curve that has a five percent
droop for over-frequency conditions (e.g., between 60.036 and 61.000
Hz) and a 3 percent droop for under-frequency conditions (e.g., between
59.964 and 59.000 Hz).\172\
---------------------------------------------------------------------------

    \171\ See NOPR, 157 FERC ] 61,122 at n.126.
    \172\ See WIRAB Comments at 7.
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d. Requirements for the Status and Settings of the Governor or
Equivalent Controls
    81. We agree with NERC that the balancing authority should know the
status and settings of the governor or equivalent controls and plant
level controls in order to assess whether there is an appropriate
amount of frequency reserve available.\173\ In addition, the Commission
agrees with NERC that providing this information to the balancing
authority ``would support [balancing authority] and [frequency response
sharing group] efforts to help ensure sufficient frequency response and
their compliance with Reliability Standard BAL-003-1.1.'' \174\
---------------------------------------------------------------------------

    \173\ NERC Comments at 6-7.
    \174\ Id.
---------------------------------------------------------------------------

    82. Accordingly, we are modifying in this final action the NOPR
proposal to require the interconnection customer to provide its
relevant balancing authority with the status and settings of the

governor or equivalent controls upon request or when the
interconnection customer operates the generating facility with its
governor or equivalent controls not in service. We determine that this
is just and reasonable because it will help improve situational
awareness by helping the balancing authority assess whether there is an
appropriate amount of frequency responsive capacity online.
    83. Regarding the process for an interconnection customer to
disable its governor or equivalent controls, we share Bonneville's
concern that the interconnection customer should not be allowed to
operate its generating facility with its governor or equivalent
controls not in service by merely notifying the transmission
provider.\175\ While we believe that it is not necessary to require the
interconnection customer to meet specific operational conditions (e.g.,
maintenance or outages of mechanical equipment) as a precondition to
disabling the governor or equivalent controls as Bonneville
suggests,\176\ we are modifying the NOPR proposal to provide additional
clarity on this issue.
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    \175\ Bonneville Comments at 4.
    \176\ Id.
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    84. Specifically, we revise the pro forma LGIA and pro forma SGIA
to require the interconnection customer to make Reasonable Efforts to
keep outages of the generating facility's governor or equivalent
controls to a minimum whenever it is operated in parallel with the
Transmission System. The interconnection customer shall immediately
notify the transmission provider and relevant balancing authority of
its need to operate the generating facility without the governor or
equivalent controls in service.
    85. Accordingly, we will modify the pro forma LGIA and pro forma
SGIA to state that when providing notice to the transmission provider
of its intent to disable its governor or equivalent controls, the
interconnection customer's notice shall include: (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 why the governor or equivalent controls are unable to be
operated in service; and (3) a reasonable estimate as to when the
governor or equivalent controls will be returned to service. The
interconnection customer will be required to then make Reasonable
Efforts to return its governor or equivalent controls to service as
soon as practicable and notify the transmission provider and balancing
authority when it has done so.

C. Requirement To Ensure the Timely and Sustained Response to Frequency
Deviations

1. NOPR Proposal
    86. In the NOPR, the Commission proposed to prohibit all new large
and small generating facilities from taking any action that would
inhibit the provision of primary frequency response, except under
certain conditions, including but not limited to, ambient temperature
limitations, outages of mechanical equipment, or regulatory
requirements.\177\ The Commission explained that the lack of
coordination between governor and plant-level control systems can
result in premature withdrawal of primary frequency response by
allowing additional plant control systems to reverse the action of the
governor to return the unit to operating at a pre-selected target set-
point.\178\ The Commission noted that NERC's Primary Frequency Control
Guideline explains that ``in order to provide sustained primary
frequency response, it is essential that the prime mover governor,
plant controls and remote plant controls are coordinated.'' \179\
---------------------------------------------------------------------------

    \177\ NOPR, 157 FERC ] 61,122 at P 49.
    \178\ Id.
    \179\ Id. (citing NERC Primary Frequency Control Guideline at
4).
---------------------------------------------------------------------------

    87. Accordingly, the Commission proposed to require new generating
facilities that respond to frequency deviations to not inhibit primary
frequency response, such as by coordinating plant-level control
equipment with the governor or equivalent controls.\180\ In particular,
the Commission proposed to include new Sections <IP_ADDRESS> of the pro
forma LGIA and <IP_ADDRESS> of the pro forma SGIA to require that the real
power response of new large and small generating facilities ``to
sustained frequency deviations outside of the deadband setting is
provided without undue delay . . . until system frequency returns to a
stable value within the deadband setting of the governor or equivalent
controls.'' \181\
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    \180\ Id.
    \181\ Id. PP 52-53.
---------------------------------------------------------------------------

2. Comments
    88. Several commenters support including the proposed provisions
for timely and sustained response in the pro forma LGIA and pro forma
SGIA.\182\ NERC supports the minimum operating conditions proposed in
the NOPR because ``[s]uch requirements for the capability of `timely
and sustained response to frequency deviations' should promote
reliability and help avoid a scenario where the transforming resource
mix reduces frequency response capability.'' \183\ ISO-RTO Council
asserts that requiring primary frequency response to be sustained until
frequency returns within the deadband parameter ``is consistent with
the current requirements of PJM and ISO-NE, as well as CAISO.'' \184\
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    \182\ Bonneville Comments at 2, First Solar Comments at 4; Idaho
Power Comments at 1-2; ISO-RTO Council Comments at 5; NERC Comments
at 5-6; WIRAB Comments at 5.
    \183\ NERC Comments at 5-6.
    \184\ ISO-RTO Council Comments at 5.
---------------------------------------------------------------------------

    89. While acknowledging the importance of timely and sustained
frequency response, EEI does not believe that such requirements should
be included in the pro forma LGIA and pro forma SGIA because ``the
requirements do not consider the resource type or available capacity in
requiring sustained response and therefore impose operating
requirements for all governors or equivalent controls.'' \185\ EEI
recommends that the Commission ``limit its modifications of the pro
forma LGIA and SGIA requirements to address resource capability (but
not operational requirements) in order to allow regional needs and
markets to address the issue of timely and sustained response for
frequency deviations.'' \186\ Also, EEI believes that individual
balancing authorities should determine operating requirements ``on an
as-needed basis or through compliance guidance'' from NERC.\187\ AES
Companies agree, asserting that it is prudent for each balancing
authority to determine appropriate criteria for timely and sustained
response, because ``the criteria for sustained and timely response may
differ from system to system due to operating conditions, resource mix
and more.'' \188\
---------------------------------------------------------------------------

    \185\ EEI Comments at 9.
    \186\ Id.
    \187\ Id. at 12.
    \188\ AES Companies Comments at 14.
---------------------------------------------------------------------------

    90. EEI raises an additional concern, stating that ``requirements
to provide timely and sustained frequency response cannot be
implemented in a manner that is fair and non-discriminatory'' because
interconnection agreements ``do not provide the necessary controls to
ensure compliance . . . [or] effectively or fairly ensure compensation
to those entities providing this support.'' \189\ EEI states that
without a generic headroom requirement, a uniform requirement for
timely primary frequency response ``unfairly discriminates between
those

resources that are capable of providing timely response due to their
design or current operating status over resources that are not capable
of providing a timely response.'' \190\ As an example, EEI states that
renewables may not be able to provide a timely response to under-
frequency deviations if they are operating at capacity or due to other
technical limitations.\191\
---------------------------------------------------------------------------

    \189\ EEI Comments at 11.
    \190\ Id.
    \191\ Id.
---------------------------------------------------------------------------

    91. WIRAB and EEI recommend certain modifications to the NOPR
proposal for timely and sustained response. Both recommend that the
Commission explicitly prohibit in the pro forma LGIA and pro forma SGIA
the interconnection customer from blocking or otherwise inhibiting the
ability of the governor or equivalent controls to respond.\192\
---------------------------------------------------------------------------

    \192\ EEI Comments at 18-19; WIRAB Comments at 5-6.
---------------------------------------------------------------------------

    92. In the NOPR, the Commission proposed to require that the real
power response of new large and small generating facilities to
sustained frequency deviations outside of the deadband setting is
provided without undue delay . . . until system frequency returns to a
stable value within the deadband setting of the governor or equivalent
controls.'' \193\ WIRAB recommends that the term ``without undue
delay'' be defined to require the generating facility to ``provide
immediate frequency response when system frequency deviates outside of
the required deadband settings, and that no grace period be allowed
that can postpone the response.'' \194\ Additionally, WIRAB recommends
that ``stable value'' be defined as the ``settled frequency response
value achieved when frequency has rebounded and settled--after hitting
the nadir--but possibly before reaching the normal frequency of 60
Hz.'' \195\ Also, WIRAB recommends that ``[o]utside controls should not
override a generator's frequency response until the system frequency
has settled.'' \196\ WIRAB states that its recommended changes would
ensure a consistent, timely, and sustained response from generating
facilities providing primary frequency response.\197\
---------------------------------------------------------------------------

    \193\ NOPR, 157 FERC ] 61,122 at PP 52-53.
    \194\ WIRAB Comments at 5.
    \195\ Id. at 5-6. WIRAB notes that NERC describes this settled
frequency value in its Interconnection Frequency Response Obligation
calculation used in Reliability Standard BAL-003-1.1 and labels the
value ``Value B'' in the calculation. Id. at n.8.
    \196\ Id. at 6.
    \197\ Id. at 5.
---------------------------------------------------------------------------

    93. AWEA asks the Commission to clarify that its proposed
prohibition of actions ``inhibiting'' response does not restrict the
ability of wind and other generating facilities to adjust the speed of
their response in coordination with system operators to ensure a fair
and coordinated response that best meets the needs of the system as a
whole.\198\ AWEA explains that the fast controls inherent in modern
wind turbines allow them to respond to frequency deviations more
quickly and accurately than many conventional generators, and that some
generating facilities can respond so fast that slower-responding
facilities cannot provide a coordinated response.\199\ AWEA argues that
there should be flexibility to ensure a fair and coordinated response
(i.e., allow wind generating facilities to respond more slowly than
their full design capability) that meets the needs of the system and
does not result in a disproportionate share of the response--and cost
burden--being provided by facilities that can respond more rapidly
(such as very fast-responding wind plants).\200\ Accordingly, AWEA
recommends that the Commission clarify that adjustments to the response
speed of non-synchronous generating facilities, when done to ensure
coordinated response for the system operator and fair distribution of
cost impacts across generating facility types, do not ``inhibit''
response within the meaning of the NOPR, or if it does, are within the
scope of the operational constraints permitted under the NOPR.\201\
---------------------------------------------------------------------------

    \198\ AWEA Comments at 8-9.
    \199\ Id.
    \200\ Id. at 9.
    \201\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    94. We determine that it is just and reasonable to include a
requirement for timely and sustained response in the pro forma LGIA and
pro forma SGIA. As stated in the NOI, premature withdrawal of primary
frequency response ``has the potential to degrade the overall response
of the Interconnection and result in a frequency that declines below
the original nadir.'' \202\ We are persuaded by the reliability
assessments performed by NERC confirming a general decline in primary
frequency response that, unless adequately addressed, could worsen as
the generation resource mix continues to evolve.\203\ The requirement
for timely and sustained response would address that decline and more
specifically would address concerns raised by NERC and others about the
premature withdrawal of primary frequency response following a system
disturbance, which is a significant concern in the Eastern
Interconnection and a somewhat smaller issue in the Western
Interconnection.\204\ This phenomenon stems from generating facilities
that do not sustain the response until system frequency returns to
within the deadband parameter; instead they withdraw the response soon
after it is provided.\205\ In adopting this requirement, we agree with
commenters who stated that there should be a clear requirement for
primary frequency response to be timely and sustained.\206\
---------------------------------------------------------------------------

    \202\ See NOI, 154 FERC ] 61,117 at P 49.
    \203\ See NERC Comments at 5. NERC states that it ``has
determined that increasing levels of non-synchronous resources
installed without controls that enable frequency response
capability, coupled with retirement of conventional resources that
have traditionally provided primary frequency response, has
contributed to the decline in primary frequency response'' and that
``a changing resource mix will further alter the dispatch of
resources and combinations of resources . . . potentially resulting
in systems operating states where frequency response capability
could be diminished unless a sufficient amount of frequency
responsive capacity is included in the dispatch.''
    \204\ See NOI, 154 FERC ] 61,117 at PP 49-50. See also Frequency
Response and Frequency Bias Setting Reliability Standard, Notice of
Proposed Rulemaking, 78 FR 45479 (July 29, 2013), 144 FERC ] 61,057,
at PP 35-38 (2013).
    \205\ In the NOI, the Commission stated that primary frequency
response withdrawal ``has the potential to degrade the overall
response of the Interconnection and result in a frequency that
declines below the original nadir.'' See NOI, 154 FERC ] 61,117 at P
49.
    \206\ See, e.g., Bonneville Comments at 2; ISO-RTO Council
Comments at 5; NERC Comments at 5-6; WIRAB Comments at 6.
---------------------------------------------------------------------------

    95. We are not persuaded by EEI's and AES Companies' view that
timely and sustained response requirements should be part of regional
solutions rather than be included in the pro forma LGIA and pro forma
SGIA. NERC's assessments and conclusions do not indicate that the
fundamental concerns about declining primary frequency response or the
premature withdrawal of primary frequency response are unique or
limited to individual regions. In addition, we note that frequency