[Federal Register Volume 83, Number 44 (Tuesday, March 6, 2018)]
[Rules and Regulations]
[Pages 9636-9677]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-03707]



[[Page 9635]]

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  

[[Page 9636]]


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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, (202) 502-6281, [email protected].
Mark Bennett (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE, Washington, 
DC 20426, (202) 502-8524, [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..........................

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        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

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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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[[Page 9639]]

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

[[Page 9640]]

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.
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    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 9.6.2.1 of the pro forma LGIA does not address 
the settings of governors or equivalent controls (i.e., deadband and 
droop), nor does Article 9.6.2.1 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 9.6.2.1 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 9.6.2.1 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 9.6.2.1 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,

[[Page 9641]]

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.
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    \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

[[Page 9642]]

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.
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    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.
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    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.

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

[[Page 9643]]

    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 9.6.4.1 of the pro forma LGIA and 1.8.4.1 
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

[[Page 9644]]

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

[[Page 9645]]

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 9.6.2.1 of 
the pro forma LGIA to promote and ensure the adequate provision of 
primary frequency response.\138\ Article 9.6.2.1 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

[[Page 9646]]

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

[[Page 9647]]

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

[[Page 9648]]

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.
---------------------------------------------------------------------------

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

[[Page 9649]]

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.
---------------------------------------------------------------------------

    \175\ Bonneville Comments at 4.
    \176\ Id.
---------------------------------------------------------------------------

    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 9.6.4.2 of the pro 
forma LGIA and 1.8.4.2 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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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

[[Page 9650]]

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 
response is an Interconnection-wide phenomenon. Accordingly, we find 
that minimum, uniform primary frequency response requirements, 
including timely and sustained response, are just and reasonable.
    96. EEI comments that without a provision to ``fairly ensure 
adequate compensation,'' and a mandate that each new generating 
facility operate with headroom at all times, the proposed requirements 
for timely and sustained primary frequency response ``cannot be 
implemented in a manner that is fair and non-discriminatory.'' \207\ 
EEI asserts that ``requiring all resources to have a timely operating 
response, but

[[Page 9651]]

failing to require necessary headroom, unfairly discriminates between 
those resources that are capable of providing a timely response due to 
their design or current operation status over resources that are not 
capable of providing a timely response.'' \208\ We disagree. We are 
imposing operating requirements on all newly interconnecting generating 
facilities (with limited exemptions) but not mandating headroom or 
compensation for any generating facilities. Any headroom maintained by 
these facilities is not required by this final action, and does not 
render our operating requirements unduly discriminatory. If future 
conditions necessitate a headroom requirement, we will then consider 
any appropriate compensation.
---------------------------------------------------------------------------

    \207\ EEI Comments at 11.
    \208\ Id.
---------------------------------------------------------------------------

    97. As noted in Section II above, one of the Commission's concerns 
with the current lack of clear, uniform primary frequency response 
requirements is NERC's finding indicating that a number of generator 
owners/operators have implemented operating settings that have 
effectively removed the availability of their generating facilities 
from providing timely and sustained primary frequency response (e.g., 
wide deadband settings, uncoordinated plant-level controls).\209\ The 
reforms adopted in this final action, to be applied uniformly to new 
generating facilities, are intended to eliminate these practices. 
Accordingly, the Commission determines that the requirements are just, 
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \209\ Id. PP 8-9, 39.
---------------------------------------------------------------------------

    98. Further, while it is true that generating facilities that are 
operated with no headroom at the time of an under-frequency deviation 
will provide little or no response in the upward direction, they will 
still be available to support the reliability of the power system by 
responding in the downward direction during abnormal over-frequency 
system conditions. Since the timing of an abnormal frequency deviation 
outside of the deadband parameter--and when a generating facility will 
thus be required to respond--is unpredictable, it is possible that 
these generating facilities will have operating capability in the 
upward direction to respond to some abnormal under-frequency 
deviations.
    99. We agree with the suggestions of EEI and WIRAB to explicitly 
prohibit interconnection customers from blocking or otherwise 
inhibiting the governor's or equivalent controls' ability to 
respond.\210\ Accordingly, as discussed below in Section II.K.3, the 
Commission will modify in this final action the NOPR proposal to 
require interconnection customers to not block or otherwise inhibit the 
governor or equivalent controls' ability to respond.
---------------------------------------------------------------------------

    \210\ EEI Comments at 16, 18-19; WIRAB Comments at 5-6.
---------------------------------------------------------------------------

    100. AWEA, ESA, and WIRAB ask the Commission to clarify the 
proposed timely and sustained response provisions, and their comments 
raise the following questions: (1) How soon should a generating 
facility begin to provide primary frequency response following a 
disturbance; and (2) how long, at a minimum, should the response be 
sustained?
    101. Regarding how soon a generating facility should begin to 
provide primary frequency response following a disturbance, the 
Commission agrees with WIRAB that the definition of ``without undue 
delay'' should be clarified.\211\ Accordingly, we clarify that the NOPR 
proposal for generating facilities to respond ``without undue delay'' 
is intended to address the concern that an interconnection customer 
could program an intentional delay of several seconds or minutes to 
effectively avoid contributing to the support of power system 
reliability following a disturbance. Following the sudden loss of 
generation or load, primary frequency response must be delivered as 
promptly as possible, within the physical characteristics of the 
generating facility, in order to avoid, for example, Interconnection 
frequency declining to a level where UFLS relays are activated or to a 
lower level where generation under-speed protection relays activate, 
resulting in additional generation trips or cascading outages. 
Accordingly, in response to WIRAB's request to clarify when a 
generating facility should respond to a frequency deviation, we will 
modify the NOPR proposal and adopt in this final action the requirement 
that generating facilities respond immediately after system frequency 
deviates outside of the deadband parameter, to the extent that they 
have available operating capability in the direction needed to correct 
frequency deviation at the time of the disturbance.\212\
---------------------------------------------------------------------------

    \211\ See WIRAB Comments at 5.
    \212\ The Commission accepted similar tariff language proposed 
by CAISO. See Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182, at 
P 17 (2016) (accepting, among other things, CAISO's proposed changes 
to s Section 4.6.5.1 of its tariff, which provides in pertinent part 
that ``Participating Generators with governor controls that are 
synchronized to the CAISO Controlled Grid must respond immediately 
and automatically.'').
---------------------------------------------------------------------------

    102. We agree with WIRAB that no grace period should be allowed 
that can postpone the response. Accordingly, we deny AWEA's request to 
coordinate response times between interconnection customers and system 
operators.\213\ Instead, we require generating facilities to respond 
immediately, consistent with the technical capabilities of the 
generating facility and its control equipment.
---------------------------------------------------------------------------

    \213\ See AWEA Comments at 8-9 (describing efforts to coordinate 
the fast response times of wind facilities with system operators).
---------------------------------------------------------------------------

    103. Regarding the minimum period of time that a response should be 
sustained, we will not establish in this final action a minimum 
timeframe in minutes that the response to frequency deviations should 
be sustained since the amount of time that Interconnection frequency 
remains outside of the deadband varies by event.
    104. We determine that rather than using the term ``stable'' used 
in the NOPR concerning the sustained response requirement, it is 
preferable to require primary frequency response to be sustained until 
such time that system frequency returns to a value within the deadband. 
Therefore, we find that WIRAB's recommendation to adopt its definition 
of ``stable value'' is moot. Accordingly, we clarify that with the 
exception of certain operational constraints described in Section 
9.6.4.2 of the pro forma LGIA and Section 1.8.4.2 of the pro forma 
SGIA, generating facilities that respond to abnormal and sustained 
frequency deviations outside of the deadband parameter are required to 
provide and sustain primary frequency response until system frequency 
has returned to a value within the deadband parameter. If frequency 
recovers to within the deadband but suddenly deviates outside of the 
deadband parameter again, the interconnection customer will be required 
to provide and sustain its response until such time that frequency 
returns to a value within the deadband.
    105. Comments related to electric storage resources pertaining to 
the timely and sustained response provisions are addressed below in 
Section II.H.2.

D. Proposal Not To Mandate Headroom

1. NOPR Proposal
    106. In the NOPR, the Commission clarified that the proposed 
requirements did not impose a generic headroom requirement, but sought 
comment on such a requirement.\214\ The Commission stated its belief 
that the reliability benefits from the proposed

[[Page 9652]]

modifications to the pro forma LGIA and pro forma SGIA do not require 
imposing additional costs that would result from a generic headroom 
requirement.\215\
---------------------------------------------------------------------------

    \214\ NOPR, 157 FERC ] 61,122 at P 51.
    \215\ Id.
---------------------------------------------------------------------------

2. Comments
    107. Several commenters state that the Commission should not create 
a mandatory headroom requirement.\216\ Idaho Power asserts that a 
generic headroom requirement is not necessary at this time.\217\ AWEA, 
Public Interest Organizations, and SDG&E state that there are 
significant opportunity costs involved in maintaining headroom.\218\ 
WIRAB adds that not every generating facility needs to provide primary 
frequency response all the time; instead the decision of whether a 
generating facility provides primary frequency response and the 
necessary amount of headroom should be determined by economic 
considerations rather than by generic requirements.\219\ EEI supports 
the NOPR proposal not to include a generic headroom requirement in the 
pro forma LGIA and pro forma SGIA ``since these requirements go beyond 
capability (i.e., equipment specifications.)'' \220\ However, EEI also 
asserts that not requiring headroom while requiring all primary 
frequency responses to be timely and sustained would be discriminatory, 
because all generating facilities are not capable of timely 
responses.\221\ We address this assertion above in Section II.C.3.
---------------------------------------------------------------------------

    \216\ EEI, Public Interest Organizations, AWEA, ESA, ISO-RTO 
Council, Xcel, Idaho Power, WIRAB, NERC, First Solar.
    \217\ Idaho Power Comments at 2.
    \218\ AWEA Comments at 2; Public Interest Organizations Comments 
at 4; SDG&E Comments at 2.
    \219\ WIRAB Comments at 9.
    \220\ EEI Comments at 13.
    \221\ Id. at 11.
---------------------------------------------------------------------------

    108. AWEA requests that the Commission consider expanding on the 
NOPR proposal by finding that it would be unjust and unreasonable for a 
transmission provider to impose a requirement for all generating 
facilities to reserve headroom to provide primary frequency response 
due to the large inefficiency and cost of such a requirement.\222\ ESA 
asserts that it interprets the Commission's proposal as an explicit 
prohibition against requiring interconnection customers to reserve 
headroom as a condition of interconnection.\223\
---------------------------------------------------------------------------

    \222\ AWEA Comments at 3.
    \223\ ESA Comments at 2.
---------------------------------------------------------------------------

3. Commission Determination
    109. We will not mandate a headroom requirement at this time. We 
continue to believe that the reliability benefits from the proposed 
modifications to the pro forma LGIA and pro forma SGIA do not require 
imposing additional costs that would result from a generic headroom 
requirement.\224\
---------------------------------------------------------------------------

    \224\ NOPR, 157 FERC ] 61,122 at P 44.
---------------------------------------------------------------------------

    110. We decline to address AWEA's request to find it unjust and 
unreasonable for a transmission provider to impose a requirement for 
all generating facilities to reserve headroom to provide primary 
frequency response. Instead, in response to AWEA and ESA, we clarify 
that this final action does not prohibit a transmission provider from 
arguing to the Commission that headroom should be required as a 
condition of interconnection in a particular factual circumstance and 
proposing an associated compensation mechanism. We will evaluate any 
such filings on a case-by-case basis. Finally, we revise proposed 
Article 9.6.4 of the pro forma LGIA and Article 1.8.4 of the pro forma 
SGIA to delete the following reference: ``Nothing shall require the 
generating facility to operate above its minimum operating limit, below 
its maximum operating limit, or otherwise alter its dispatch to have 
headroom to provide primary frequency response.'' We believe that this 
phrase is unnecessary and that it is clear without it that we are not 
requiring headroom as a condition of interconnection.

E. Proposal Not To Mandate Compensation

1. NOPR Proposal
    111. The Commission did not propose to mandate compensation related 
to the new primary frequency response requirements, stating ``the 
Commission has previously accepted changes to transmission provider 
tariffs that similarly required interconnection customers to install 
primary frequency response capability or that established specific 
governor settings, without requiring any accompanying compensation.'' 
\225\ Further, the Commission clarified that the absence of a 
compensation mandate is not intended to prohibit a public utility from 
filing a proposal for primary frequency response compensation under 
section 205 of the FPA.\226\
---------------------------------------------------------------------------

    \225\ Id. P 55 (citing PJM Interconnection, L.L.C., 151 FERC ] 
61,097 at n.58; Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182, 
at PP 10-12 and 17 (2016); New England Power Pool, 109 FERC ] 61,155 
(2004), order on reh'g, 110 FERC ] 61,335 (2005)).
    \226\ Id.
---------------------------------------------------------------------------

2. Comments
    112. Many commenters support not mandating compensation.\227\ On 
the other hand, a few commenters reject the NOPR's overarching 
approach, asserting instead that a market-based approach or a 
centralized forward procurement process is needed.\228\ Other 
commenters qualify their support of the NOPR's approach to compensation 
on future efforts to establish forward procurement or market 
mechanisms.\229\
---------------------------------------------------------------------------

    \227\ ISO-RTO Council; WIRAB; Xcel; PG&E APPA et al.; EEI; MISO 
TOs; NRECA; California Cities; and SoCal Edison.
    \228\ AES; SDG&E API; Chelan County; R St. Institute; and CESA.
    \229\ AWEA; ELCON; Public Interest Organizations; and First 
Solar.
---------------------------------------------------------------------------

    113. Some commenters believe that compensation issues are best 
decided at the regional level.\230\ ISO-RTO Council asserts that not 
mandating compensation is reasonable because ``[f]undamentally, the 
costs of providing primary frequency response by all registered 
generators should be viewed simply as a cost of reliable generator 
operation (similar to, for example, maintenance, staffing, metering, 
software, and communications).\231\ APPA et al. agrees, stating that 
primary frequency response capability should be a standard feature of 
new generating facilities.\232\ APPA et al. also notes that the 
Commission recently recognized imposing requirements for generating 
facilities with governor controls without additional compensation is a 
just and reasonable condition of participation in wholesale 
markets.\233\ In addition, SoCal Edison believes that the costs of 
primary frequency response capability are already adequately recovered 
through existing bilateral or market-based capacity contracts.\234\
---------------------------------------------------------------------------

    \230\ Xcel Comments at 7; PG&E Comments at 2; EEI Comments at 
11; MISO TOs Comments at 14.
    \231\ ISO-RTO Council Comments at 10.
    \232\ APPA et al. Comments at 6.
    \233\ Id. (citing Cal. Indep. Sys. Operator Corp., 156 FERC ] 
61,182 at P 17 (2016)).
    \234\ SoCal Edison Comments at 4.
---------------------------------------------------------------------------

    114. AWEA states that the cost of attaining primary frequency 
response capability for new generators is low \235\ but asserts that 
the Commission's decision not to address compensation for primary 
frequency response capability in the proposed rulemaking is not a major 
concern, so long as there is no headroom requirement.\236\ California 
Cities compares primary frequency response with a number of 
interconnection requirements for generating facilities in which the 
recovery of capital costs and operating

[[Page 9653]]

expenses are not necessarily ensured.\237\ California Cities states 
that developers of new generating facilities have the opportunity to 
recover capital costs for primary frequency response capability in the 
same ways they recover other capital costs associated with generation 
resources and can factor the costs of primary frequency response into 
their economic assessment of project viability under anticipated market 
conditions and into their negotiations for capacity sales.\238\
---------------------------------------------------------------------------

    \235\ AWEA Comments at 1.
    \236\ Id. at 9.
    \237\ California Cities Comments at 4.
    \238\ Id.
---------------------------------------------------------------------------

    115. ELCON supports not mandating compensation, expressing its 
expectation that such costs should be low, observing that the 
administrative costs of a compensation scheme may outweigh the costs of 
providing mandated service.\239\ Further, ELCON joins APPA et al. in 
noting that this is consistent with prior Commission decisions 
requiring the installation of primary frequency response capability or 
specifying governor settings, without mandating compensation.\240\ 
ELCON emphasizes that its comments regarding compensation are limited 
to the currently proposed limited applicability of new requirements to 
new generation facilities because a broader approach would trigger more 
significant costs and should focus on market-based solutions such as 
that under Order No. 819.\241\
---------------------------------------------------------------------------

    \239\ ELCON Comments at 6.
    \240\ Id. n.4 (citing PJM Interconnection, L.L.C., 151 FERC ] 
61,097 at n.58; Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182, 
at PP 10-12 and 17 (2016); New England Power Pool, 109 FERC ] 61,155 
(2004), order on reh'g, 110 FERC ] 61,335 (2005)).
    \241\ Id. at 7.
---------------------------------------------------------------------------

    116. In support of compensation, several commenters state that the 
proposed requirements are inefficient or uneconomic because, among 
other points, they require new generating facilities to install and 
operate a governor or equivalent controls when the necessary primary 
frequency response could be provided at lower cost by another 
generating facility (e.g., battery storage or existing generating 
facility).\242\ These commenters believe that market-based procurement 
will create opportunities for transmission providers to obtain higher-
quality frequency response at a lower cost compared to a mandatory 
primary frequency response requirement for all newly interconnecting 
generating facilities. Rather than the mandatory requirements proposed 
in the NOPR, some commenters prefer market-based compensation to incent 
the ``right'' level of primary frequency response.\243\
---------------------------------------------------------------------------

    \242\ AES Companies Comments at 9; API Comments at 4; AWEA 
Comments at 11; ELCON Supplemental Comments at 12, in support of R 
St Institute's Comments; Competitive Suppliers Comments at 4; ESA 
Comments at 6; Public Interest Organizations Comments at 2; R St 
Institute Comments at 4; SDG&E Comments at 5-6 and SDG&E 
Supplemental Comments at 2-3. Public Interest Organizations, in 
their Comments at 5-6, refer to the need to remove settlement system 
``disincentives'' to the provision of primary frequency response by 
existing generators, which the Commission interprets as a request 
for compensation for providing this service.
    \243\ API Comments at 3-4; Chelan County Comments at 1-2; Public 
Interest Organizations Comments at 6-7; R St Institute's Comments at 
2-3; and SDG&E Comments at 3.
---------------------------------------------------------------------------

    117. Other commenters believe that generating facilities should not 
be required to provide primary frequency response without compensation 
for their costs of providing the service.\244\ SDG&E asserts that the 
NOPR proposals will not address the Commission's concerns regarding the 
decline in primary frequency response because ``uncompensated costs are 
at the root of poor historical performance.'' \245\ Further, AWEA 
raises concerns that it is unjust and unreasonable to mandate that new 
generation incur investment and maintenance costs to be primary 
frequency response capable without being provided a real opportunity to 
recover such costs.\246\ Competitive Suppliers assert that ``[a]ll 
resources that provide essential reliability services such as primary 
frequency response and inertia should be explicitly compensated rather 
than mandating generators provide them without distinct and additional 
compensation.'' \247\ Competitive Suppliers urge the Commission to 
address compensation in a final rule or additional NOPR.\248\ First 
Solar encourages the Commission to require compensation for the 
configuration and additional communication, software and control 
technologies required to operate the equipment at a solar PV generation 
facility to provide essential reliability services.\249\ First Solar 
believes that the Commission should also require ISOs and RTOs develop 
a funding mechanism and operational and market rules to accommodate the 
headroom requirements for these facilities to provide frequency 
response.\250\
---------------------------------------------------------------------------

    \244\ AWEA Comments at 10; ELCON Supplemental Comments at 12-13 
(over longer term); Competitive Suppliers Comments at 3, 5; ESA 
Comments at 6-7; First Solar Comments at 4; MISO TOs Comments at 5 
(compensation should be determined regionally); and SDG&E Comments 
at 3.
    \245\ SDG&E Comments at 3.
    \246\ AWEA Comments at 10.
    \247\ Competitive Suppliers Comments at 5.
    \248\ Id.
    \249\ First Solar Comments at 4.
    \250\ Id.
---------------------------------------------------------------------------

    118. ESA raises concerns that, without compensation, the primary 
frequency response requirement for electric storage ``may produce 
disproportionate adverse economic impacts.'' \251\ Therefore, ESA 
recommends that the Commission ``direct RTOs/ISOs to use pay-for-
performance principles to price primary frequency response provision.'' 
\252\ ESA relies on Order No. 755, where the Commission found that 
frequency regulation compensation practices that do not compensate 
performance result in rates that are unjust, unreasonable, and unduly 
discriminatory or preferential. ESA contends that the same argument 
applies to frequency response compensation.\253\
---------------------------------------------------------------------------

    \251\ ESA Comments at 4.
    \252\ Id. at 6.
    \253\ ESA Comments at 6-7 (citing Frequency Regulation 
Compensation in Organized Wholesale Power Markets, Order No. 755, 
FERC Stats. & Regs. ] 31,324, at P 2 (2011) (crossed referenced at 
137 FERC ] 61,064).
---------------------------------------------------------------------------

3. Commission Determination
    119. We will not mandate compensation for primary frequency 
response service in this final action. We are not persuaded by comments 
that assert: (1) Generating facilities should not be required to 
provide a service if there is not explicit compensation; (2) market-
based compensation would be more efficient than the NOPR proposal; (3) 
inertia should be compensated in this final action; and (4) that 
frequency regulation compensation under Order No. 755 requires that 
primary frequency response be compensated. We address each of these 
points below.
    120. Commenter assertions that the Commission is improperly 
requiring the provision of a service without compensation are 
misplaced. While we are requiring newly interconnecting generating 
facilities to install equipment capable of providing frequency response 
and adhere to specified operating requirements, we are not mandating 
headroom, which is a necessary component for the provision of primary 
frequency response service. In addition, as stated in the NOPR, ``[t]he 
Commission has previously accepted changes to transmission provider 
tariffs that similarly required interconnection customers to install 
primary frequency response capability or that established specified 
governor settings, without requiring any accompanying compensation.'' 
\254\ Further, we agree

[[Page 9654]]

with California Cities that there are interconnection requirements for 
generating facilities in which the recovery of capital costs and 
operating expenses are not necessarily ensured.
---------------------------------------------------------------------------

    \254\ NOPR, 157 FERC ] 61,122 at P 55 (citing PJM 
Interconnection, L.L.C., 151 FERC ] 61,097 at n.58; Cal. Indep. Sys. 
Operator Corp., 156 FERC ] 61,182 at PP 10-12 and 17; New England 
Power Pool, 109 FERC ] 61,155, order on reh'g, 110 FERC ] 61,335). 
The Commission reiterated this approach in Indianapolis Power & 
Light Company v. Midcontinent Indep. Sys. Operator, Inc., 158 FERC ] 
61,107, at PP 36-37 (2017) (Indianapolis Power) (denying 
Indianapolis Power's request that the Commission find MISO's Tariff 
to be unjust, unreasonable, and unduly discriminatory or 
preferential because it does not compensate suppliers of primary 
frequency response).
---------------------------------------------------------------------------

    121. On balance, we find that the record indicates that the cost of 
installing, maintaining, and operating a governor or equivalent 
controls is minimal.\255\ Also, the greatest cost associated with 
providing primary frequency response results from maintaining headroom, 
as noted by several commenters.\256\ No commenter provided any evidence 
suggesting that the costs of providing primary frequency response are 
greater than those indicated in the NOPR.\257\ While the Commission has 
approved specific compensation for discrete services that require 
substantial identifiable costs, such as for frequency regulation and 
operating reserves, the Commission has not required specific 
compensation for all reliability-related costs. We agree with those 
commenters who observe that minimal reliability-related costs such as 
those incurred to provide primary frequency response, are reasonably 
considered to be part of the general cost of doing business, and are 
not specifically compensated.
---------------------------------------------------------------------------

    \255\ See NOPR, 157 FERC ] 61,122 at PP 62-71; see also ISO-RTO 
Council Comments at 9 (stating ``the incremental cost to provide 
frequency response is minimal''); ELCON Comments at 6 (citing ``the 
low costs triggered by the NOPR's limited applicability to only new 
generating facilities''); AWEA Comments at 1 (stating ``the cost of 
attaining [primary frequency response] capability for new generators 
is low.'').
    \256\ See AWEA Comments at 9; Public Interest Organizations 
Comments at 4.
    \257\ See NOPR, 157 FERC ] 61,122 at P 41 (stating that ``small 
generating facilities are capable of installing and enabling 
governors at low cost in in a manner comparable to large generating 
facilities.'').
---------------------------------------------------------------------------

    122. With regard to requests for the Commission to mandate market-
based compensation, we are not persuaded by assertions that mandatory 
market-based mechanisms for the procurement of primary frequency 
response capability are just and reasonable at this time given the 
record before us. While some economic efficiency may be gained from 
acquiring primary frequency response from the subset of generation that 
is most economically efficient at providing this service, we believe 
that the time and costs of developing a market in RTO/ISO regions or 
bilaterally purchasing the service in non-RTO/ISO regions should be 
carefully considered. ISO-RTO Council asserts, for example, that the 
administrative costs of developing and implementing market-based 
compensation of primary frequency response are likely to outweigh the 
incremental efficiency benefits.\258\ Similarly, SDG&E states that, to 
develop a market, each RTO/ISO will have to address issues such as 
developing complex software to operate the market and verifying 
generator performance in sub-minute intervals, which may require the 
installation of high-quality metering equipment such as phasor 
measurement units.\259\ Nonetheless, an RTO/ISO may propose such an 
approach upon an adequate showing under section 205, if it so chooses.
---------------------------------------------------------------------------

    \258\ See ISO-RTO Council Comments at 9-10. See also ELCON 
Comments at 6.
    \259\ See SDG&E Comments at n.6.
---------------------------------------------------------------------------

    123. With regard to Competitive Suppliers' view that the Commission 
should mandate explicit compensation for inertial response, we decline 
to adopt such a requirement.\260\ We recognize the reliability value of 
inertial response, as it helps to slow the rate of change of frequency 
during frequency deviations. In addition, very low levels of inertial 
response within an Interconnection increase the risk that the speed of 
primary frequency response delivery will be too slow to prevent large 
frequency deviations from exceeding pre-determined thresholds for load 
shedding or automatic generator trip protection. However, no commenter 
asserts that inertial response trends on the Eastern and Western 
Interconnections are approaching levels that could threaten 
reliability. In addition, because inertial response is provided 
automatically by the rotating mass of synchronous machines as system 
frequency deviates and is not controllable, synchronous generating 
facilities do not incur additional incremental costs to provide 
inertial response. Indeed, neither Competitive Suppliers nor any other 
commenter has indicated what, if any, incremental costs must be 
incurred to provide inertial response. Accordingly, we conclude that 
compensation for inertial response compensation is not warranted at 
this time.
---------------------------------------------------------------------------

    \260\ See Competitive Suppliers Comments at 5.
---------------------------------------------------------------------------

    124. We disagree with ESA's contention that the treatment of 
frequency regulation under Order No. 755 requires compensation of 
primary frequency response in this final action. In Indianapolis Power, 
the Commission rejected a similar request for primary frequency 
response compensation based on Order No. 755, finding that ``Order No. 
755 is inapposite, as that order involved an existing market, where the 
Commission found that the frequency regulation compensation practices 
of RTOs and ISOs resulted in rates that are unjust, unreasonable, and 
unduly discriminatory or preferential.'' \261\ For similar reasons, 
Order No. 755 is inapposite here.
---------------------------------------------------------------------------

    \261\ Indianapolis Power, 158 FERC ] 61,107 at P 37.
---------------------------------------------------------------------------

    125. AES and MISO TOs request that the Commission allow for the 
development of primary frequency response pools, self-supply of primary 
frequency response, and transferred primary frequency response 
markets.\262\ We conclude that existing requirements (e.g., contracts 
for frequency response service under Order No. 819,\263\ and recent 
Commission action regarding transferred frequency response \264\) 
already address two of these options. Also, a Frequency Response 
Sharing Group under Reliability Standard BAL-003-1.1, is an option 
currently available to balancing authorities.
---------------------------------------------------------------------------

    \262\ AES Comments at 5; MISO TOs Comments at 11.
    \263\ Third-Party Provision of Primary Frequency Response 
Service, Order No. 819, FERC Stats. & Regs. ] 31,375 (2015) (cross-
referenced at 153 FERC ] 61,220).
    \264\ Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182, order 
on clarification, compliance, and rehearing, 158 FERC ] 61,129 
(2017).
---------------------------------------------------------------------------

    126. Finally, nothing in this final action is meant to prohibit a 
public utility from filing a proposal for primary frequency response 
compensation under section 205 of the FPA.\265\
---------------------------------------------------------------------------

    \265\ See NOPR, 157 FERC ] 61,122 at P 55.
---------------------------------------------------------------------------

F. Application to Existing Generating Facilities That Submit New 
Interconnection Requests That Result in an Executed or Unexecuted 
Interconnection Agreement

1. NOPR Proposal
    127. In the NOPR, the Commission proposed to apply the revisions to 
the pro forma LGIA and pro forma SGIA to new generating facilities that 
execute or request the unexecuted filing of interconnection agreements 
on or after the effective date of any final action issued.\266\ The 
Commission also proposed to apply the requirements to any large or 
small generating facility that has an executed or has requested the 
filing of an unexecuted LGIA or SGIA as of the effective date of any 
final action, but that takes any action that requires the submission of 
a new interconnection request on or after the effective date of any 
final action.\267\ The Commission sought comment on the

[[Page 9655]]

proposed effective date, including whether the proposed application of 
the requirements would be unduly burdensome.\268\
---------------------------------------------------------------------------

    \266\ Id. P 54.
    \267\ Id.
    \268\ Id.
---------------------------------------------------------------------------

2. Comments
    128. Most commenters addressing this issue agree with the proposed 
effective date and applicability, with some suggesting additional 
action would be helpful.\269\ While Bonneville supports the 
Commission's proposed effective dates, it observes that ``if 
significant modifications are made to the generating facility, the cost 
of including primary frequency response capability may not add much to 
the cost of the modifications themselves.'' \270\ Therefore, Bonneville 
believes that the Commission should ``explore defining what constitutes 
a `significant modification''' and require existing generating 
facilities to include primary frequency response capability when making 
one.\271\ California Cities support the Commission's proposal because 
the proposal is sufficiently narrow as to only include those generating 
facilities that make a substantial change.\272\
---------------------------------------------------------------------------

    \269\ Idaho Power Comments at 2; WIRAB Comments at 8-9; First 
Solar Comments at 4; Bonneville Comments at 3; California Cities 
Comments at 3-4; ISO-RTO Council Comments at 8.
    \270\ Bonneville Comments at 3.
    \271\ Id.
    \272\ California Cities Comments at 3-4.
---------------------------------------------------------------------------

    129. Other commenters, however, believe that the NOPR proposal 
should go further. ISO-RTO Council states that it ``is unaware of any 
limitations that would render the Commission's proposed effective date 
infeasible or unduly burdensome'' and therefore it supports the 
proposed effective date.\273\ However, ISO-RTO Council suggests that 
the Commission expand the application of the primary frequency response 
capability and operating requirements to both conforming and non-
conforming interconnection agreements resulting from new 
interconnection requests by existing generating facilities.\274\ ISO-
RTO Council explains that under the NOPR proposal, an existing 
interconnection customer that ``takes an action that requires the 
submission of a new interconnection request resulting in the execution 
of a conforming interconnection agreement would not be obligated under 
the Commission's proposed requirements because the interconnection 
agreement would not be filed.'' \275\ Therefore, ISO-RTO Council 
recommends that the proposed requirements apply to any existing 
interconnection customer that takes any action that requires the 
submission of a new interconnection request that results in the 
execution of an interconnection agreement, regardless of whether the 
agreement is filed, or the filing of an unexecuted interconnection 
agreement after the effective date of any final action.\276\
---------------------------------------------------------------------------

    \273\ ISO-RTO Council Comments at 8.
    \274\ Id.
    \275\ Id.
    \276\ Id.
---------------------------------------------------------------------------

    130. Xcel contends that the Commission's proposal does not go far 
enough to ensure future generating facilities are capable of providing 
primary frequency response.\277\ Xcel's concern pertains to the 
possibility of a generating facility obtaining an interconnection 
agreement for more generation than is initially installed. In this 
situation, new generating facilities installed years after the 
effective date of the final action would not be required to install 
primary frequency response capability because a new interconnection 
agreement for subsequent phases is not required.\278\ Therefore, Xcel 
asks the Commission to consider requiring that any new generating 
facility added to expand an existing large or small generating facility 
more than two years after the effective date of the final action be 
required to provide primary frequency response, even if no new 
interconnection agreement is required.\279\
---------------------------------------------------------------------------

    \277\ Xcel Comments at 6.
    \278\ Id.
    \279\ Id. Xcel states that this approach should not apply to an 
uprate of an existing facility.
---------------------------------------------------------------------------

    131. SVP raises concerns that the proposed reforms could apply to 
existing generating facilities if interconnection customers amend their 
interconnection agreements for minor updates involving no material 
substantive changes to the interconnected facilities or to the 
interconnection itself.\280\ SVP explains that as a licensee of three 
hydropower projects, each with a generating capacity of less than 20 
MW, SVP has for over 30 years continually procured interconnection 
service for these facilities through an interconnection agreement with 
PG&E.\281\ SVP states that it is coordinating with PG&E and CAISO to 
reformat the existing agreements and that it may execute and file an 
amended agreement after the effective date of the final action with no 
material changes to the facilities or to the interconnection.\282\ SVP 
seeks clarification that the proposed reforms will not apply to 
existing facilities with existing interconnection agreements that 
execute new form agreements if there are no material substantive 
changes to the interconnected facilities or to the interconnection 
itself.\283\
---------------------------------------------------------------------------

    \280\ SVP Comments at 5-6.
    \281\ Id. at 4-5.
    \282\ Id. at 5.
    \283\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    132. With the clarifications noted below, we adopt the NOPR 
proposal to apply the primary frequency response requirements adopted 
herein to all newly interconnecting generating facilities as well as to 
all existing large and small generating facilities that take any action 
that requires the submission of a new interconnection request that 
results in the filing of an executed or unexecuted interconnection 
agreement on or after the effective date of this final action.\284\ In 
response to SVP's request, we clarify that where the submission of a 
new interconnection request by an existing generating facility results 
in an executed or unexecuted interconnection agreement by that existing 
generating facility, such event would be considered the triggering 
event that would impose the requirements of this final action. 
Accordingly, should an existing interconnection customer sign a new or 
amended interconnection agreement for reformatting purposes only those 
existing generating facilities would not be subject to the requirements 
of this final action.\285\
---------------------------------------------------------------------------

    \284\ NOPR, 157 FERC ] 61,122 at P 63.
    \285\ Article 1 of the pro forma LGIA defines an interconnection 
request as: ``an interconnection customer request, in the form of 
Appendix 1 to the Standard Large Generator Interconnection 
Procedures, in accordance with the Tariff, to interconnect a new 
Generating Facility, or to increase the capacity of, or make a 
Material Modification to the operating characteristics of, an 
existing Generating Facility that is interconnected with the 
Transmission Provider's Transmission System.'' Sections 30.9 and 
30.10 of the pro forma LGIA provide that the LGIA and its appendices 
may be amended by mutual agreement of the parties and do not state 
that a new interconnection request must be submitted in order to do 
so.
---------------------------------------------------------------------------

    133. Bonneville suggests that the Commission should ``explore 
defining what constitutes a `significant modification' '' to existing 
generating facilities that would subject them to the primary frequency 
response requirements adopted in this final action. It is unclear what 
Bonneville means by ``significant modification.'' However, we note that 
under the pro forma LGIP, a ``material modification'' \286\ to an 
existing generating facility would result in an interconnection request 
requiring a new interconnection agreement, thereby

[[Page 9656]]

subjecting the existing generating facility to the requirements adopted 
in this final action.\287\ The Commission has not adopted a bright-line 
definition of what constitutes a material modification; rather, that is 
a fact-specific inquiry.\288\ Bonneville has not persuaded us that we 
should adopt such a bright line now. Bonneville provides no information 
regarding how many, if any, modification requests by existing 
generating facilities would not be deemed material, and would therefore 
not trigger the requirements of this final action, since the 
interconnection customer would not be required to submit a new 
interconnection request or execute a new interconnection agreement. 
Accordingly, we are not persuaded by Bonneville of the need to include 
a definition for the new term ``significant modification'' at this 
time.
---------------------------------------------------------------------------

    \286\ The pro forma LGIA defines a Material Modification as: 
``those modifications that have a material impact on the cost or 
timing of any Interconnection Request with a later queue priority 
date.''
    \287\ See pro forma LGIP Sec. 4.4.3.
    \288\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 168.
---------------------------------------------------------------------------

    134. Similarly, Xcel provides no support for its suggestion that a 
significant number of new generating facilities, covered by a prior 
interconnection agreement, may be built two or more years following the 
effective date of this final action and therefore should be subject to 
the primary frequency response requirements.\289\ Accordingly, we 
decline to adopt Xcel's suggestion to require ``new generating 
facilities that are interconnected two years or more after the 
effective date of the Final Rule [to] also meet these requirements, 
even if a new interconnection agreement is not required.'' \290\
---------------------------------------------------------------------------

    \289\ Xcel Comments at 6.
    \290\ Id. at 4.
---------------------------------------------------------------------------

    135. Further, the Commission believes that ISO-RTO Council's 
request that ``the Commission expand the application of the primary 
frequency response requirements to both conforming and non-conforming 
interconnection agreements resulting from new interconnection requests 
by existing generators'' is unnecessary.\291\ ISO-RTO Council's concern 
relates to the NOPR's use of the phrase ``filing of an executed or 
unexecuted interconnection agreement.'' \292\ We note that if an 
interconnection customer executes a new conforming interconnection 
agreement for an existing generating facility as a result of a new 
interconnection request, the agreement would not be filed at the 
Commission but instead reported in Electric Quarterly Reports (EQRs). 
However, a conforming new or amended LGIA or SGIA would need to conform 
to the specific transmission provider's most recently revised pro forma 
LGIA and pro forma SGIA, which would include the requirements of this 
final action. The Commission clarifies that the final action is 
intended to apply to all existing generating facilities that submit a 
new interconnection request that results in an executed or unexecuted 
interconnection agreement, regardless of whether that agreement is 
filed at the Commission or merely reported in EQRs.
---------------------------------------------------------------------------

    \291\ ISO-RTO Council Comments at 8.
    \292\ See NOPR, 157 FERC ] 61,122 at PP 46, 54, 63.
---------------------------------------------------------------------------

G. Application to Existing Generating Facilities That Do Not Submit New 
Interconnection Requests That Result in an Executed or Unexecuted 
Interconnection Agreement

1. NOPR Proposal
    136. In the NOPR, the Commission sought comment on the proposal to 
apply the proposed reforms only to newly interconnecting generating 
facilities. In particular, the Commission sought comment on whether 
additional primary frequency response performance or capability 
requirements for existing facilities are needed, and if so, whether the 
Commission should impose those requirements by: (1) Directing the 
development or modification of a reliability standard pursuant to 
section 215(d)(5) of the FPA; or (2) acting pursuant to section 206 of 
the FPA to require changes to the pro forma OATT.\293\
---------------------------------------------------------------------------

    \293\ NOPR, 157 FERC ] 61,122 at PP 3, 57.
---------------------------------------------------------------------------

2. Comments
    137. Most commenters oppose applying the proposed primary frequency 
response requirements to existing generating facilities.\294\ Several 
commenters argue that requiring existing generating facilities to 
install and operate governors or equivalent controls would be overly 
expensive and unnecessarily burdensome.\295\ Specifically, AWEA 
contends that a retroactive primary frequency response requirement 
would be particularly costly for older wind turbines with fixed blades 
that cannot physically provide primary frequency response, newer wind 
turbines that would still require substantial hardware and software 
changes, and turbines from vendors that are out of business.\296\ 
Moreover, some commenters argue that a blanket requirement is 
unnecessary given generally adequate levels of frequency response at 
this time.\297\
---------------------------------------------------------------------------

    \294\ PG&E, APPA et al., AWEA, NRECA, WIRAB, ELCON, Competitive 
Suppliers, TVA, Public Interest Organizations, and Sunflower and 
Mid-Kansas oppose expanding the applicability of the reforms to 
existing generating facilities.
    \295\ APPA et al. Comments at 7-8; NRECA Comments at 10; Public 
Interest Organization Comments at 4; ELCON Comments at 5-6.
    \296\ AWEA Comments at 4.
    \297\ NRECA Comments at 10; WIRAB Comments at 10-12; Competitive 
Suppliers Comments at 6.
---------------------------------------------------------------------------

    138. NERC and the NYTOs contend that it is too soon after the 
implementation of Reliability Standard BAL-003-1.1 to determine whether 
it is necessary or appropriate to impose requirements for primary 
frequency response on existing generating facilities.\298\
---------------------------------------------------------------------------

    \298\ NERC Comments at 8; NYTOs Supplemental Comments at 3-4.
---------------------------------------------------------------------------

    139. On the other hand, Bonneville and ISO-RTO Council support 
reforms that would apply to existing generating facilities, suggesting 
that the Commission direct NERC to develop a Reliability Standard for 
frequency response. While Bonneville states that the cost to retrofit 
existing generators may be prohibitive, it contends that a standard 
similar to TRE's regional Reliability Standard BAL-001-TRE-01, which 
requires generator owners/operators in the Texas region to set their 
governors to meet performance requirements, would ensure both 
capability and performance.\299\ ISO-RTO Council argues that the 
development of a Reliability Standard will spread frequency response 
requirements over many generating facilities in a non-discriminatory 
manner and help facilitate compliance with Reliability Standard BAL-
003-1.1.\300\
---------------------------------------------------------------------------

    \299\ Bonneville Comments at 3-4.
    \300\ ISO-RTO Council Comments at 13.
---------------------------------------------------------------------------

    140. Other commenters suggest that the Commission should wait to 
apply the proposed reforms to existing generation facilities until 
further research is completed. APPA et al. state that NERC's required 
report on the availability of generating facilities to provide 
frequency response,\301\ due in July 2018, will better inform the 
Commission whether further action is needed on existing generating 
facilities.\302\ WIRAB states that while it does not believe new or 
modified Reliability Standards are currently needed, it recommends that 
the Commission ``direct NERC and the Regional Entities to measure and 
monitor frequency response, particularly governor response and 
withdrawal, in Event Analysis and track resulting trends,'' \303\ and 
develop guidelines and best practices that reflect regional 
differences.\304\ WIRAB states

[[Page 9657]]

that NERC's Frequency Response Annual Analysis Report ``can easily be 
expanded to track trends, model and analyze frequency response in each 
of the interconnections over a 10-year time horizon, and to make 
recommendations regarding current and future frequency response 
needs.'' \305\ WIRAB states that if significant declines in frequency 
response occur, such as decreasing frequency nadirs or continued 
evidence of governor withdrawal, the Commission could then direct NERC 
and the Regional Entities to develop or modify their mandatory 
reliability standards and/or update NERC's Primary Frequency Control 
Guideline to ensure frequency response is preserved.\306\
---------------------------------------------------------------------------

    \301\ Order No. 794, 146 FERC ] 61,024 at P 3.
    \302\ APPA et al. Comments at 3-4.
    \303\ WIRAB Comments at 10.
    \304\ Id. at 4.
    \305\ Id. at 10.
    \306\ Id. at 11.
---------------------------------------------------------------------------

    141. In order to encourage regional flexibility and periodic 
updating of the proposed maximum droop and deadband settings, WIRAB 
recommends that the Commission direct NERC and the Regional Entities 
``to monitor frequency response capability in each region, revisit and 
revise NERC's droop and deadband setting guidelines as needed, and 
generated best practices'' to encourage generating facilities to 
``appropriately tighten regional droop and deadband settings as needed 
to maintain system reliability.'' \307\ Further, WIRAB recommends that 
the Commission periodically reexamine the specific droop and deadband 
settings, which should not be viewed as a ``once-and-for-all 
decision.'' \308\ In support of its position, WIRAB reminds the 
Commission that NERC's Primary Frequency Control Guideline states that 
tighter deadband settings of approximately 0.017 Hz can be 
successfully implemented and encouraged efforts to lower deadband 
settings to that level.\309\
---------------------------------------------------------------------------

    \307\ Id. at 4.
    \308\ Id.
    \309\ Id. at 4-5.
---------------------------------------------------------------------------

    142. Similarly, ISO-RTO Council requests the monitoring of the need 
for existing generators to provide primary frequency response. ISO-RTO 
Council acknowledges that NERC and the industry have already taken 
steps to ensure sufficient primary frequency response, including the 
development of Reliability Standard BAL-003-1.1, publishing an 
operating guide for generating facilities, outreach to governor and 
controls manufacturers, conducting webinars, as well as outreach to the 
North American Generator Forum.\310\ ISO-RTO Council asserts that the 
Commission should not delay the issuance of the final action by 
requiring the development of a Reliability Standard for existing 
generating facilities.\311\ Instead, it maintains such requirements 
should be evaluated and, if necessary, proposed in a future 
proceeding.\312\
---------------------------------------------------------------------------

    \310\ ISO-RTO Council Comments at 11, n.23.
    \311\ Id.
    \312\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    143. 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. We conclude that applying the proposed requirements only to 
newly interconnecting generating facilities will adequately address the 
Commission's concerns regarding primary frequency response. We are 
persuaded by commenters that requiring existing generating facilities 
that have not submitted a new interconnection request to install and 
operate governors or equivalent controls would be overly expensive and 
unnecessarily burdensome.\313\ The record indicates that costs of 
installing primary frequency response capability is minimal for newly 
interconnecting generating facilities, and as such, we do not believe 
that a mandate for compensation is needed at this time. However, the 
record also indicates that the expense to some existing facilities may 
be cost prohibitive,\314\ for example if retrofits are needed, and 
accordingly we believe that applying the requirements to existing 
generating facilities may be unduly burdensome.
---------------------------------------------------------------------------

    \313\ APPA et al. Comments at 7-8; NRECA Comments at 10; Public 
Interest Organization Comments at 4; ELCON Comments at 5-6.
    \314\ See, e.g., Bonneville Comments at 3.
---------------------------------------------------------------------------

    144. We agree that NERC, the Regional Entities, and other affected 
industry stakeholders should continue to measure and monitor the impact 
of Reliability Standard BAL-003-1.1 on generating facility frequency 
response performance, and the amount and adequacy of primary frequency 
response generally. We note that Order No. 794 required NERC to file in 
July 2018 the results of a study on the availability of existing 
generating facilities to provide primary frequency response.\315\ We 
expect that NERC's July 2018 report will inform the Commission if 
additional action is warranted regarding the need to impose additional 
requirements on existing generating facilities.
---------------------------------------------------------------------------

    \315\ Order No. 794, 146 FERC ] 61,024 at P 3.
---------------------------------------------------------------------------

    145. NERC's July 2018 report will afford an opportunity for all 
interested parties to consider WIRAB's recommendation to expand the 
scope of NERC's Frequency Response Annual Analysis Report and/or State 
of Reliability Report to ``track trends, model and analyze frequency 
response in each of the [I]nterconnections over a 10-year time horizon, 
and to make recommendations regarding current and future frequency 
response needs.'' \316\ The July 2018 report may also provide insight 
into whether NERC should consider tracking and reporting the resulting 
trends of frequency response performance at the regional level (e.g., 
at the regional entity or balancing authority level), and if necessary, 
develop guidelines and/or best practices that reflect regional 
differences.\317\ This will allow the Commission to access future 
standards directives, as necessary.
---------------------------------------------------------------------------

    \316\ See WIRAB Comments at 10.
    \317\ NERC already tracks frequency response performance at the 
Interconnection-wide level in its annual State of Reliability 
Report.
---------------------------------------------------------------------------

    146. We also encourage NERC to review, and if necessary, update its 
Primary Frequency Control Guideline as appropriate to reflect changes 
in the generation resource mix, particularly as it pertains to the 
technical attributes of non-synchronous generating facilities.
    147. In addition, NERC and the Regional Entities should also 
continue to monitor the operation and impact of the operating 
requirements for droop, deadband, and sustained response adopted in 
this final action, and recommend to the Commission any changes to those 
settings (e.g., lower droop values or tighter deadband settings) in the 
future that may become appropriate in light of changed circumstances.

H. Requests for Exemption or Special Accommodation

1. Combined Heat and Power Facilities
a. NOPR Proposal
    148. In the NOPR, the Commission proposed to apply the primary 
frequency response capability and operating requirements to all newly 
interconnecting generating facilities, including CHP facilities.
b. Comments
    149. ELCON and API contend that the special characteristics of 
industrial CHP generating facilities warrant an exemption or special 
accommodation from the proposed revisions to the pro forma LGIA and pro 
forma SGIA.\318\

[[Page 9658]]

ELCON is concerned that, because of the unique connection between their 
generation and industrial equipment, the mandatory nature of the new 
primary frequency response requirements could adversely impact the 
manufacturing processes of its member companies. ELCON asserts that the 
generation equipment in CHP facilities ``which are part and parcel of 
the load itself, cannot be treated as if they were conventional, stand-
alone generators, and forcing them to act as stand-alone generation 
will compromise and potentially harm the manufacturing process by 
interfering with the steam balance.'' \319\
---------------------------------------------------------------------------

    \318\ ELCON Comments at 8-9; API Comments at 4-5. The Commission 
notes that API states that CHP and cogeneration facilities are 
interchangeable. See API Comments at 2. However, this final action 
uses only the term ``CHP'' to avoid confusion with ``cogeneration 
facility,'' which is a defined term under the Public Utility 
Regulatory Policies Act of 1978. See 18 CFR 292.203(b) and 292.205 
(2017).
    \319\ ELCON Comments at 9.
---------------------------------------------------------------------------

    150. In particular, ELCON explains that ``[g]eneration equipment 
that is integrated with industrial process equipment is operated to 
optimize the overall manufacturing process including the safe operation 
of critical infrastructure'' and that ``[r]equiring all industrial 
generation to provide primary frequency response without respect to the 
operational needs of the manufacturing process may jeopardize the 
reliability and safe operation of both.'' \320\
---------------------------------------------------------------------------

    \320\ Id. at 8.
---------------------------------------------------------------------------

    151. ELCON explains that there are a ``wide variety of 
configurations and capacities in the universe of CHP generators that 
are dedicated to an industrial process,'' with some CHP industrial 
facilities designed to generate in excess of their load having ``the 
flexibility to provide [primary frequency response] to the extent their 
industrial process would not be impacted.'' \321\ ELCON also notes that 
other CHP facilities are sized to match their industrial load, ``which 
in reality means sized to the steam or thermal requirement of the host 
manufacturing process.'' \322\ ELCON asserts that ``[s]uch facilities 
cannot reasonably provide [primary frequency response] service without 
compromising the efficiency, reliability and safe operation of the 
manufacturing process.'' \323\
---------------------------------------------------------------------------

    \321\ ELCON Supplemental Comments at 2-3.
    \322\ Id.
    \323\ Id.
---------------------------------------------------------------------------

    152. For example, ELCON states that an increasing number of 
manufacturers are installing turbines at their industrial facilities to 
obtain lower emissions and other benefits \324\ that are susceptible to 
a loss of combustion during certain types of frequency excursions. 
ELCON explains that such events could have severe consequences, 
including load curtailment and suspension, a manufacturing shutdown, 
and execution of emergency procedures to de-pressure and stabilize 
equipment.\325\ ELCON states that additional implications of such 
events include ``the loss of production, possibly for an extended 
period, additional maintenance and repair costs for equipment, 
additional personnel costs, excess emissions during shutdown and 
startup procedures, and although the shutdown process is designed to be 
executed safely and effectively, some increased potential for safety, 
health, and environmental consequences.'' \326\ During under-frequency 
conditions, the provision of primary frequency response results in 
increased MW output, which ELCON explains may result in a level of 
steam production that exceeds the operating requirements of the 
manufacturing process.\327\
---------------------------------------------------------------------------

    \324\ Combustion turbines operating in ``lean-burn'' mode use a 
higher air to fuel ratio (i.e., excess air is allowed into the 
process) to reduce NOx emissions.
    \325\ ELCON Supplemental Comments at 4.
    \326\ Id. at 4-5.
    \327\ Id. at 6. ELCON raises an additional concern that 
mandating primary frequency response could discourage the 
development of CHP facilities ``because of the added investment 
cost, operational risk, efficiency loss and regulatory burden.'' Id. 
at 9.
---------------------------------------------------------------------------

    153. To address these concerns, ELCON states that ``the proposed 
LGIA and SGIA language should be revised to explicitly exclude 
imposition of mandatory primary frequency response obligations on 
industrial CHP units and other similarly-situated forms of industrial 
behind-the-meter generation.'' \328\ ELCON proposes the following new 
language for the pro forma LGIA, Section 9.6.4.3 and pro forma SGIA, 
Section 1.8.4.3 to specifically exempt ``industrial behind-the-meter 
generation that is sized-to-load (i.e., the industrial load and the 
generation are near-balanced in real-time operation and the generation 
is controlled to maintain the unique thermal, chemical, or mechanical 
output necessary for the operating requirement of its host industrial 
facility).'' \329\ ELCON asserts, however, that an exemption from the 
mandatory primary frequency response obligation still could allow 
certain industrial processes that are capable of providing primary 
frequency response to opt-in to such arrangements.\330\
---------------------------------------------------------------------------

    \328\ Id. at 9.
    \329\ Id. at 11.
    \330\ Id.
---------------------------------------------------------------------------

    154. API supports ELCON's exemption request, adding that CHP 
facilities bring certain benefits such as high efficiency and lowered 
emissions and that the proposal may present a barrier to entry for such 
generating facilities.\331\ API contends that adjusting operating 
levels for reasons outside of the manufacturing process, such as in 
response to instructions of the balancing authority, ``risks a decline 
in CHP efficiency and may introduce substantial risks to the 
manufacturing process.'' \332\ Accordingly, API requests that the final 
action exempt all CHP technologies from maintaining and operating 
automatic turbine-generator governors as a condition of 
interconnection, regardless of whether they are sized for load or 
not.\333\
---------------------------------------------------------------------------

    \331\ API Comments at 5.
    \332\ Id.
    \333\ Id. at 4.
---------------------------------------------------------------------------

c. Commission Determination
    155. The Commission exempts newly interconnecting CHP facilities 
that are sized to serve on-site load and have no material export 
capability from the operating requirements of this final action. 
However, considering the low costs associated with governor 
installation, we will require all newly interconnecting CHP facilities, 
including those sized-to-load, to install a governor or equivalent 
control equipment capable of providing primary frequency response as a 
condition of interconnection as proposed in the NOPR.\334\ We believe 
that it is prudent to require newly interconnecting CHP facilities to 
install primary frequency response capability now in the event that 
there is an increased need in the future for primary frequency response 
capability. Further, we adopt, with certain modifications, the 
definition of ``sized-to-load'' contained in ELCON's proposed new 
language for the pro forma LGIA and pro forma SGIA.\335\ In particular, 
we define CHP facilities that are ``sized-to-load'' as those generating 
facilities that are behind-the-meter generation that are sized-to-load 
(i.e., the thermal load and the generation are near-balanced in real-
time operation and the generation is primarily controlled to maintain 
the unique thermal, chemical, or mechanical output necessary for the 
operating requirement of its host facility).\336\ We believe that 
ELCON's request to limit the definition of ``sized-to-load'' only to 
industrial CHP facilities is too narrow.
---------------------------------------------------------------------------

    \334\ ELCON noted ``the low costs triggered by the NOPR's 
limited applicability to only new generation facilities'' when 
agreeing with the Commission's proposal not to mandate compensation. 
ELCON Comments at 6.
    \335\ See ELCON Supplemental Comments at 11.
    \336\ Id.
---------------------------------------------------------------------------

    156. We agree with ELCON and API that CHP facilities sized-to-load 
present

[[Page 9659]]

unique concerns regarding the efficiency, reliability, and safe 
operation of their industrial processes that warrant this exemption. 
For example, ELCON notes that an increasing number of interconnection 
customers with CHP facilities are using turbines susceptible to a loss 
of combustion during certain types of frequency excursions, and that 
such events could have severe consequences, including load curtailment 
and suspension, a manufacturing shutdown, and execution of emergency 
procedures to de-pressure and stabilize equipment.\337\ Additionally, 
during under-frequency conditions, the provision of primary frequency 
response results in increased MW output, which ELCON explains may 
result in a level of steam production that exceeds the operating 
requirements of the manufacturing process.\338\
---------------------------------------------------------------------------

    \337\ ELCON Supplemental Comments at 4.
    \338\ Id. at 6. ELCON raises an additional concern that 
mandating primary frequency response could discourage the 
development of CHP facilities ``because of the added investment 
cost, operational risk, efficiency loss and regulatory burden.'' Id. 
at 9.
---------------------------------------------------------------------------

2. Electric Storage Resources
a. NOPR Proposal
    157. The NOPR proposed to apply the primary frequency response 
capability and operating requirements to all new generating facilities, 
including electric storage resources, without exception.
b. Comments
i. NOPR Comments
    158. While most comments on the NOPR did not specifically request 
an exemption for electric storage resources, some commenters suggest 
changes to the proposed pro forma LGIA and pro forma SGIA provisions to 
accommodate electric storage resources. In particular, ESA argues that 
the proposed requirements disproportionately affect electric storage 
resources in four ways.\339\ First, ESA states that the use of a 
nameplate capacity basis for primary frequency response will require 
storage to provide more frequent and greater magnitude of primary 
frequency response service than traditional generating facilities.\340\ 
For example, ESA argues if a traditional generating facility with a 
nameplate capacity of 100 MW has a minimum set point of 40 MW, the 
primary frequency response service will be based on the 60 MW of 
capacity above that minimum set point. However, ESA states that 
electric storage has no minimum set point and is capable of operating 
at the full range of its capacity for withdrawals and injections.\341\
---------------------------------------------------------------------------

    \339\ ESA Comments at 3.
    \340\ Id. at 3-4.
    \341\ Id.
---------------------------------------------------------------------------

    159. Second, ESA claims that whereas traditional generating 
facilities start-up and shut-down as a part of normal operations and 
are not required to provide primary frequency response while offline, 
electric storage resources are, by contrast, ``always online'' even 
when not charging or discharging.\342\ Therefore, ESA suggests that 
electric storage resources will be available, on a more frequent basis, 
to provide primary frequency response than other generating facilities 
that go offline.\343\ Third, ESA states that different electric storage 
technologies have different optimal depths of discharge, and exceeding 
the optimal depth of discharge accelerates the degradation of the 
facility and increases operations and maintenance costs. ESA asserts 
that this scenario indicates the potential of the use of nameplate 
capacity as the basis for primary frequency response to result in a 
disproportionate impact on electric storage resources.\344\
---------------------------------------------------------------------------

    \342\ Id. at 4.
    \343\ Id.
    \344\ Id. at 3-4.
---------------------------------------------------------------------------

    160. Fourth, ESA notes that unlike traditional generating 
facilities, electric storage is energy limited. Thus, ESA argues that 
the requirement to sustain output in proposed section 9.6.4.2 of the 
pro forma LGIA poses unique regulatory and financial exposure, such as 
NERC violations and lost revenues in future intervals, especially when 
a storage resource is at a low state of charge subsequent to the 
provision of energy or ancillary services.\345\
---------------------------------------------------------------------------

    \345\ Id. at 4.
---------------------------------------------------------------------------

    161. ESA claims that, for these reasons, the proposal is unduly 
discriminatory by potentially burdening storage, and recommends that 
the NOPR proposal be modified to: (1) Establish a minimum set point for 
primary frequency response service; and (2) include inadequate state of 
charge as an explicit operational constraint exempting storage from 
maintaining sustained output.\346\ Absent these requested changes, ESA 
requests a complete exemption for electric storage resources.\347\
---------------------------------------------------------------------------

    \346\ Id. at 4-5.
    \347\ Id. at 5.
---------------------------------------------------------------------------

    162. AES Companies request a complete exemption from the proposed 
NOPR requirements for electric storage resources including but not 
limited to battery storage devices providing one or more ancillary 
services.\348\ AES Companies assert that the proposed requirement of a 
maximum five percent droop setting, if imposed, would unnecessarily 
limit the benefits that electric storage resources specifically 
designed for primary frequency response can contribute to grid 
stability.\349\ AES Companies also state that a five percent droop 
setting ignores the majority of the primary frequency response capacity 
that an electric storage resource was designed to deliver by directing 
the resource to deliver only a fraction of its benefits.\350\ AES 
Companies further argue for an exemption from the requirement to 
dedicate a portion of the capacity of an electric storage resource for 
the provision of primary frequency response.\351\ AES Companies state 
that droop parameters should be specific to the technology, and that 
requiring, for instance, a lithium ion battery to provide primary 
frequency response at its full capacity would require a droop 
approaching 0 percent.\352\
---------------------------------------------------------------------------

    \348\ See AES Companies Comments at 17, 19 (i.e., specified 
changes to the pro forma language).
    \349\ Id. at 6. AES Companies contend that a five percent droop 
will limit the amount of capacity that an electric storage resource 
can dedicate to primary frequency response service.
    \350\ Id.
    \351\ Id. at 6. The Commission notes that in the NOPR, it did 
not propose any mandatory headroom requirements.
    \352\ AES Companies Comments at 7.
---------------------------------------------------------------------------

ii. Supplemental Comments
    163. Supplemental commenters are split on whether electric storage 
resources should be subject to the operating requirements proposed in 
the NOPR. Tri-State, ISO-RTO Council, Berkshire, NERC, and WIRAB 
support applying the proposed requirements to electric storage 
resources. SoCal Edison opposes the proposed operating requirements, 
but explains that if the Commission adopts the proposal, it should be 
applicable to all newly interconnecting generating facilities on a 
technology neutral basis so that such requirements will be implemented 
in a non-discriminatory fashion.\353\
---------------------------------------------------------------------------

    \353\ SoCal Edison Supplemental Comments at 2.
---------------------------------------------------------------------------

    164. However, Sunrun, AES Companies, and CESA comment that electric 
storage resources would bear a disproportionate impact compared to 
other resources due to the proposed droop and sustained response 
requirements, and therefore request an exemption or an accommodation 
from the proposed requirements. Several other commenters reiterate 
their initial NOPR comments that operating requirements for primary 
frequency response should not be included in the pro forma LGIA and pro 
forma SGIA, stating that a market-based approach to

[[Page 9660]]

primary frequency response, or regional flexibility in facilitating the 
provision of primary frequency response (e.g., allowing balancing 
authorities to determine which generating facilities should supply 
primary frequency response) would lead to more efficient and cost 
effective outcomes.\354\
---------------------------------------------------------------------------

    \354\ See, e.g., EEI Comments at 4-5.
---------------------------------------------------------------------------

    165. A number of commenters reference either technical or economic 
challenges that would be unique to electric storage resources under the 
proposed requirements. Sunrun, ESA, and CESA state that electric 
storage resources have a finite lifecycle, and that compliance with the 
proposed operating requirements for timely and sustained response may 
limit the lifetime of an electric storage resource.\355\ These 
commenters also assert that different electric storage technologies 
will have different depths of discharge and may face different 
challenges under the proposed operating requirements.
---------------------------------------------------------------------------

    \355\ Sunrun Supplemental Comments at 2; ESA Supplemental 
Comments at 4; CESA Supplemental Comments at 11.
---------------------------------------------------------------------------

    166. ESA argues that the proposed droop and sustained response 
requirements would impose adverse conditions on electric storage 
resources because they would bear a disproportionate impact on the 
provision of primary frequency response capability compared to other 
generating facilities. In particular, ESA asserts that because electric 
storage resources are energy-limited, it is inappropriate to require 
electric storage resources to provide sustained response because doing 
so would constrain electric storage resources from effectively managing 
their fuel supply (i.e., state of charge), potentially reducing their 
ability to fulfill service obligations and creating an effective 
headroom requirement.\356\
---------------------------------------------------------------------------

    \356\ ESA Supplemental Comments at 3.
---------------------------------------------------------------------------

    167. ESA restates its NOPR comment that droop is calculated as a 
percent of nameplate capacity above a minimum set point, and because 
electric storage resources lack such a set point, storage resources 
will be required to provide proportionally greater primary frequency 
response service.\357\ In addition, ESA states that if an electric 
storage resource is charging when called upon to provide primary 
frequency response, the switch to discharging means that the electric 
storage resource will provide both the injected energy and the removal 
of an effective ``load,'' creating a response significantly greater 
than contemplated in the proposed droop settings.\358\ However, EPRI 
states that this concern can be mitigated if the Commission makes 
certain clarifications in the final action. In particular, EPRI states 
that the NOPR requirement setting the droop curve at no more than five 
percent, based on nameplate capacity, can be assumed to refer to a 
slope equating to a five percent change in frequency causing a change 
in the full discharge capacity (not discharge capacity plus charge 
capacity) of the electric storage resource.\359\ Both AES Companies and 
ESA comment that the proposed deadband and timely response requirements 
do not pose challenges or adverse operational impacts for most electric 
storage resources.\360\
---------------------------------------------------------------------------

    \357\ Id. at 4.
    \358\ Id.
    \359\ EPRI Supplemental Comments at 6.
    \360\ AES Companies Supplemental Comments at 23; ESA 
Supplemental Comments at 6.
---------------------------------------------------------------------------

    168. Additionally, ESA claims that since electric storage resources 
are always ``online,'' as opposed to generating facilities that start-
up and shut-down (i.e., go offline), electric storage resources would 
be available to provide primary frequency response on a more frequent 
basis, and would therefore be expected to provide more primary 
frequency response service than generating facilities that go 
offline.\361\ On the other hand, APS states that while it acknowledges 
that electric storage resources could provide more primary frequency 
response than other resources, such provision will be limited by the 
obligations and operational characteristics and design of such 
resources, similar to all other resource types. In particular, if there 
is to be a minimum state of charge below which electric storage 
resources would not have to provide primary frequency response, these 
resources may not be providing primary frequency response of greater 
magnitude than other resources.\362\
---------------------------------------------------------------------------

    \361\ ESA Supplemental Comments at 7.
    \362\ APS Supplemental Comments at 6.
---------------------------------------------------------------------------

    169. Several commenters assert that there is little substantive 
difference between the operating constraints faced by electric storage 
resources and the operational characteristics that limit the capacity 
of other types of generating facilities to provide primary frequency 
response.\363\ For example, NERC asserts that ``run-of-river hydro 
units may have insufficient river flow, thermal units may have 
discharge temperature limitations on cooling water, gas turbines may 
need to be derated during the summer, pumped storage may not have yet 
refilled storage reservoirs, and units may be in the middle of coming 
on or going off-line.'' \364\ NERC states that while several types of 
generating facilities have technical limitations that may inhibit their 
ability to provide primary frequency response under certain 
circumstances, these operating constraints should not preclude any 
generating facility from maintaining primary frequency response 
capability.\365\ A number of supplemental commenters state that any 
determination regarding accommodations to mitigate such operational 
constraints, including, for example, the threshold limit below which an 
electric storage resource should be required to provide primary 
frequency response or allowed to disconnect from the grid during low 
frequency events, must be made on a case-by-case basis and can be done 
during the interconnection process.\366\ Further, APS comments that the 
operational wear and tear on electric storage resources and its impact 
on the overall life expectancy of an electric resource is not 
significantly different than the potential impact of wear and tear on 
other generating facilities.\367\
---------------------------------------------------------------------------

    \363\ See, e.g., APS Supplemental Comments at 4; NERC 
Supplemental Comments at 5, stating that operating constraints 
should not preclude any new generating facility from maintaining 
primary frequency response capability.
    \364\ NERC Supplemental Comments at 5.
    \365\ Id.
    \366\ See, e.g., APS Supplemental Comments at 5, 7; EPRI 
Supplemental Comments at 12-13; NRECA Supplemental Comments at 3; 
NERC Supplemental Comments at 5, stating that interconnection 
customers should evaluate any ``technical limitations on a unit-by-
unit basis and coordinate with their NERC Balancing Authority and 
Interconnection Agreement Transmission Provider/Transmission Owner, 
as appropriate.''
    \367\ APS Supplemental Comments at 7.
---------------------------------------------------------------------------

    170. ISO-RTO Council also believes that possible accommodations or 
exemptions for electric storage resources and small generators are 
unwarranted, stating that such measures could allow such resources to 
avoid solving the very problem to which such resources contribute and 
the NOPR rules were intended to address.\368\ ISO-RTO Council asserts 
that the proposed requirements are consistent with the recommendations 
and guidelines contained in NERC's Primary Frequency Control Guideline, 
and are similar to the current requirements of PJM, ISO-NE, and CAISO 
for electric storage resources and/or small generators to install, 
maintain and operate primary frequency response related equipment as a 
condition of interconnection ``that have not required exemptions for 
either electric storage resources or small generators.'' \369\ ISO-RTO 
Council

[[Page 9661]]

further notes that primary frequency response capability requirements 
that already exist in ``areas with substantial penetration of renewable 
resources'' in the European Union have not had ``negative impacts.'' 
\370\
---------------------------------------------------------------------------

    \368\ ISO-RTO Council Supplemental Comments at 2.
    \369\ Id. at 3.
    \370\ Id. at 4 (citing ENTSO-E requirements for Generators, 
Chapter 1, Article 13).
---------------------------------------------------------------------------

    171. EPRI states that the unique characteristics of electric 
storage resources should not directly affect the current requirements 
for droop settings.\371\ Specifically, EPRI comments that there is a 
limited amount of additional power required (2 percent of nameplate or 
less for a 0.1 Hz frequency deviation) and a limited amount of time it 
must be sustained (generally five minutes or less, maximum about seven 
minutes).\372\ EPRI concludes that the energy required to provide 
sustained frequency response is very small in relation to the energy 
that the electric storage resource would be providing otherwise.\373\
---------------------------------------------------------------------------

    \371\ EPRI Supplemental Comments at 4.
    \372\ Id.
    \373\ Id.
---------------------------------------------------------------------------

    172. While ESA supports an exemption for electric storage 
resources, it suggests several accommodations to the proposed 
requirements to mitigate the potentially adverse impact of the proposed 
requirements on electric storage resources. ESA asserts that electric 
storage resources should have a means to effectively ``go offline,'' 
similar to generating facilities on shut down, and that the language 
``whenever the Large Generating Facility is operated in parallel with 
the Transmission System'' in Section 9.6.2.1 should be interpreted to 
mean providing services to the grid and should exclude simply being 
idle.\374\ WIRAB adds that it would not be just and reasonable to 
require an electric storage resource to enable primary frequency 
response while in standby mode when other generating facilities are not 
subject to a similar requirement.\375\
---------------------------------------------------------------------------

    \374\ ESA Supplemental Comments at 8.
    \375\ WIRAB Supplemental Comments at 6.
---------------------------------------------------------------------------

    173. ESA also suggests that electric storage resources should be 
exempt from requirements for providing sustained primary frequency 
response when such a resource does not have enough energy stored to 
provide sustained frequency response at required capacity when a 
frequency deviation occurs (i.e., inadequate state of charge).\376\ ESA 
states that this exemption for ``inadequate state of charge'' should be 
included along with the allowances for ambient temperature limitations, 
outages of mechanical equipment, and regulatory requirements in the 
proposed tariff language of Section 9.6.4.2. WIRAB agrees that the 
concept of energy limitation should be included as an exemption to 
sustained response in proposed Section 9.6.4.2 of the pro forma LGIA 
and 1.8.4.2 of the pro forma SGIA, but clarifies that this exemption 
should not apply only to electric storage resources because other 
generating facilities also face energy limitations.\377\
---------------------------------------------------------------------------

    \376\ ESA Supplemental Comments at 10.
    \377\ WIRAB Supplemental Comments at 5.
---------------------------------------------------------------------------

    174. ESA states that, in lieu of other mechanisms to accommodate 
electric storage resources, operators of electric storage resources 
could specify an operating range outside of which electric storage 
resources would not be required to provide and/or sustain primary 
frequency response.\378\ Doing so, according to ESA, would prevent the 
excessive wear and tear impacts on electric storage resources, as well 
as potentially mitigate inadequate state of charge for sustained 
response.\379\ However, ESA states that even with this approach to 
mitigate adverse impacts of primary frequency response requirements, 
electric storage resources would continue to face constraints on state 
of charge management and a reduction in capability to provide other 
energy and ancillary services, primarily as a result of the 
unpredictable nature of abnormal frequency deviations.\380\ APS 
comments that establishing a minimum set point or an operating range 
are both workable solutions, and argues that the Commission should 
allow flexibility in determining the approach on a case-by-case 
basis.\381\ APS states that an operating range could be established 
through collaboration and evaluation during the interconnection process 
and included in the interconnection agreement.\382\ EPRI comments that 
a static operating range could lead to inefficiencies.\383\ AES 
Companies does not support the use of an operating range.\384\
---------------------------------------------------------------------------

    \378\ ESA Supplemental Comments at 12-13.
    \379\ Id. at 13.
    \380\ Id.
    \381\ APS Supplemental Comments at 9.
    \382\ Id. at 8-9.
    \383\ EPRI Supplemental Comments at 15.
    \384\ AES Companies Supplemental Comments at 38.
---------------------------------------------------------------------------

    175. SDG&E believes that markets for primary frequency response 
have the potential to eliminate nearly all the issues addressed by the 
questions in the Commission's Request for Supplemental Comments.\385\ 
Berkshire recommends that the Commission acknowledge in the final 
action that electric storage resources are not always utilized as 
generation or accounted for as generation assets, and that the 
Commission consider holding a technical conference to discuss 
alternative applications for electric storage resources apart from 
providing primary frequency response within a prescribed 
bandwidth.\386\
---------------------------------------------------------------------------

    \385\ SDG&E Supplemental Comments at 3-4
    \386\ Berkshire Supplemental Comments at 2-3.
---------------------------------------------------------------------------

c. Commission Determination
    176. In consideration of the unique physical and operational 
characteristics of electric storage resources, we will require 
transmission providers to include in their pro forma LGIA and pro forma 
SGIA specific accommodations for electric storage resources and place 
limitations on when electric storage resources will be required to 
provide primary frequency response consistent with the conditions set 
forth in Sections 9.6.4, 9.6.4.1, 9.6.4.2, 9.6.4.3, and 9.6.4.4 of the 
pro forma LGIA and Sections 1.8.4, 1.8.4.1, 1.8.4.2, 1.8.4.3, and 
1.8.4.4 of the pro forma SGIA, as applicable.
    177. Specifically, as discussed in further detail below, this 
includes the identification of an operating range within which electric 
storage resources will be required to provide primary frequency 
response, the identification of particular operating circumstances when 
electric storage resources will not be required to provide primary 
frequency response, and the inclusion of energy limitations in the list 
of exemptions from the requirement to provide primary frequency 
response.
    178. We disagree with SoCal Edison, ISO-RTO Council, and WIRAB that 
suggest electric storage resources should be subject to the same 
requirements for primary frequency response as all other 
resources.\387\ We find that the provision of primary frequency 
response in accordance with the requirements of this final action may 
present challenges for some electric storage resources. Specifically, 
we are persuaded by ESA's comments that requiring an electric storage 
resource to sustain its output without any consideration for whether 
the electric storage resource has sufficient state of charge could 
result in depths of discharge that could accelerate the degradation of 
an electric storage resource. However, while we agree that electric 
storage resources could experience disproportionate harm from the 
proposed requirements under some circumstances, we are also persuaded 
by EPRI's suggestion that those harms would be modest and can be 
mitigated with certain

[[Page 9662]]

accommodations.\388\ In particular, EPRI notes that ``the energy 
required to provide sustained primary frequency response is very small 
in relation to the energy that the electric storage resource would be 
providing otherwise due to provision of energy or other ancillary 
services such that the risk of running into state of charge limits 
would already be known and not likely impacted by provision of primary 
frequency response by itself.'' \389\
---------------------------------------------------------------------------

    \387\ ISO-RTO Supplemental Comments at 4-5; SoCal Edison 
Supplemental Comments at 2; WIRAB Supplemental Comments at 3.
    \388\ ``If an electric storage resource is not providing any 
online service, it should not be required to provide primary 
frequency response to align with the rules designated in the NOPR.'' 
EPRI Supplemental Comments at 8; ``Resources claiming artificial 
minimum set points during operational time frames that they would 
not provide primary frequency response during over-frequency events 
can be managed on a case-by-case basis, if sufficient primary 
frequency response capability is otherwise available.'' EPRI 
Supplemental Comments at 10; ``The [operating] range should be 
provided if there are any ``rough zones'' for any technologies where 
primary frequency response is not controllable, not possible, or 
would lead to extraordinary damage or wear-and-tear costs.'' EPRI 
Supplemental Comments at 15.
    \389\ EPRI Supplemental Comments at 4.
---------------------------------------------------------------------------

    179. We are persuaded by ESA's comment that allowing operators of 
electric storage resources to specify an operating range ``would 
prevent the excessive wear and tear impacts on electric storage as well 
as potentially mitigate inadequate state of charge for sustained 
response.'' \390\ Therefore, while acknowledging the limited degree of 
the amount of energy that will be required to provide sustained 
response,\391\ we find that, on balance, limiting the circumstances 
under which electric storage resources are required to provide primary 
frequency response will adequately alleviate the potential for 
excessive wear and tear that may have otherwise been experienced by 
electric storage resources.
---------------------------------------------------------------------------

    \390\ See ESA Supplemental Comments at 12-13.
    \391\ See EPRI Supplemental Comments at 4, stating that ``the 
energy required to provide sustained primary frequency response is 
very small in relation to the energy that the electric storage 
resource would be providing otherwise due to provision of energy or 
other ancillary services.''
---------------------------------------------------------------------------

    180. Specifically, we will require electric storage resources to 
identify in their interconnection request an operating range for the 
basis of the provision of primary frequency response. This operating 
range will represent the minimum and maximum states of charge between 
which an electric storage resource will be required to provide primary 
frequency response. The operating range for each electric storage 
resource will need to be agreed to by the interconnection customer and 
transmission provider, in consultation with the applicable balancing 
authority or any other relevant parties as appropriate, consider the 
system needs for primary frequency response, and the physical 
limitations of the electric storage resource as identified by the 
developer and any relevant manufacturer specifications, and be 
established in Appendix C of the pro forma LGIA (``Interconnection 
Details'') or Attachment 5 of the pro forma SGIA (``Additional 
Operating Requirements for the Transmission Provider's Transmission 
System and Affected Systems Needed to Support the Interconnection 
Customer's Needs''). We find that this operating range addresses 
concerns regarding excessive wear and tear on electric storage 
resources, mitigates the concerns about inadequate state of charge, and 
effectively allows electric storage resources to identify a minimum and 
maximum set point below and above which they will not be obligated to 
provide primary frequency response comparable to synchronous generation 
as suggested by ESA.\392\
---------------------------------------------------------------------------

    \392\ See ESA Supplemental Comments at 12-13.
---------------------------------------------------------------------------

    181. However, we do not agree with ESA that electric storage 
resources should not be required to specify the details of an 
inadequate state of charge parameter in their interconnection 
agreements.\393\ We find that requiring an electric storage resource to 
identify the states of charge at which it is unable to inject or 
receive additional energy to provide primary frequency response is 
necessary to mitigate the adverse impacts on electric storage resources 
while still requiring them to provide this essential reliability 
service when they are technically capable to do so. While we believe 
that the interconnection customer will have the best information 
regarding the physical capabilities of the electric storage resource 
and any limitations that should be placed on its operations due to 
manufacturer specifications, we also believe that the transmission 
provider will have the best information with respect to: (1) The 
expected magnitude of frequency deviations; (2) the expected duration 
that system frequency will remain outside of the deadband parameter; 
and (3) the expected incidence of frequency deviations outside of the 
deadband parameter. This information from the transmission provider is 
necessary for the interconnection customer to calculate the anticipated 
obligations to provide primary frequency response for an electric 
storage resource in terms of the energy requirements for individual 
incidents, as well as increased electricity throughput (i.e., cycling) 
over the life of the electric storage resource. We note that both the 
physical limitations of the electric storage resource, as identified by 
the interconnection customer, and the expected primary frequency 
response system requirements, as identified by the transmission 
provider, may be necessary to determine the appropriate operating range 
for an electric storage resource. Therefore, we find that it is 
necessary to provide the interconnection customer with the ability to 
propose an operating range with its initial interconnection request, 
but also allow the transmission provider and/or balancing authority to 
consider the system needs for primary frequency response prior to 
reaching an agreement on the final operating range among the parties in 
a LGIA or SGIA. We also find that the transmission providers must treat 
electric storage resources in a not unduly discriminatory or 
preferential manner when determining the appropriate operating range.
---------------------------------------------------------------------------

    \393\ See ESA Supplemental Comments at 11.
---------------------------------------------------------------------------

    182. Because the requirements for primary frequency response may 
change over time, the Commission is persuaded by commenters that it is 
appropriate to provide transmission providers with flexibility to 
determine whether the operating ranges established in the 
interconnection agreements for electric storage resources are static or 
dynamic values.\394\ We understand that system conditions and 
contingency planning can change, which may alter the anticipated 
incidence, magnitude, and duration of frequency deviations. 
Additionally, the capabilities of electric storage resources to provide 
primary frequency response may change due to degradation, repowering, 
or changes in service obligations, and these may also need to be 
considered when revisiting a dynamic operating range.\395\ If a 
transmission provider decides to implement a dynamic operating range 
for an electric storage resource to provide primary frequency response, 
it must also determine how frequently the operating range will be 
reevaluated and the factors that may be considered when reevaluating it 
either on a case-by-case basis in Appendix C of the pro forma LGIA and 
Attachment 5 of the pro forma SGIA, or as a standard approach filed in 
compliance with this final action. To the extent that the 
interconnection customer and the transmission provider

[[Page 9663]]

cannot agree on these issues, the interconnection customer has the 
right to request the filing of an unexecuted interconnection agreement 
to seek Commission resolution.
---------------------------------------------------------------------------

    \394\ See, e.g., APS Supplemental Comments at 8; EPRI 
Supplemental Comments at 15; ESA Supplemental Comments at 13.
    \395\ A dynamic operating range will allow the minimum and 
maximum state of charge values that define the operating range to 
change over time based on changing system needs and/or electric 
storage resource capabilities.
---------------------------------------------------------------------------

    183. Additionally, we agree with comments that suggest certain 
electric storage technologies are always online and capable of 
providing primary frequency response, and that without any 
accommodation, those resources could be required to provide sustained 
primary frequency response more frequently than other generating 
facilities that start up and shut down (i.e., go offline).\396\ 
Therefore, we find that it is appropriate to place limitations on when 
electric storage resources are required to provide primary frequency 
response. In particular, we agree with EPRI that ``[if] an electric 
storage resource is not providing any online service, it should not be 
required to provide primary frequency response.'' \397\ To require an 
electric storage resource to provide a service under conditions that 
other generating facilities are not required to provide it would raise 
discrimination concerns. Therefore, we revise the pro forma LGIA and 
pro forma SGIA to make clear that electric storage resources will only 
be required to provide primary frequency response when they are online 
and are dispatched to inject electricity to the grid and/or dispatched 
to receive electricity from the grid. We clarify that the requirement 
to provide primary frequency response will exclude situations when an 
electric storage resource is not dispatched to inject electricity to 
the grid and/or dispatched to receive electricity from the grid.
---------------------------------------------------------------------------

    \396\ See ESA Supplemental Comments at 7.
    \397\ See EPRI Supplemental Comments at 8. EPRI states that the 
determination of a generating facility being online is ``it being 
connected to the grid and providing online services (energy or 
online ancillary services).''
---------------------------------------------------------------------------

    184. We also agree with WIRAB that electric storage resources and 
some other resources could face physical limitations that would make 
them unable to provide primary frequency response, and believe that 
accommodations for such limitations are appropriate.\398\ While the 
previously discussed accommodations for electric storage resources are 
intended to limit adverse impacts of the primary frequency response 
requirements on them, we find that providing a specific exemption for 
physical energy limitations will not only further ensure that electric 
storage resources are not required to provide primary frequency 
response when they are physically unable to do so, but it will also 
prevent other resources that experience similar physical limitations 
from being required to provide the service when they are not able to. 
Conditions under which a resource is physically unable to provide 
primary frequency response could, for example, include an inability for 
an electric storage resource to increase its output because it does not 
have any stored energy (i.e., its state of charge is equal to zero), or 
an inability for a wind or solar generating facility to increase output 
because there is not sufficient wind or solar energy to allow an 
increase in MW output.
---------------------------------------------------------------------------

    \398\ See WIRAB Supplemental Comments at 4.
---------------------------------------------------------------------------

    185. Moreover, we find that including this exemption in the pro 
forma LGIA and pro forma SGIA is consistent with our finding that it is 
not necessary to establish a headroom requirement for primary frequency 
response. Because we are not requiring newly interconnecting generating 
facilities to maintain headroom to provide primary frequency response, 
we find that it is unjust and unreasonable to require the provision of 
primary frequency response from generating facilities that are 
physically unable to provide the service. Accordingly, we clarify that 
all generating facilities subject to this final action will be exempt 
from the timely and sustained frequency response requirements if they 
experience a physical energy limitation that would prevent them from 
fulfilling their obligations that would have otherwise been required 
under the parameters set forth in this final action. To implement this 
requirement, we modify the list of exemptions in Section 9.6.4.2 
(Timely and Sustained Response) of the pro forma LGIA and Section 
1.8.4.2 (Timely and Sustained Response) of the pro forma SGIA to 
include the term ``physical energy limitation.'' We define ``physical 
energy limitation'' to mean the circumstance when a resource would not 
have the physical ability, due to insufficient remaining charge for an 
electric storage resource or insufficient remaining fuel for a 
generating facility to satisfy its timely and sustained primary 
frequency response service obligation, as dictated by the magnitude of 
the frequency deviation and the droop parameter of the governor or 
equivalent controls. However, we also find that when a generating 
facility experiences a physical energy limitation, then the 
interconnection customer must be able to demonstrate to the 
transmission provider, and to the extent applicable, the relevant 
balancing authority, that such a physical energy limitation existed 
before or during an abnormal frequency deviation outside of the 
deadband parameter.
    186. We find that ESA's comments that suggest a minimum set point 
should be used in the determination of the droop response are 
misplaced. A generating facility's minimum set point is not used in the 
calculation of the MW droop response. We clarify that for all 
generating facilities, the calculation of the MW droop response is 
based on a generating facility's nameplate capacity (i.e., for a five 
percent droop curve, a generating facility would be expected to 
increase its output by 100 percent of its nameplate capacity for a five 
percent change in frequency). While it is true in theory that an 
electric storage resource may have a greater operating range over which 
to provide primary frequency response, from a practical standpoint the 
droop parameter limits the percentage of nameplate capacity that a 
generating facility will provide in response to abnormal frequency 
deviations.\399\
---------------------------------------------------------------------------

    \399\ For example, as pointed out by EPRI, ``[a] [five percent] 
droop setting and 36mHz deadband equates to an individual resource 
having a frequency response of about [two percent of] nameplate 
capacity per tenth of a Hz at a tenth of a Hz frequency deviation.'' 
EPRI Supplemental Comments at 7.
---------------------------------------------------------------------------

    187. ESA contends that ``[i]f a storage resource is charging when 
called to provide [primary frequency response], the switch to 
discharging means that the storage [resource] will provide both the 
injected energy and the removal of an effective `load,' creating a 
response significantly greater than contemplated in the proposed droop 
settings.'' \400\ To address ESA's concern, we will require electric 
storage resources that are being dispatched to charge at the time of an 
abnormal frequency deviation to increase (for over-frequency 
deviations) or decrease (for under-frequency deviations) the rate at 
which they are charging according to the droop parameter to satisfy the 
timely and sustained primary frequency response requirement. For 
example, if an electric storage resource is charging at two MW prior to 
an abnormal under-frequency deviation, and the calculated response per 
the droop parameter is to increase real-power output by one MW, the 
electric storage resource could satisfy its obligation by reducing its 
consumption by one MW (instead of completely reducing its consumption 
by the full two MW and then discharging at one MW, which would result 
in a net of three MW provided as primary frequency response). Further, 
if an electric storage resource is capable of switching from charging 
to discharging, or vice versa, within the time period that the primary 
frequency response is

[[Page 9664]]

needed the resource should do so if necessary to meet its calculated 
response. For example, if an electric storage resource is charging at 
one MW prior to an abnormal under-frequency deviation, and the 
calculated response per the droop parameter is to increase real-power 
output by three MW, the electric storage resource could satisfy its 
obligation by switching from charging at one MW to discharging at two 
MW. We clarify that electric storage resources would not be required to 
change from charging to discharging, or vice versa, if they are not 
technically capable of making the transition during the period in which 
the primary frequency response is needed.
---------------------------------------------------------------------------

    \400\ ESA Supplemental Comments at 3-4.
---------------------------------------------------------------------------

    188. Regarding AES Companies' contention that a five percent droop 
setting ignores the majority of the primary frequency response capacity 
that an electric storage resource was designed to deliver,\401\ we note 
that, as stated in the NOPR, the requirements adopted in this final 
action are minimum requirements; therefore, if a new generating or 
electric storage facility elects, in coordination with its transmission 
provider and/or balancing authority, 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.\402\
---------------------------------------------------------------------------

    \401\ AES Companies Comments at 6.
    \402\ NOPR, 157 FERC ] 61,122 at P 48.
---------------------------------------------------------------------------

    189. Finally, we are not persuaded by Berkshire that a technical 
conference is needed at this time because there is sufficient evidence 
in the record to make a finding on this issue, as discussed in this 
final action.
3. Distributed Energy Resources
a. NOPR Proposal
    190. In the NOPR, the Commission proposed to apply the primary 
frequency response capability and operating requirements to all newly 
interconnecting generating facilities interconnecting through an LGIA 
or SGIA.\403\
---------------------------------------------------------------------------

    \403\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 7, order 
on reh 'g, Order No. 2006-A, FERC Stats. & Regs. ] 31,196, order on 
clarification, Order No. 2006-B, FERC Stats. & Regs. ] 31,221.
---------------------------------------------------------------------------

b. Comments
    191. Several commenters assert that the final action should include 
special considerations for generating facilities connecting at the 
distribution level. Public Interest Organizations state that, in the 
NOI, SolarCity Corporation raised concerns that already-installed 
behind-the-meter generation and DERs could become subject to the pro 
forma SGIA should those DERs opt to participate in wholesale energy 
markets.\404\ Public Interest Organizations request that the Commission 
clarify the circumstances in which DER participation in wholesale 
energy markets would trigger requirements in the SGIA because 
``[u]nless warranted by a significant shortfall of primary frequency 
response service, requiring the retrofit of existing generators for 
primary frequency response capability under such circumstances would 
not be cost-effective.'' \405\ TVA states that exceptions to the 
primary frequency response requirements could reasonably be justified 
for generating facilities interconnected only through lower voltage 
distribution systems.\406\
---------------------------------------------------------------------------

    \404\ Public Interest Organizations Comments at 3.
    \405\ Id. at 3-4.
    \406\ TVA Comments at 4.
---------------------------------------------------------------------------

    192. Xcel argues that dynamic frequency response at the 
distribution level can interfere with anti-islanding \407\ protection 
methods, and that, unlike transmission-connected generation, generating 
facilities connected to the distribution system must meet the anti-
islanding requirements of the Institute of Electrical and Electronics 
Engineers (IEEE) Standards to protect the distribution system.\408\ 
Xcel explains that the IEEE anti-islanding standards may require that 
the primary frequency response of the facility be restricted or that 
suitable mitigation measures be installed.\409\ Accordingly, Xcel 
asserts that the pro forma SGIA should require that the distribution 
system operator be notified of the primary frequency response 
capabilities of a generating facility to be connected to the 
distribution system, and that the distribution system operator must 
have the ability to place limitations on the primary frequency response 
of the generating facility if such limitations are required to ensure 
system reliability and power quality.\410\
---------------------------------------------------------------------------

    \407\ Islanding refers to the condition in which a DER continues 
to power a location even though electrical grid power from the 
electric utility is no longer present. Unintentional islanding can 
pose a hazard to utility personnel and customer equipment, and it 
may prevent automatic re-connection of devices. The currently 
effective version of IEEE-1547 standard requires that for an 
unintentional island in which the DER energizes a portion of the 
distribution system, the DER shall detect the island and cease to 
energize the system within two seconds of the formation of an 
island.
    \408\ Xcel Comments at 9; IEEE Standard 1547-2003, 
Interconnecting Distributed Resources with Electric Power Systems 
and IEEE Standard 1547a-2014, Interconnecting Distributed Resources 
with Electric Power Systems Amendment 1.
    \409\ Xcel Comments at 9.
    \410\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    193. The requirements of this final action will apply to newly 
interconnecting DERs that execute, or request the unexecuted filing of, 
an LGIA or SGIA on or after the effective date of this final action. We 
find Public Interest Organizations' request that the Commission clarify 
the circumstances in which DER participation in wholesale energy 
markets would trigger requirements in the pro forma SGIA to be outside 
the scope of this proceeding.\411\
---------------------------------------------------------------------------

    \411\ CAISO, ISO-NE, MISO, NYISO, PJM, and SPP all have programs 
that allow demand response and/or certain demand-side resources to 
aggregate and participate in wholesale markets. The CAISO model 
requires a prospective DER aggregator to execute a Distributed 
Energy Resource Provider Agreement to accept and abide by the terms 
of the CAISO Tariff, but does not require the DER aggregator nor the 
aggregated DERs to execute an SGIA. See Cal. Indep. Sys. Operator 
Corp., 155 FERC ] 61,229, at P 1 (2016) (conditionally accepting 
tariff provisions to facilitate participation of aggregations of 
distribution-connected or distributed energy resources in CAISO's 
energy and ancillary service markets).
---------------------------------------------------------------------------

    194. Xcel is concerned that dynamic frequency response at the 
distribution level can interfere with anti-islanding protection 
methods. The sustained response provisions adopted herein would require 
a generating facility, only to the extent that it is allowed to remain 
online and ride through a disturbance and has operating capability in 
the direction needed to counteract the frequency deviation, to provide 
and sustain its response.
    195. The Commission in Order No. 828 provided flexibility to 
address anti-islanding concerns by finding that, if a transmission 
provider believes a particular facility has a higher risk of 
unintentional islanding due to specific conditions at that facility, 
the transmission provider may coordinate with the small generating 
facility to set ride through settings appropriate for those conditions, 
in accordance with Good Utility Practice and the appropriate technical 
standards.\412\ For those facilities with a lower risk of forming an 
unintentional island, the Commission found that they can be held to a 
longer ride through requirement.\413\
---------------------------------------------------------------------------

    \412\ See Order No. 828, 156 FERC ] 61,062 at P 28.
    \413\ Id.
---------------------------------------------------------------------------

    196. We clarify that the sustained response provisions in the 
revisions to the pro forma LGIA and pro forma SGIA apply only when a 
generating facility is allowed to ride through, and do not supersede a 
generating facility's ride through settings, or require an 
interconnection customer to override anti-islanding protection or any 
protective relaying that has been set to

[[Page 9665]]

disconnect the generating facility during certain abnormal system 
conditions. Further, we clarify that for those abnormal system 
conditions in which a generating facility is not tripped offline by 
anti-islanding or protective relays and remains connected, to the 
extent it has the necessary MW operating capability in the appropriate 
direction to correct the frequency deviation, it would be expected to 
provide and sustain primary frequency response.
    197. Accordingly, the obligations imposed for primary frequency 
response apply only to generating facilities allowed to ride through 
and, because the ride through settings will be coordinated between the 
interconnection customer and the transmission provider, we believe this 
should adequately address Xcel's anti-islanding concerns.
4. Nuclear Generating Facilities
a. NOPR Proposal
    198. In the NOPR, the Commission proposed to exempt generating 
facilities regulated by the NRC due to their unique operating 
characteristics and regulatory requirements.
b. Comments
    199. Several commenters support the exemption for nuclear 
generating facilities.\414\ EEI and the MISO TOs agree with the 
proposed exemption, explaining that nuclear units are restricted by 
their NRC operating licenses on the amount of primary frequency 
response, if any, they can provide for safety reasons.\415\ EEI also 
noted that in comments filed in response to the NOI, the Nuclear Energy 
Institute pointed out that nuclear plants are not well-suited to 
provide primary frequency response, and emphasized the role of the NRC 
as the safety regulator for commercial nuclear operations and its 
regulatory restrictions on NRC licenses.\416\ MISO TOs assert that 
nuclear generating facilities generally have turbine controls, which 
are designed to maintain steam pressure and do not respond to grid 
frequency deviations, and that because primary frequency response is 
automatic, unsupervised and unplanned maneuvering of a nuclear reactor 
can lead to safety issues.\417\
---------------------------------------------------------------------------

    \414\ See, e.g., AES Companies Comments at 7; MISO TOs Comments 
at 8, 13-14; EEI Comments at 14; NRECA Comments at 3; PG&E Comments 
at 2; SoCal Edison Comments at 4; TVA Comments at 3; Xcel Comments 
at 8.
    \415\ EEI Comments at 14; MISO TOs Comments at 13.
    \416\ EEI Comments at 14.
    \417\ MISO TOs Comments at 13-14.
---------------------------------------------------------------------------

    200. On the other hand, other commenters believe that the 
Commission should not automatically exempt new nuclear generating 
facilities. WIRAB asserts that the Commission should require new 
nuclear generating facilities to seek individual exemptions, as needed, 
based on legitimate safety requirements in their NRC operating 
license.\418\ WIRAB contends that in the future, new nuclear generating 
facilities in the U.S. may have the capability to safely and reliably 
respond to frequency deviations, and therefore the Commission should 
not provide an automatic exemption.\419\
---------------------------------------------------------------------------

    \418\ WIRAB Comments at 7-8.
    \419\ Id.
---------------------------------------------------------------------------

    201. Similarly, ISO-RTO Council believes that the Commission should 
not ``anticipate'' exemption requirements. Instead, ``any pro forma 
exemptions to the requirement to provide frequency response, including 
exemptions for new nuclear units, should be supported by applicable 
regulatory requirements, such as NRC rules and any regional 
requirements demonstrated by the nuclear owner to be applicable to the 
particular unit or type of unit.'' \420\
---------------------------------------------------------------------------

    \420\ ISO-RTO Council Comments at 7.
---------------------------------------------------------------------------

c. Commission Determination
    202. We adopt the NOPR proposal to exempt nuclear generating 
facilities from the final action requirements, due to the unique 
regulatory and technical requirements of nuclear generating facilities. 
As explained in the NOPR, nuclear generating facilities have separate 
licensing requirements under the NRC, which often restrict or severely 
limit nuclear generating facilities from providing primary frequency 
response.\421\ Further, nuclear generating facilities are designed to 
maintain internal steam pressure and are not intended to react to 
changes in the grid.\422\
---------------------------------------------------------------------------

    \421\ NOPR, 157 FERC ] 61,122 at P 31.
    \422\ Id.
---------------------------------------------------------------------------

    203. We disagree with WIRAB's and ISO-RTO Council's view that an 
entire class of generating facilities should not be exempted from the 
pro forma requirements. We find that the unique regulatory and 
technical requirements of nuclear facilities justify an exemption. 
Requiring nuclear generating facilities to request unit-specific 
exemptions from providing a service that their licensing requirements 
already limit or restrict could result in an unreasonable 
administrative burden that can be avoided by allowing a general 
exemption in the pro forma LGIA and pro forma SGIA, and we do so here.
5. Wind Generating Facilities
a. NOPR Proposal
    204. In the NOPR, the Commission did not propose to exempt new wind 
generating facilities from the new primary frequency response 
requirements. The Commission observed that while primary frequency 
response functionality has not been a standard feature on non-
synchronous generating facilities, recent technological advancements 
have equipped wind generating facilities with this capability. The 
Commission further noted that wind generating facilities typically 
operate at their maximum operating output, and generally lack excess 
capacity (or headroom) to provide primary frequency response during 
under-frequency conditions.\423\
---------------------------------------------------------------------------

    \423\ NOPR, 157 FERC ] 61,122 at P 13.
---------------------------------------------------------------------------

b. Comments
    205. AWEA states that the Commission's proposed addition of a 
primary frequency response requirement to the pro forma LGIA and pro 
forma SGIA can be met at low cost for new wind projects, and therefore 
new wind turbines should not have difficulty complying with the 
Commission's proposal.\424\ AWEA further states that it does not oppose 
the addition of the proposed primary frequency response capability 
requirement to interconnection standards for new non-synchronous 
generators, and that the proposed deadband and response rates for 
capability settings of maximum 5 percent droop and 0.036 Hz 
deadband appear reasonable and consistent with industry practice.\425\
---------------------------------------------------------------------------

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

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

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

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

[[Page 9666]]

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

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

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

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

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

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

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

    \431\ We further note that MISO's Net Zero Interconnection 
Service is an interconnection request that results in a GIA. As 
such, a generator connecting to the transmission system using Net 
Zero Interconnection Service would be expected to comply with this 
final action. See MISO Tariff Attachment X 3.3.1.1 (Additional 
Requirements for a Net Zero Interconnection Request application).
---------------------------------------------------------------------------

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

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

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

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

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

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

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

[[Page 9667]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 9668]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 9669]]

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

I. Regional Flexibility

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

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

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

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

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

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

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

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

J. Miscellaneous Comments

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

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

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

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

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

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

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

[[Page 9670]]

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

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

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

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

1. NOPR Proposal
    242. To implement the proposed primary frequency response 
requirements, the Commission proposed in the NOPR to revise Sections 
9.6 and 9.6.2.1 of the pro forma LGIA and add new Sections 9.6.4, 
9.6.4.1, and 9.6.4.2 to the pro forma LGIA.\487\ Similarly, the 
Commission proposed to revise Section 1.8 of the pro forma SGIA and add 
new Sections 1.8.4, 1.8.4.1, and 1.8.4.2 to the pro forma SGIA.\488\
---------------------------------------------------------------------------

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

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

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

3. Commission Determination
    244. We deny AES Companies' request to modify Section 9.6 of the 
pro forma LGIA as the request is related to reactive power and thus 
beyond the scope of this proceeding. We also deny AES Companies other 
proposed modifications to the pro forma LGIA and pro forma SGIA.
    245. Further, as explained in Sections II.B and II.C above, we 
conclude that EEI's requested modifications to the proposed revisions 
in the pro forma LGIA and pro forma SGIA that undermine uniformity are 
not consistent with the objectives explained herein and therefore are 
denied. However, we adopt EEI's requested language pertaining to timely 
and sustained response, particularly the phrase ``shall not block or 
inhibit governor or equivalent controls.''
    246. In light of the above discussion, we revise the pro forma LGIA 
to modify Sections 9.6 and 9.6.2.1 and adds new Sections 9.6.4, 
9.6.4.1, 9.6.4.2, 9.6.4.3, and 9.6.4.4. This section contains the 
totality of the revised revisions the pro forma LGIA. The revisions, 
with bracketed deletions from and italicized additions to the pro forma 
LGIA are as follows:

9.6 Reactive Power and Primary Frequency Response

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

[[Page 9671]]

Transmission System, Interconnection Customer shall operate the Large 
Generating Facility consistent with the provisions specified in 
Sections 9.6.4.1 and 9.6.4.2 of this Agreement. The primary frequency 
response requirements contained herein shall apply to both synchronous 
and non-synchronous Large Generating Facilities.
    9.6.4.1 Governor or Equivalent Controls. Whenever the Large 
Generating Facility is operated in parallel with the Transmission 
System, Interconnection Customer shall operate the Large Generating 
Facility with its governor or equivalent controls in service and 
responsive to frequency. Interconnection Customer shall: (1) In 
coordination with Transmission Provider and/or the relevant balancing 
authority, set the deadband parameter to: (1) A maximum of 0.036 Hz and set the droop parameter to a maximum of 5 
percent; or (2) implement the relevant droop and deadband settings from 
an approved NERC Reliability Standard that provides for equivalent or 
more stringent parameters. Interconnection Customer shall be required 
to provide the status and settings of the governor or equivalent 
controls to Transmission Provider and/or the relevant balancing 
authority upon request. If Interconnection Customer needs to operate 
the Large Generating Facility with its governor or equivalent controls 
not in service, Interconnection Customer shall immediately notify 
Transmission Provider and the relevant balancing authority, and provide 
both with the following information: (1) The operating status of the 
governor or equivalent controls (i.e., whether it is currently out of 
service or when it will be taken out of service); (2) the reasons for 
removing the governor or equivalent controls from service; and (3) a 
reasonable estimate of when the governor or equivalent controls will be 
returned to service. Interconnection Customer shall make Reasonable 
Efforts to return its governor or equivalent controls into service as 
soon as practicable. Interconnection Customer shall make Reasonable 
Efforts to keep outages of the Large Generating Facility's governor or 
equivalent controls to a minimum whenever the Large Generating Facility 
is operated in parallel with the Transmission System.
    9.6.4.2 Timely and Sustained Response. Interconnection Customer 
shall ensure that the Large Generating Facility's real power response 
to sustained frequency deviations outside of the deadband setting is 
automatically provided and shall begin immediately after frequency 
deviates outside of the deadband, and to the extent the Large 
Generating Facility has operating capability in the direction needed to 
correct the frequency deviation. Interconnection Customer shall not 
block or otherwise inhibit the ability of the governor or equivalent 
controls to respond and shall ensure that the response is not 
inhibited, except under certain operational constraints including, but 
not limited to, ambient temperature limitations, physical energy 
limitations, outages of mechanical equipment, or regulatory 
requirements. The Large Generating Facility shall sustain the real 
power response at least until system frequency returns to a value 
within the deadband setting of the governor or equivalent controls. A 
Commission-approved Reliability Standard with equivalent or more 
stringent requirements shall supersede the above requirements.
    9.6.4.3 Exemptions. Large Generating Facilities that are regulated 
by the United States Nuclear Regulatory Commission shall be exempt from 
Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this Agreement. Large 
Generating Facilities that are behind the meter generation that is 
sized-to-load (i.e., the thermal load and the generation are near-
balanced in real-time operation and the generation is primarily 
controlled to maintain the unique thermal, chemical, or mechanical 
output necessary for the operating requirements of its host facility) 
shall be required to install primary frequency response capability in 
accordance with the droop and deadband capability requirements 
specified in Section 9.6.4, but shall be otherwise exempt from the 
operating requirements in Sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.4 
of this Agreement.
    9.6.4.4 Electric Storage Resources. Interconnection Customer 
interconnecting an electric storage resource shall establish an 
operating range in Appendix C of its LGIA that specifies a minimum 
state of charge and a maximum state of charge between which the 
electric storage resource will be required to provide primary frequency 
response consistent with the conditions set forth in Sections 9.6.4, 
9.6.4.1, 9.6.4.2, and 9.6.4.3 of this Agreement. Appendix C shall 
specify whether the operating range is static or dynamic, and shall 
consider (1) the expected magnitude of frequency deviations in the 
interconnection; (2) the expected duration that system frequency will 
remain outside of the deadband parameter in the interconnection; (3) 
the expected incidence of frequency deviations outside of the deadband 
parameter in the interconnection; (4) the physical capabilities of the 
electric storage resource; (5) operational limitations of the electric 
storage resource due to manufacturer specifications; and (6) any other 
relevant factors agreed to by Transmission Provider and Interconnection 
Customer, and in consultation with the relevant transmission owner or 
balancing authority as appropriate. If the operating range is dynamic, 
then Appendix C must establish how frequently the operating range will 
be reevaluated and the factors that may be considered during its 
reevaluation.
    Interconnection Customer's electric storage resource is required to 
provide timely and sustained primary frequency response consistent with 
Section 9.6.4.2 of this Agreement when it is online and dispatched to 
inject electricity to the Transmission System and/or receive 
electricity from the Transmission System. This excludes circumstances 
when the electric storage resource is not dispatched to inject 
electricity to the Transmission System and/or dispatched to receive 
electricity from the Transmission System. If Interconnection Customer's 
electric storage resource is charging at the time of a frequency 
deviation outside of its deadband parameter, it is to increase (for 
over-frequency deviations) or decrease (for under-frequency deviations) 
the rate at which it is charging in accordance with its droop 
parameter. Interconnection Customer's electric storage resource is not 
required to change from charging to discharging, or vice versa, unless 
the response necessitated by the droop and deadband settings requires 
it to do so and it is technically capable of making such a transition.
    247. Similarly, the Commission modifies Section 1.8 of the pro 
forma SGIA and adds new Sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3, 
and 1.8.4.4. This section contains the totality of the revised 
revisions the pro forma SGIA. The revisions, with italicized additions 
to the pro forma SGIA are as follows:
    1.8 Reactive Power and Primary Frequency Response
    1.8.4 Primary Frequency Response. Interconnection Customer shall 
ensure the primary frequency response capability of its Small 
Generating Facility by installing, maintaining, and operating a 
functioning governor or equivalent controls. The term ``functioning 
governor or equivalent controls'' as used herein shall mean the 
required hardware and/or software that provides frequency responsive 
real power control with the ability to sense changes in system 
frequency and autonomously adjust the Small Generating Facility's real 
power output

[[Page 9672]]

in accordance with the droop and deadband parameters and in the 
direction needed to correct frequency deviations. Interconnection 
Customer is required to install a governor or equivalent controls with 
the capability of operating: (1) With a maximum 5 percent droop and 
0.036 Hz deadband; or (2) in accordance with the relevant 
droop, deadband, and timely and sustained response settings from an 
approved NERC Reliability Standard providing for equivalent or more 
stringent parameters. The droop characteristic shall be: (1) Based on 
the nameplate capacity of the Small Generating Facility, and shall be 
linear in the range of frequencies between 59 to 61 Hz that are outside 
of the deadband parameter; or (2) based an approved NERC Reliability 
Standard providing for an equivalent or more stringent parameter. The 
deadband parameter shall be: the range of frequencies above and below 
nominal (60 Hz) in which the governor or equivalent controls is not 
expected to adjust the Small Generating Facility's real power output in 
response to frequency deviations. The deadband shall be implemented: 
(1) Without a step to the droop curve, that is, once the frequency 
deviation exceeds the deadband parameter, the expected change in the 
Small Generating Facility's real power output in response to frequency 
deviations shall start from zero and then increase (for under-frequency 
deviations) or decrease (for over-frequency deviations) linearly in 
proportion to the magnitude of the frequency deviation; or (2) in 
accordance with an approved NERC Reliability Standard providing for an 
equivalent or more stringent parameter. Interconnection Customer shall 
notify Transmission Provider that the primary frequency response 
capability of the Small Generating Facility has been tested and 
confirmed during commissioning. Once Interconnection Customer has 
synchronized the Small Generating Facility with the Transmission 
System, Interconnection Customer shall operate the Small Generating 
Facility consistent with the provisions specified in Sections 1.8.4.1 
and 1.8.4.2 of this Agreement. The primary frequency response 
requirements contained herein shall apply to both synchronous and non-
synchronous Small Generating Facilities.
    1.8.4.1 Governor or Equivalent Controls. Whenever the Small 
Generating Facility is operated in parallel with the Transmission 
System, Interconnection Customer shall operate the Small Generating 
Facility with its governor or equivalent controls in service and 
responsive to frequency. Interconnection Customer shall: (1) In 
coordination with Transmission Provider and/or the relevant balancing 
authority, set the deadband parameter to: (1) A maximum of 0.036 Hz and set the droop parameter to a maximum of 5 
percent; or (2) implement the relevant droop and deadband settings from 
an approved NERC Reliability Standard that provides for equivalent or 
more stringent parameters. Interconnection Customer shall be required 
to provide the status and settings of the governor or equivalent 
controls to Transmission Provider and/or the relevant balancing 
authority upon request. If Interconnection Customer needs to operate 
the Small Generating Facility with its governor or equivalent controls 
not in service, Interconnection Customer shall immediately notify 
Transmission Provider and the relevant balancing authority, and provide 
both with the following information: (1) The operating status of the 
governor or equivalent controls (i.e., whether it is currently out of 
service or when it will be taken out of service); (2) the reasons for 
removing the governor or equivalent controls from service; and (3) a 
reasonable estimate of when the governor or equivalent controls will be 
returned to service. Interconnection Customer shall make Reasonable 
Efforts to return its governor or equivalent controls into service as 
soon as practicable. Interconnection Customer shall make Reasonable 
Efforts to keep outages of the Small Generating Facility's governor or 
equivalent controls to a minimum whenever the Small Generating Facility 
is operated in parallel with the Transmission System.
    1.8.4.2 Timely and Sustained Response. Interconnection Customer 
shall ensure that the Small Generating Facility's real power response 
to sustained frequency deviations outside of the deadband setting is 
automatically provided and shall begin immediately after frequency 
deviates outside of the deadband, and to the extent the Small 
Generating Facility has operating capability in the direction needed to 
correct the frequency deviation. Interconnection Customer shall not 
block or otherwise inhibit the ability of the governor or equivalent 
controls to respond and shall ensure that the response is not 
inhibited, except under certain operational constraints including, but 
not limited to, ambient temperature limitations, physical energy 
limitations, outages of mechanical equipment, or regulatory 
requirements. The Small Generating Facility shall sustain the real 
power response at least until system frequency returns to a value 
within the deadband setting of the governor or equivalent controls. A 
Commission-approved Reliability Standard with equivalent or more 
stringent requirements shall supersede the above requirements.
    1.8.4.3 Exemptions. Small Generating Facilities that are regulated 
by the United States Nuclear Regulatory Commission shall be exempt from 
Sections 1.8.4, 1.8.4.1, and 1.8.4.2 of this Agreement. Small 
Generating Facilities that are behind the meter generation that is 
sized-to-load (i.e., the thermal load and the generation are near-
balanced in real-time operation and the generation is primarily 
controlled to maintain the unique thermal, chemical, or mechanical 
output necessary for the operating requirements of its host facility) 
shall be required to install primary frequency response capability in 
accordance with the droop and deadband capability requirements 
specified in Section 1.8.4, but shall be otherwise exempt from the 
operating requirements in Sections 1.8.4, 1.8.4.1, 1.8.4.2, and 1.8.4.4 
of this Agreement.
    1.8.4.4 Electric Storage Resources. Interconnection Customer 
interconnecting an electric storage resource shall establish an 
operating range in Attachment 5 of its SGIA that specifies a minimum 
state of charge and a maximum state of charge between which the 
electric storage resource will be required to provide primary frequency 
response consistent with the conditions set forth in Sections 1.8.4, 
1.8.4.1, 1.8.4.2 and 1.8.4.3 of this Agreement. Attachment 5 shall 
specify whether the operating range is static or dynamic, and shall 
consider: (1) The expected magnitude of frequency deviations in the 
interconnection; (2) the expected duration that system frequency will 
remain outside of the deadband parameter in the interconnection; (3) 
the expected incidence of frequency deviations outside of the deadband 
parameter in the interconnection; (4) the physical capabilities of the 
electric storage resource; (5) operational limitations of the electric 
storage resource due to manufacturer specifications; and (6) any other 
relevant factors agreed to by Transmission Provider and Interconnection 
Customer, and in consultation with the relevant transmission owner or 
balancing authority as appropriate. If the operating range is dynamic, 
then Attachment 5 must establish how frequently the operating range 
will be

[[Page 9673]]

reevaluated and the factors that may be considered during its 
reevaluation.
    Interconnection Customer's electric storage resource is required to 
provide timely and sustained primary frequency response consistent with 
Section 1.8.4.2 of this Agreement when it is online and dispatched to 
inject electricity to the Transmission System and/or receive 
electricity from the Transmission System. This excludes circumstances 
when the electric storage resource is not dispatched to inject 
electricity to the Transmission System and/or dispatched to receive 
electricity from the Transmission System. If Interconnection Customer's 
electric storage resource is charging at the time of a frequency 
deviation outside of its deadband parameter, it is to increase (for 
over-frequency deviations) or decrease (for under-frequency deviations) 
the rate at which it is charging in accordance with its droop 
parameter. Interconnection Customer's electric storage resource is not 
required to change from charging to discharging, or vice versa, unless 
the response necessitated by the droop and deadband settings requires 
it to do so and it is technically capable of making such a transition.
    248. The Commission is also modifying the pro forma LGIP and pro 
forma SGIP to require newly interconnecting electric storage resources 
to include the details of the operating range in their interconnection 
request.
    249. In particular, the Commission is modifying the following 
sections of the pro forma LGIP as indicated below:

Appendix 1 to LGIP Interconnection Request for a Large Generating 
Facility

5. Interconnection Customer provides the following information:

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

Attachment A to Appendix 1 Interconnection Request

Unit Ratings

    Primary frequency response operating range for electric storage 
resources:

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

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

Attachment 2 Small Generator Interconnection Request (Application Form)

Small Generating Facility Information

    Primary frequency response operating range for electric storage 
resources:

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

III. Compliance and Implementation

    251. Section 35.28(f)(1) of the Commission's regulations requires 
every public utility with a non-discriminatory OATT on file to also 
have a pro forma LGIA and pro forma SGIA on file with the 
Commission.\490\
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    \490\ 18 CFR 35.28(f)(1) (2017).
---------------------------------------------------------------------------

    252. We reiterate that the requirements of this final action apply 
to all newly interconnecting large and small generating facilities that 
execute or request the unexecuted filing of a LGIA or SGIA on or after 
the effective date of this final action as well as all existing large 
and small generating facilities that take any action that requires the 
submission of a new interconnection request that results in the filing 
of an executed or unexecuted interconnection agreement on or after the 
effective date of this final action. We are not requiring changes to 
existing interconnection agreements that were executed, or filed 
unexecuted, prior to the effective date of this final action.
    253. We require each public utility transmission provider that has 
a pro forma LGIA and/or pro forma SGIA within its OATT to submit a 
compliance filing within 70 days following publication of this final 
action in the Federal Register.\491\ The compliance filing must 
demonstrate that it meets the requirements set forth in this final 
action.
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    \491\ For purposes of this final action, a public utility is a 
utility that owns, controls, or operates facilities used for 
transmitting electric energy in interstate commerce, as defined by 
the FPA. See 16 U.S.C. 824(e). A non-public utility that seeks 
voluntary compliance with the reciprocity condition of an OATT may 
satisfy that condition by filing an OATT, which includes a LGIA and 
SGIA.
---------------------------------------------------------------------------

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

    \492\ See Order No. 792, 145 FERC ] 61,159 at P 270.
    \493\ See 18 CFR 35.28(f)(1)(i).
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    255. We find that transmission providers that are not public 
utilities must adopt the requirements of this final action as a 
condition of maintaining the status of their safe harbor tariff or 
otherwise satisfying the reciprocity requirement of Order No. 888.\494\
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    \494\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,760-63 (1996), 
order on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order 
on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 
(2002).
---------------------------------------------------------------------------

IV. Information Collection Statement

    256. The following collection of information contained in this 
final action is subject to review by the Office of Management and 
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of 
1995, 44 U.S.C. 3507(d).\495\ The Paperwork Reduction Act (PRA) \496\ 
requires each federal agency to seek and obtain Office of Management 
and Budget (OMB) approval before undertaking a collection of 
information directed to ten or more persons, or contained in a rule of 
general applicability. OMB's regulations require the approval of 
certain information collection requirements imposed by agency 
rules.\497\ Upon approval of a collection of information, OMB will 
assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of this proposal will not be 
penalized for failing to respond to this collection of information 
unless the collection of information displays a valid OMB control 
number. Transmission providers and generating facilities are subject to 
the proposed revisions to the pro forma LGIA and pro forma SGIA.
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    \495\ 44 U.S.C. 3507(d) (2012).
    \496\ 44 U.S.C. 3501-3520 (2012).
    \497\ 5 CFR 1320.11 (2017).
---------------------------------------------------------------------------

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

[[Page 9674]]

take any action that requires the submission of a new interconnection 
request that results in the filing of an executed or unexecuted 
interconnection agreement on or after the effective date of this final 
action. Generating facilities subject to this final action will be 
required to install, maintain, and operate equipment capable of 
providing primary frequency response, consistent with certain operating 
requirements for droop, deadband, and timely and sustained response. 
The reforms adopted in this final action would require filings of pro 
forma LGIAs and pro forma SGIAs with the Commission. We anticipate the 
revisions required by this final action, once implemented, will not 
significantly change existing burdens on an ongoing basis. With regard 
to those public utility transmission providers that believe they 
already comply with the revisions adopted in this final action, they 
can demonstrate their compliance in the filing required 70 days after 
the effective date of this final action. The Commission will submit the 
proposed reporting requirements to OMB for its review and approval 
under section 3507(d) of the Paperwork Reduction Act.\499\ In the NOPR, 
the Commission used FERC-516B as a temporary ``placeholder'' 
information collection number.\500\ The Commission is now using FERC-
516 information collection because it is no longer pending at OMB in 
any actions.
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    \498\ 18 CFR 35.28(f)(1) (2017).
    \499\ 44 U.S.C. 3507(d).
    \500\ The reporting requirements in the NOPR were included under 
FERC-516B (OMB Control No. 1902-0286), because FERC-516 was pending 
review at OMB in an unrelated action. The reporting requirements in 
this final action are included under FERC-516 (OMB Control No. 1902-
0096).
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    258. While the Commission expects the revisions adopted in this 
final action will provide significant benefits, the Commission 
understands that implementation would entail some costs. The Commission 
solicited comments on the collection of information and the associated 
burden estimate in the NOPR. The Commission did not receive any 
comments concerning its burden or cost estimates.
    Burden Estimate \501\: Costs to Comply with Paperwork Requirements: 
The estimated annual costs are as follows: FERC-516: 74 entities * 1 
response/entity (10 hours/response * $74.50/hour) = $56,610.\502\
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    \501\ Burden means the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, 
disclose or provide information to or for a Federal agency, 
including: The time, effort, and financial resources necessary to 
comply with a collection of information that would be incurred by 
persons in the normal course of their activities (e.g., in compiling 
and maintaining business records) will be excluded from the 
``burden'' if the agency demonstrates that the reporting, 
recordkeeping, or disclosure activities needed to comply are usual 
and customary.
    \502\ The estimates for cost per response are derived using the 
following formula: 2017 Average Burden Hours per Response * $76.50 
per Hour = Average Cost per Response. The hourly cost figure of 
$76.50 is the average FERC employee wage plus benefits. We assume 
that respondents earn at a similar rate.

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

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

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

    Action: Revision of currently approved collection of information.
    OMB Control No.: 1902-0096.
    Respondents for this Rulemaking: Businesses or other for profit 
and/or not-for-profit institutions.
    Frequency of Information: One-time during year 1.
    259. Necessity of Information: The Commission is modifying the pro 
forma LGIA and pro forma SGIA to require all newly interconnecting 
large and small generating facilities, both synchronous and non-
synchronous, to install, maintain, and operate equipment capable of 
providing primary frequency response as a condition of interconnection. 
Specifically, the Commission is modifying the pro forma LGIA by 
revising Sections 9.6 and 9.6.2.1 and adding new Sections 9.6.4, 
9.6.4.1, 9.6.4.2 and 9.6.4.3, and is modifying the pro forma SGIA by 
revising section 1.8 and adding new Sections 1.8.4, 1.8.4.1, 1.8.4.2, 
and 1.8.4.3.
    260. Internal Review: The Commission has reviewed the changes and 
has determined that the changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has assured itself, by means of internal review, that there 
is specific, objective support for the burden estimates associated with 
the information collection requirements.
    261. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen 
Brown, Office of the Executive Director], email: 
[email protected], Phone: (202) 502-8663, fax: (202) 273-0873.
    262. Comments on the collection of information and the associated 
burden estimate in the final action should be sent to the Commission in 
this docket and may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW, Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission], at the following email address: 
[email protected]. Please reference OMB Control No. 1902-0096 
and the docket number of this rulemaking in your submission.

V. Regulatory Flexibility Act

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

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

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

[[Page 9675]]

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

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

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

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

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

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

VI. Environmental Analysis

    267. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\511\ As we 
stated in the NOPR, the Commission concludes that neither an 
Environmental Assessment nor an Environmental Impact Statement is 
required for the revisions adopted in this final action under Sec.  
380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale of electric energy subject to 
the Commission's jurisdiction, plus the classification, practices, 
contracts and regulations that affect rates, charges, classifications, 
and services.\512\ The revisions adopted in this final action would 
update and clarify the application of the Commission's standard 
interconnection requirements to large and small generating facilities.
---------------------------------------------------------------------------

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

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

VII. Document Availability

    269. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern Standard Time) at 888 First Street NE, 
Room 2A, Washington, DC 20426.
    270. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number of this document, excluding the last three digits, in 
the docket number field.
    271. User assistance is available for eLibrary and the Commission's 
website during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

VIII. Effective Date and Congressional Notification

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

[[Page 9676]]

execute or request the unexecuted filing of an LGIA or SGIA on or after 
the effective date of this final action as well as all existing large 
and small generating facilities that take any action that requires the 
submission of a new interconnection request that results in the filing 
of an executed or unexecuted interconnection agreement on or after the 
effective date of this final action. The Commission has determined, 
with the concurrence of the Administrator of the Office of Information 
and Regulatory Affairs of OMB, that this final action is not a ``major 
rule'' as defined in section 351 of the Small Business Regulatory 
Enforcement Fairness Act of 1996. This final action is being submitted 
to the Senate, House, Government Accountability Office, and Small 
Business Administration.

    By the Commission.

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

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

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

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

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

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


[[Page 9677]]

III. Appendix C: Uniform System of Accounts

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

Production Plant

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

Transmission Plant

    353 Station equipment.

Distribution Plant

    362 Station equipment.

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