162 FERC ¶ 61,128

UNITED STATES OF AMERICA

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

(Issued February 15, 2018)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

SUMMARY: The Federal Energy Regulatory Commission (Commission) is revising its 

regulations 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. To implement 

these requirements, the Commission is modifying the pro forma Large Generator 

Interconnection Agreement (LGIA) and the pro forma Small Generator Interconnection 

Agreement (SGIA). 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.

EFFECTIVE DATE: This Final Rule will become effective [Insert Date 70 days after 

publication in the FEDERAL REGISTER].
Docket No. RM16

-6-000 - 2 -

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

Jomo.Richardson@ferc.gov

Mark Bennett (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8524

Mark.Bennet@ferc.gov

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Essential Reliability Services and the Evolving BulkPower System—Primary Frequency ResponseDocket No. RM16-6-000

ORDER NO. 842

FINAL RULE

(Issued February 15, 2018)

TABLE OF CONTENTS

Paragraph Numbers

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 Equipment Capable of Providing 

Primary Frequency Response....................................................................................... 28.

1. NOPR Proposal................................................................................................... 28.

2. Comments........................................................................................................... 29.

3. Commission Determination................................................................................ 33.

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

LGIA and Pro Forma SGIA ........................................................................................ 40.

1. NOPR Proposal................................................................................................... 40.

2. Comments........................................................................................................... 43.

3. Commission Determination................................................................................ 56.

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

Deviations .................................................................................................................... 86.

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.
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E. Proposal not to Mandate Compensation............................................................... 111.

1. NOPR Proposal................................................................................................. 111.

2. Comments......................................................................................................... 112.

3. Commission Determination.............................................................................. 119.

F. Application to Existing Generating Facilities that Submit New Interconnection 

Requests That Result in an Executed or Unexecuted Interconnection Agreement ... 126.

1. NOPR Proposal................................................................................................. 126.

2. Comments......................................................................................................... 127.

3. Commission Determination.............................................................................. 131.

G. Application to Existing Generating Facilities that do not Submit New 

Interconnection Requests that Result in an Executed or Unexecuted Interconnection 

Agreement .................................................................................................................. 135.

1. NOPR Proposal................................................................................................. 135.

2. Comments......................................................................................................... 136.

3. Commission Determination.............................................................................. 142.

H. Requests for Exemption or Special Accommodation .......................................... 147.

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 Consider Potential Impact on Load 

and New Technology............................................................................................. 224.

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 Frequency Response .......................... 237.

3. Primary Frequency Response Obligations and Pools....................................... 239.

K. Specific Revisions to the Pro Forma LGIA and Pro Forma SGIA ................... 241.

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.
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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

IV. Appendix D: Modifications to NOPR Proposal
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 BulkPower System—Primary Frequency ResponseDocket No. RM16-6-000

ORDER NO. 842

FINAL RULE

(Issued February 15, 2018)

1. In this Final Rule, 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 

 1 16 U.S.C. 824e.
Docket No. RM16-6-000 - 2 -

pro forma LGIA and pro forma SGIA, including maximum droop and deadband 

parameters and provisions for timely and sustained response. 

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 Rule. 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 Rule. 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.

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 

 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.
Docket No. RM16-6-000 - 3 -

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 Interconnection3 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

 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, FERC Stats. & Regs. ¶ 32,682, at PP 4-10 

(2011).
Docket No. RM16-6-000 - 4 -

5. Mitigation of frequency deviations after the sudden loss of generation or load is 

driven by three primary factors: inertial response, primary frequency response, and 

secondary frequency response.5

 Primary frequency response actions begin within 

seconds after system frequency changes and are mostly provided by the automatic and 

autonomous actions (i.e., outside of system operator control) of turbine-governors, while 

some response is provided by frequency responsive loads.6

 Primary frequency response 

actions are intended to arrest abnormal frequency deviations and ensure that system 

frequency remains within acceptable bounds. An important goal for system planners 

and operators is for the frequency nadir,7 during large disturbances, to remain above the 

first stage of UFLS set points within an Interconnection.

 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 
Docket No. RM16-6-000 - 5 -

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 authorities8 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

 

decrease in power consumed by the load within an Interconnection matches the net initial 

loss of generation (in megawatts (MW)).

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).
Docket No. RM16-6-000 - 6 -

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 governor12 (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 

 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.
Docket No. RM16-6-000 - 7 -

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

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 

 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 Rule, 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.

17 NERC Frequency Response Initiative Report at 22. 
Docket No. RM16-6-000 - 8 -

Response Obligations,18 there has been a decline in the frequency response performance 

of the Western and Eastern Interconnections from historic values.19

B. Prior Commission Actions

9. In Order Nos. 200320 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 providers22 to file revised OATTs 

 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.

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.
Docket No. RM16-6-000 - 9 -

containing these standardized provisions, and use the LGIA and SGIA to provide nondiscriminatory 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

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 rules and 

regulations 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 

 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).

24 NOI, 154 FERC ¶ 61,117.
Docket No. RM16-6-000 - 10 -

energy resources (VERs),25 which typically do not contribute to system inertia26 or have 

primary frequency response capabilities, the net amount of frequency responsive 

generation online will be reduced.27

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 

 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.

28 Id. P 14.

29 Id. P 41.
Docket No. RM16-6-000 - 11 -

generating facilities30 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

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

 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.

32 Id. PP 2 and 44-45.

33 Id. PP 2, 46, and 52.

34 Id. PP 2, 53-54. 
Docket No. RM16-6-000 - 12 -

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 nonsynchronous, 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. 

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.

 35 Essential Reliability Services and the Evolving Bulk-Power System—Primary 

Frequency Response, Notice of Proposed Rulemaking, 157 FERC ¶ 61,122 (2016) 

(NOPR).
Docket No. RM16-6-000 - 13 -

15. Twenty-eight entities submitted comments in response to the NOPR and are listed 

in Appendix A to this Final Rule. 

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 resources36 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

 36 For the purposes of this Final Rule, 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 concerning electric storage resources in 

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.
Docket No. RM16-6-000 - 14 -

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

18. Twenty entities submitted comments in response to the notice of request for 

supplemental comments and are listed in Appendix B to this Final Rule. 

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

 40 Id. P 8.

41 Id. P 9.

42 Id. P 10.
Docket No. RM16-6-000 - 15 -

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 nonsynchronous 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 

 43 Section 215(a)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (2012) defines “BulkPower 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_Respons

e_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.
Docket No. RM16-6-000 - 16 -

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 

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 

 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.
Docket No. RM16-6-000 - 17 -

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

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 

 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_Respons

e_Webinar_QandA_April_2015.pdf.).
Docket No. RM16-6-000 - 18 -

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.

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

 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=00000000300200

6203. 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.

51 See NERC’s Primary Frequency Control Guideline.

52 NOPR, 157 FERC ¶ 61,122 at P 39.
Docket No. RM16-6-000 - 19 -

24. We also find that revisions to the pro forma LGIA and pro forma SGIA are 

necessary to provide for the continued reliable operation of the Bulk-Power System by 

addressing the potential adverse impacts on primary frequency response of the nation’s 

evolving generation resource mix described in the NOI.53 As noted in the NOPR, 

NERC’s Essential Reliability Services Task Force concluded that primary frequency 

response capability should be required of all new generating facilities.54 However, the 

pro forma LGIA and the pro forma SGIA do not currently require generating facilities to 

install such capability.

25. Further, the limited references to primary frequency response in the Commission’s 

regulations 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 

 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.
Docket No. RM16-6-000 - 20 -

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.

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 

 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. 
Docket No. RM16-6-000 - 21 -

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

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 

 57 NOPR, 157 FERC ¶ 61,122 at P 43.

58 Id. P 44.
Docket No. RM16-6-000 - 22 -

power output in accordance with the proposed maximum droop and deadband parameters 

and in the direction needed to correct frequency deviations.59

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 

 59 Id. P 47.

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.
Docket No. RM16-6-000 - 23 -

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 

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 

 63 Bonneville Comments at 2.

64 Id.

65 EEI Comments at 2.

66 NERC Comments at 5.

67 Id.
Docket No. RM16-6-000 - 24 -

interconnecting synchronous and non-synchronous generating facilities.68 Tri-State 

comments that primary frequency response requirements for all generating facilities are 

necessary to address the decline in frequency response and are in the best interest of 

industry.69 ISO-RTO Council adds that a number of Regional Transmission Operators 

(RTOs) and Independent System Operators (ISOs) have, for several years, had similar 

requirements to those proposed in the NOPR, and as a result, the Commission’s proposal 

does not create significant burdens as it merely extends these existing “best practices” 

nationwide.70 SVP states that the NOPR proposals should not create a major hardship in 

terms of costs or other burdens related to installing frequency response capability.71 

SoCal Edison states that there is neither a technological nor an economic reason not to 

require primary frequency response capability of small and/or non-synchronous 

generating facilities.72 

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 

 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.

73 See, e.g., API Comments at 2; APS Supplemental Comments at 12; Chelan 
Docket No. RM16-6-000 - 25 -

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 

 

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.
Docket No. RM16-6-000 - 26 -

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

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

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 

 78 Id. at 8-9.

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.
Docket No. RM16-6-000 - 27 -

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 

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 

 80 NOPR, 157 FERC ¶ 61,122 at P 47.

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. 
Docket No. RM16-6-000 - 28 -

mix has frequency responsive capacity available for dispatch by system operators to

maintain system reliability.

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. 
Docket No. RM16-6-000 - 29 -

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 Rule, 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 

 84 NOPR, 157 FERC ¶ 61,122 at P 48. 
Docket No. RM16-6-000 - 30 -

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 

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-room88 at the time of 

the disturbance) to provide a proportional response within this range of frequencies.89

 85 Id.

86 Id. P 50.

87 For the purposes of this Final Rule, 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 Rule, 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.
Docket No. RM16-6-000 - 31 -

42. The Commission also proposed that if the interconnection customer90 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 Efforts91 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

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 

 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. 
Docket No. RM16-6-000 - 32 -

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

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. 

 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.

97 NERC Comments at 5.
Docket No. RM16-6-000 - 33 -

(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

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

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 

 98 ISO-RTO Council Comments at 4-5.

99 WIRAB Comments at 3.

100 Id.

101 NRECA Comments at 2.
Docket No. RM16-6-000 - 34 -

governors or equivalent controls, and not establish specific operating requirements that 

must be used.102 While supporting revisions to the pro forma LGIA and pro forma SGIA 

to obligate newly interconnecting generators to install governors or equivalent controls to 

provide primary frequency response, EEI opposes including operating requirements. EEI 

asserts that tariffs, rather than interconnection agreements, are a more effective means of 

establishing operating requirements, since there are significant differences among 

generating facility types and interconnections as well as cost considerations, and because 

interconnection agreements “do not provide the necessary controls to ensure 

compliance.”103 EEI further states that operating requirements for new generating 

facilities are better determined by individual balancing authorities on an as-needed basis 

or through voluntary guidance from NERC.104 EEI also requests that, rather than 

mandating specific operating requirements, the Commission conduct a series of regional 

technical conferences to “allow for a more holistic evaluation of all [essential reliability 

services]”105 and provides details regarding the proposed focus and scope of such 

conferences.106 

 102 See, e.g., AES Companies Comments at 6; EEI Comments at 8; MISO TOs 

Comments at 10-11; SoCal Edison Comments at 2-3; Xcel Comments at 7. 

103 EEI Comments at 9, 11.

104 Id. at 11-12.

105 Id. at 12.

106 Id. at 4, n.5.
Docket No. RM16-6-000 - 35 -

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

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

 107 MISO TOs Comments at 9.

108 Id. at 11.

109 AES Companies Comments at 6.

110 Id.

111 NRECA Comments at 3.
Docket No. RM16-6-000 - 36 -

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 Rule should be flexible enough to allow for regional 

differences.114

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

 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.

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.
Docket No. RM16-6-000 - 37 -

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.
Docket No. RM16-6-000 - 38 -

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

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 

 120 EEI Comments at 14.

121 ISO-RTO Council Comments at 6.

122 Id.

123 WIRAB Comments at 7.
Docket No. RM16-6-000 - 39 -

result in a 5 percent droop across the entire range, but that non-linear droop parameters 

may lead to faster responses.124 More specifically, WIRAB explains that rather than a 

linear 5 percent droop across the entire operating range, “nonlinear or piecewise droop 

parameters,” such as a 5 percent droop between 60.036 and 61.000 Hz and a 3 percent 

droop between 59.964 and 59.000 Hz, “may help to restore system frequency to normal 

faster and improve system resiliency.”125 On the other hand, EEI recommends that the 

Commission not include in the pro forma interconnection agreements the proposed 

requirement for the droop characteristic to be linear in the operating between 59 to 

61 Hz.126 In support of its position, EEI contends that: (1) the proposed frequency range 

includes the deadband, where governors do not operate; and (2) actual generating facility 

response to frequency deviations may not be linear.127 

53. Regarding deadband parameters, NERC suggests that the Commission consider 

replacing the proposed requirements with the NERC Primary Frequency Control 

Guideline’s recommendation128 concerning the implementation of the deadband within 

the droop curve.129 Specifically, NERC recommends that deadbands should be 

 124 Id.

125 Id.

126 EEI Comments at 14-15, 17.

127 Id. at 14.

128 NERC Primary Frequency Control Guideline at 6.

129 NERC Comments at 6. 
Docket No. RM16-6-000 - 40 -

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

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

 130 Id.

131 Id.

132 Id. at 6-7.

133 Id.
Docket No. RM16-6-000 - 41 -

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

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 

 134 Bonneville Comments at 4. 

135 Id. at 4-5. 

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. 
Docket No. RM16-6-000 - 42 -

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.

 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.
Docket No. RM16-6-000 - 43 -

57. We believe it is necessary to make these changes to the pro forma LGIA and 

pro forma SGIA now in order to ensure that the future generation mix will be capable of 

providing primary frequency response, and to arrest the general long-term declining 

trend for this essential reliability service. Adopting these requirements now is more 

prudent than waiting until the lack of primary frequency response undermines grid 

reliability, a point acknowledged by NERC’s Essential Reliability Services Task Force. 

58. Accordingly, we find that it is just and reasonable to include the proposed 

operating requirements of a maximum droop setting of 5 percent and deadband setting of 

±0.036 Hz for primary frequency response in the pro forma LGIA and pro forma SGIA. 

We acknowledge that the needs of individual regions and balancing authority areas may 

warrant the adoption of different operating requirements in the future.

140 Therefore, the 

operating requirements for the pro forma LGIA and pro forma SGIA we adopt here are 

minimum interconnection requirements for new generating facilities based on the 

Primary Frequency Control Guideline developed by NERC through a broad-based 

stakeholder process.141 NERC’s Primary Frequency Control Guideline “reflect[s] the 

 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 
Docket No. RM16-6-000 - 44 -

most advanced set of continent-wide best practices and information available in support 

of frequency response capability.”142

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 

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 

 

maintaining the highest levels of BES reliability.” See NERC Primary Frequency 

Control Guideline at 1.

142 NERC Comments at 6.

143 NRECA Comments at 7.

144 NERC Comments at 5.

145 Essential Reliability Services Task Force Measures Report at vi.
Docket No. RM16-6-000 - 45 -

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

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 

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 

 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.

149 NERC Comments at 5.

150 Id. at 5-6.
Docket No. RM16-6-000 - 46 -

because the pro forma interconnection agreements lack “the necessary controls to ensure 

compliance.”151 While this Final Rule 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.

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 

 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).

154 EEI Comments at 12; MISO TOs Comments at 9; SoCal Edison Comments 

at 3.
Docket No. RM16-6-000 - 47 -

establishes, with an addition and clarification, methods for proposing variations to this 

Final Rule.155

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 Rule 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

 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 Rule; and (3) “independent entity variations” filed by 

RTOs/ISOs.

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”).
Docket No. RM16-6-000 - 48 -

or SGIA, or the interconnection customer may request that the transmission provider file 

an unexecuted LGIA or SGIA.

65. Regarding EEI’s request to conduct regional conferences, we do not believe that 

they are necessary at this time since: (1) the Commission has determined that minimum 

operating requirements are appropriate to include in the pro forma LGIA and pro forma

SGIA; and (2) EEI’s request to focus on other essential reliability services besides 

primary frequency response is beyond the scope of this proceeding.

66. Comments that reference compensation in lieu of including uniform operating 

requirements in the pro forma LGIA and pro forma SGIA are addressed below in 

Section II.E.

b. Whether to Include a Reference to a Future NERC 

Reliability Standard in the Pro Forma LGIA and 

Pro Forma SGIA

67. The Commission is persuaded by ISO-RTO Council’s request to include in the 

pro forma LGIA and pro forma SGIA provisions that address any future NERC 

Reliability Standard that provides for more stringent parameters. The Commission agrees

that the pro forma LGIA and pro forma SGIA (as applied to newly interconnecting 

generation facilities) should be written to allow for the adoption of a future Reliability 

Standard with stricter operating requirements (droop and deadband parameters) without a 

need to further amend interconnection agreements.

68. Accordingly, as discussed below, we are modifying the NOPR proposal to allow 

for the possibility of a future NERC Reliability Standard that includes equivalent or more 

stringent operating requirements for droop, deadband, and/or timely and sustained 
Docket No. RM16-6-000 - 49 -

response that would supersede the operating requirements for droop, deadband, and 

timely and sustained response adopted in this Final Rule. 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

69. We clarify that interconnection customers that are required to comply with this 

Final Rule 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 Rule 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 Rule.

 157 See 18 C.F.R. § 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.

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).
Docket No. RM16-6-000 - 50 -

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 

 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. 
Docket No. RM16-6-000 - 51 -

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.

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.

 162 ISO-RTO Council Comments at 6.
Docket No. RM16-6-000 - 52 -

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.

75. We clarify that this Final Rule will not require a generating facility that responds 

to frequency deviations to provide and sustain a value of primary frequency response that 

 163 EPRI Supplemental Comments at 5.
Docket No. RM16-6-000 - 53 -

causes its MW output to exceed its maximum steady state operating limit.164 For 

example, under-frequency conditions outside of the deadband parameter would result in 

an automatic increase in the generating facility’s MW output. However, if the calculated 

incremental MW value that would be provided as primary frequency response per the 

droop parameter would cause the generating facility to exceed its maximum steady state 

operating limit, the interconnection customer would be permitted to limit the increase in 

the generating facility’s MW output such that its MW output (after primary frequency 

response has been provided) does not exceed its maximum steady state operating limit, 

since doing so may cause facility-level reliability concerns. Should a generating 

facility’s maximum operating limit per its interconnection agreement be less than its 

nameplate capacity, nothing in this Final Rule 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.

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 

 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.
Docket No. RM16-6-000 - 54 -

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 “nonstepped.”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 

 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.
Docket No. RM16-6-000 - 55 -

for this issue, NERC recommends in its Primary Frequency Control Guideline168 and its 

comments to the NOPR169 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 

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 overfrequency 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 

 168 NERC Primary Frequency Control Guideline at 6.

169 NERC Comments at 6.

170 Id.
Docket No. RM16-6-000 - 56 -

facilities respond in a linear manner, we are modifying the NOPR proposal and adopt in 

this Final Rule 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 Rule. 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 
Docket No. RM16-6-000 - 57 -

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

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

82. Accordingly, we are modifying in this Final Rule the NOPR proposal to require 

the interconnection customer to provide its relevant balancing authority with the status 

and settings of the governor or equivalent controls upon request or when the 

 171 See NOPR, 157 FERC ¶ 61,122 at n.126.

172 See WIRAB Comments at 7.

173 NERC Comments at 6-7. 

174 Id. 
Docket No. RM16-6-000 - 58 -

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. 

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. 

 175 Bonneville Comments at 4. 

176 Id.
Docket No. RM16-6-000 - 59 -

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 plantlevel 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 

 177 NOPR, 157 FERC ¶ 61,122 at P 49.
Docket No. RM16-6-000 - 60 -

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 

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

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 

 178 Id.

179 Id. (citing NERC Primary Frequency Control Guideline at 4). 

180 Id.

181 Id. PP 52-53.

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. 
Docket No. RM16-6-000 - 61 -

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

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 

 183 NERC Comments at 5-6.

184 ISO-RTO Council Comments at 5.

185 EEI Comments at 9.

186 Id.
Docket No. RM16-6-000 - 62 -

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

90. EEI raises an additional concern, stating that “requirements to provide timely 

and sustained frequency response cannot be implemented in a manner that is fair and 

non-discriminatory” because interconnection agreements “do not provide the necessary 

controls to ensure compliance...[or] effectively or fairly ensure compensation to those 

entities providing this support.”189 EEI states that without a generic headroom 

requirement, a uniform requirement for timely primary frequency response “unfairly 

discriminates between those resources that are capable of providing timely response due 

to their design or current operating status over resources that are not capable of providing 

a timely response.”190 As an example, EEI states that renewables may not be able to 

provide a timely response to under-frequency deviations if they are operating at capacity 

or due to other technical limitations.191

 187 Id. at 12.

188 AES Companies Comments at 14.

189 EEI Comments at 11.

190 Id.

191 Id.
Docket No. RM16-6-000 - 63 -

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

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 

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

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.
Docket No. RM16-6-000 - 64 -

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

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 

 196 Id. at 6.

197 Id. at 5.

198 AWEA Comments at 8-9.

199 Id.

200 Id. at 9.
Docket No. RM16-6-000 - 65 -

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

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 

 201 Id.

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.” 
Docket No. RM16-6-000 - 66 -

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

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 

 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, 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.
Docket No. RM16-6-000 - 67 -

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 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 Rule, and does 

not render our operating requirements unduly discriminatory. If future conditions 

necessitate a headroom requirement, we will then consider any appropriate compensation.

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 

 207 EEI Comments at 11.

208 Id.
Docket No. RM16-6-000 - 68 -

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 Rule, 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. 

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 Rule the NOPR proposal to 

 209 Id. PP 8-9, 39.

210 EEI Comments at 16, 18-19; WIRAB Comments at 5-6. 
Docket No. RM16-6-000 - 69 -

require interconnection customers to not block or otherwise inhibit the governor or 

equivalent controls’ ability to respond.

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 Rule the 

 211 See WIRAB Comments at 5.
Docket No. RM16-6-000 - 70 -

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

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.

103. Regarding the minimum period of time that a response should be sustained, we 

will not establish in this Final Rule 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 

 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.”).

213 See AWEA Comments at 8-9 (describing efforts to coordinate the fast response 

times of wind facilities with system operators). 
Docket No. RM16-6-000 - 71 -

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 

 214 NOPR, 157 FERC ¶ 61,122 at P 51.
Docket No. RM16-6-000 - 72 -

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

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 

 215 Id.

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.
Docket No. RM16-6-000 - 73 -

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.

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 

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

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 

 221 Id. at 11.

222 AWEA Comments at 3.

223 ESA Comments at 2.

224 NOPR, 157 FERC ¶ 61,122 at P 44.
Docket No. RM16-6-000 - 74 -

headroom to provide primary frequency response. Instead, in response to AWEA and 

ESA, we clarify that this Final Rule 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 

 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)).
Docket No. RM16-6-000 - 75 -

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 

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

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 

 226 Id.

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.

230 Xcel Comments at 7; PG&E Comments at 2; EEI Comments at 11; MISO TOs 

Comments at 14.
Docket No. RM16-6-000 - 76 -

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 

114. AWEA states that the cost of attaining primary frequency response capability for 

new generators is low235 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 expenses are not 

 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. 

235 AWEA Comments at 1.

236 Id. at 9.
Docket No. RM16-6-000 - 77 -

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

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 

 237 California Cities Comments at 4.

238 Id.

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)).
Docket No. RM16-6-000 - 78 -

significant costs and should focus on market-based solutions such as that under Order 

No. 819.241 

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 

 241 Id. at 7. 

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.
Docket No. RM16-6-000 - 79 -

in the NOPR, some commenters prefer market-based compensation to incent the “right” 

level of primary frequency response.243

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 

 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.

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.
Docket No. RM16-6-000 - 80 -

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

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

 248 Id. 

249 First Solar Comments at 4.

250 Id.

251 ESA Comments at 4.

252 Id. at 6.

253 ESA Comments at 6-7 (citing Frequency Regulation Compensation in 
Docket No. RM16-6-000 - 81 -

3. Commission Determination

119. We will not mandate compensation for primary frequency response service in this 

Final Rule. 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 Rule; 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 

 

Organized Wholesale Power Markets, Order No. 755, FERC Stats. & Regs. ¶ 31,324, at 

P 2 (2011) (crossed referenced at 137 FERC ¶ 61,064).

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 & 
Docket No. RM16-6-000 - 82 -

agree 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.

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 

 

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).

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.”).
Docket No. RM16-6-000 - 83 -

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. 

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 nonRTO/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 

 258 See ISO-RTO Council Comments at 9-10. See also ELCON Comments at 6.

259 See SDG&E Comments at n.6.
Docket No. RM16-6-000 - 84 -

Nonetheless, an RTO/ISO may propose such an approach upon an adequate showing 

under section 205, if it so chooses. 

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.

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 

 260 See Competitive Suppliers Comments at 5.
Docket No. RM16-6-000 - 85 -

Final Rule. 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. 

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 

regulations (e.g., contracts for frequency response service under Order No. 819,263 and 

recent Commission action regarding transferred frequency response264) 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.

 261 Indianapolis Power, 158 FERC ¶ 61,107 at P 37.

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).
Docket No. RM16-6-000 - 86 -

126. Finally, nothing in this Final Rule is meant to prohibit a public utility from filing a 

proposal for primary frequency response compensation under section 205 of the FPA.265

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 Rule 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 Rule, but that takes any 

action that requires the submission of a new interconnection request on or after the 

effective date of any Final Rule.267 The Commission sought comment on the proposed 

effective date, including whether the proposed application of the requirements would be 

unduly burdensome.268

 265 See NOPR, 157 FERC ¶ 61,122 at P 55.

266 Id. P 54.

267 Id.

268 Id.
Docket No. RM16-6-000 - 87 -

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

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 

 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. 

273 ISO-RTO Council Comments at 8.
Docket No. RM16-6-000 - 88 -

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 rule.276 

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 

 274 Id. 

275 Id.

276 Id.

277 Xcel Comments at 6.
Docket No. RM16-6-000 - 89 -

interconnection agreement for more generation than is initially installed. In this situation, 

new generating facilities installed years after the effective date of the Final Rule 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 Rule be required to provide primary frequency response, even if no new 

interconnection agreement is required.279

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 

 278 Id.

279 Id. Xcel states that this approach should not apply to an uprate of an existing 

facility.

280 SVP Comments at 5-6.

281 Id. at 4-5.
Docket No. RM16-6-000 - 90 -

amended agreement after the effective date of the Final Rule 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

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 Rule.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 Rule. Accordingly, should an existing interconnection customer sign a new 

 282 Id. at 5.

283 Id.

284 NOPR, 157 FERC ¶ 61,122 at P 63.
Docket No. RM16-6-000 - 91 -

or amended interconnection agreement for reformatting purposes only those existing 

generating facilities would not be subject to the requirements of this Final Rule.285

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 Rule. 

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 subjecting the existing generating facility to the requirements adopted 

in this Final Rule.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 

 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.

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.
Docket No. RM16-6-000 - 92 -

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 Rule, 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. 

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 Rule 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

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 

 289 Xcel Comments at 6.

290 Id. at 4.
Docket No. RM16-6-000 - 93 -

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 Rule. The Commission clarifies that the Final Rule 

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.

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, 

 291 ISO-RTO Council Comments at 8.

292 See NOPR, 157 FERC ¶ 61,122 at PP 46, 54, 63.
Docket No. RM16-6-000 - 94 -

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

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 

 293 NOPR, 157 FERC ¶ 61,122 at PP 3, 57.

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.
Docket No. RM16-6-000 - 95 -

commenters argue that a blanket requirement is unnecessary given generally adequate 

levels of frequency response at this time.297

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

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

 297 NRECA Comments at 10; WIRAB Comments at 10-12; Competitive Suppliers 

Comments at 6.

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

299 Bonneville Comments at 3-4.

300 ISO-RTO Council Comments at 13.
Docket No. RM16-6-000 - 96 -

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 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 

 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.
Docket No. RM16-6-000 - 97 -

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 

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

 306 Id. at 11.

307 Id. at 4.

308 Id.

309 Id. at 4-5.
Docket No. RM16-6-000 - 98 -

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 Rule 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

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 

 310 ISO-RTO Council Comments at 11, n.23.

311 Id.

312 Id.
Docket No. RM16-6-000 - 99 -

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.

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. 

 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.

315 Order No. 794, 146 FERC ¶ 61,024 at P 3.
Docket No. RM16-6-000 - 100 -

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.

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 Rule, and recommend to the Commission any changes to 

 316 See WIRAB Comments at 10.

317 NERC already tracks frequency response performance at the Interconnectionwide level in its annual State of Reliability Report.
Docket No. RM16-6-000 - 101 -

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 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 

 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 Rule 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 C.F.R. §§ 292.203(b) and 292.205 (2017). 
Docket No. RM16-6-000 - 102 -

to act as stand-alone generation will compromise and potentially harm the manufacturing 

process by interfering with the steam balance.”319 

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 

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 

 319 ELCON Comments at 9.

320 Id. at 8. 

321 ELCON Supplemental Comments at 2-3.

322 Id.
Docket No. RM16-6-000 - 103 -

cannot reasonably provide [primary frequency response] service without compromising 

the efficiency, reliability and safe operation of the manufacturing process.”323

152. For example, ELCON states that an increasing number of manufacturers are 

installing turbines at their industrial facilities to obtain lower emissions and other 

benefits324 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 underfrequency conditions, the provision of primary frequency response results in increased 

 323 Id.

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.
Docket No. RM16-6-000 - 104 -

MW output, which ELCON explains may result in a level of steam production that 

exceeds the operating requirements of the manufacturing process.327 

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

 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.

328 Id. at 9.

329 Id. at 11. 

330 Id.
Docket No. RM16-6-000 - 105 -

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 Rule 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

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 Rule. 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 

 331 API Comments at 5.

332 Id.

333 Id. at 4.

334 ELCON noted “the low costs triggered by the NOPR’s limited applicability to 
Docket No. RM16-6-000 - 106 -

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-themeter generation that are sized-to-load (i.e., the thermal load and the generation are nearbalanced 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 “sizedto-load” only to industrial CHP facilities is too narrow. 

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

 

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.
Docket No. RM16-6-000 - 107 -

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 

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 

 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.

339 ESA Comments at 3.
Docket No. RM16-6-000 - 108 -

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 

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 

 340 Id. at 3-4. 

341 Id.

342 Id. at 4.

343 Id.
Docket No. RM16-6-000 - 109 -

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

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 

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

162. AES Companies request a complete exemption from the proposed NOPR 

requirements for electric storage resources including but not limited to battery storage 

 344 Id. at 3-4.

345 Id. at 4.

346 Id. at 4-5.

347 Id. at 5.
Docket No. RM16-6-000 - 110 -

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.
Docket No. RM16-6-000 - 111 -

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 

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 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 

 353 SoCal Edison Supplemental Comments at 2.

354 See, e.g., EEI Comments at 4-5.
Docket No. RM16-6-000 - 112 -

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. 

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 

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 

 355 Sunrun Supplemental Comments at 2; ESA Supplemental Comments at 4; 

CESA Supplemental Comments at 11. 

356 ESA Supplemental Comments at 3.
Docket No. RM16-6-000 - 113 -

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 Rule. 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

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 

 357 Id. at 4.

358 Id.

359 EPRI Supplemental Comments at 6.

360 AES Companies Supplemental Comments at 23; ESA Supplemental Comments 

at 6.
Docket No. RM16-6-000 - 114 -

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

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, 

 361 ESA Supplemental Comments at 7.

362 APS Supplemental Comments at 6.

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.
Docket No. RM16-6-000 - 115 -

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

 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.
Docket No. RM16-6-000 - 116 -

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 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

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 

 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).

371 EPRI Supplemental Comments at 4.
Docket No. RM16-6-000 - 117 -

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

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

 372 Id.

373 Id.

374 ESA Supplemental Comments at 8. 

375 WIRAB Supplemental Comments at 6.
Docket No. RM16-6-000 - 118 -

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

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 

 376 ESA Supplemental Comments at 10.

377 WIRAB Supplemental Comments at 5.

378 ESA Supplemental Comments at 12-13.
Docket No. RM16-6-000 - 119 -

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 

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 

 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.
Docket No. RM16-6-000 - 120 -

for Supplemental Comments.385 Berkshire recommends that the Commission 

acknowledge in the Final Rule 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

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 

 385 SDG&E Supplemental Comments at 3-4

386 Berkshire Supplemental Comments at 2-3.
Docket No. RM16-6-000 - 121 -

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 Rule 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 accommodations.388 In particular, EPRI notes that “the energy 

 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.” 
Docket No. RM16-6-000 - 122 -

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

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.

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 

 

EPRI Supplemental Comments at 15.

389 EPRI Supplemental Comments at 4.

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.”
Docket No. RM16-6-000 - 123 -

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

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 

 392 See ESA Supplemental Comments at 12-13. 

393 See ESA Supplemental Comments at 11.
Docket No. RM16-6-000 - 124 -

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 
Docket No. RM16-6-000 - 125 -

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.

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 

 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.
Docket No. RM16-6-000 - 126 -

the pro forma LGIA and Attachment 5 of the pro forma SGIA, or as a standard approach 

filed in compliance with this final rule. To the extent that the interconnection customer 

and the transmission provider cannot agree on these issues, the interconnection customer 

has the right to request the filing of an unexecuted interconnection agreement to seek 

Commission resolution.

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 

 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).”
Docket No. RM16-6-000 - 127 -

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.

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.
Docket No. RM16-6-000 - 128 -

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 Rule 

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 Rule. 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 
Docket No. RM16-6-000 - 129 -

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 

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 

 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.

400 ESA Supplemental Comments at 3-4.
Docket No. RM16-6-000 - 130 -

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 overfrequency 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 

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.

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 
Docket No. RM16-6-000 - 131 -

was designed to deliver,401 we note that, as stated in the NOPR, the requirements adopted 

in this Final Rule 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 

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 Rule.

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

b. Comments

191. Several commenters assert that the Final Rule 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 

 401 AES Companies Comments at 6.

402 NOPR, 157 FERC ¶ 61,122 at P 48.

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.
Docket No. RM16-6-000 - 132 -

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

192. Xcel argues that dynamic frequency response at the distribution level can interfere 

with anti-islanding407 protection methods, and that, unlike transmission-connected 

generation, generating facilities connected to the distribution system must meet the anti-

 404 Public Interest Organizations Comments at 3.

405 Id. at 3-4. 

406 TVA Comments at 4.

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. 
Docket No. RM16-6-000 - 133 -

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

c. Commission Determination

193. The requirements of this Final Rule 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 Rule. 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

 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.

411 CAISO, ISO-NE, MISO, NYISO, PJM, and SPP all have programs that allow 
Docket No. RM16-6-000 - 134 -

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

 

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). 

412 See Order No. 828, 156 FERC ¶ 61,062 at P 28.

413 Id.
Docket No. RM16-6-000 - 135 -

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 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. 
Docket No. RM16-6-000 - 136 -

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

200. On the other hand, other commenters believe that the Commission should not 

automatically exempt new nuclear generating facilities. WIRAB asserts that the 

 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.
Docket No. RM16-6-000 - 137 -

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

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

c. Commission Determination

202. We adopt the NOPR proposal to exempt nuclear generating facilities from the 

Final Rule 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 

 418 WIRAB Comments at 7-8.

419 Id.

420 ISO-RTO Council Comments at 7.
Docket No. RM16-6-000 - 138 -

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

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 

 421 NOPR, 157 FERC ¶ 61,122 at P 31.

422 Id.
Docket No. RM16-6-000 - 139 -

generally lack excess capacity (or headroom) to provide primary frequency response 

during under-frequency conditions.423

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

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 

 423 NOPR, 157 FERC ¶ 61,122 at P 13.

424 AWEA Comments at 4.

425 Id. at 4-5.
Docket No. RM16-6-000 - 140 -

instead proceed with further analysis first, as contemplated by NERC, or at least allow for 

flexibility in the requirements.426

c. Commission Determination

207. We are not persuaded by Sunflower and Mid-Kansas to exempt wind generating 

facilities from the primary frequency response requirements of this Final Rule. As 

discussed above, a key focus of this Final Rule 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 Rule.

 426 Sunflower and Mid-Kansas Comments at 4.

427 AWEA Comments at 4.
Docket No. RM16-6-000 - 141 -

6. Surplus Interconnection

a. NOPR Proposal

208. In the NOPR, the Commission did not propose any provisions related to surplus 

interconnection service.428

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

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 Rule is premature, because 

 428 See Reform of Generator Interconnection Procedures and Agreements, Notice 

of Proposed Rulemaking, 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.

429 ESA Comments at 5. 

430 Id.
Docket No. RM16-6-000 - 142 -

the Commission has yet to issue any Final Rule that addresses surplus interconnection 

service.431

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-

 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 Rule. See MISO Tariff Attachment X 3.3.1.1 (Additional 

Requirements for a Net Zero Interconnection Request application).

432 NOPR, 157 FERC ¶ 61,122 at P 41 (citing IEEE-P1547 Working Group NOI 

Comments at 1, 5, and 7).
Docket No. RM16-6-000 - 143 -

synchronous generating facilities to install enhanced inverters, which include primary 

frequency response capability requirements.433

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

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 

 433 Id. P 42.

434 APPA et al. Comments at 5.

435 EEI Comments at 8.

436 See NRECA Comments at 8; Public Interest Organizations Comments at 3; 

TVA Comments at 4; Idaho Power Comments at 2.
Docket No. RM16-6-000 - 144 -

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

214. Other commenters request the Commission adopt a size limitation for applying the 

NOPR requirements. For example, TVA requests an exemption for generating facilities 

under 5 MVA as long as they do not aggregate with facilities greater than 75 MVA or 

connect to the grid at 100 kV or above.440 Similarly, Idaho Power and NRECA request 

that the Commission consider exempting generating facilities that are smaller than 10 

 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.

440 TVA Comments at 4.
Docket No. RM16-6-000 - 145 -

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

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 

 441 Idaho Power Comments at 2.

442 NRECA Comments at 8.

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.
Docket No. RM16-6-000 - 146 -

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

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 

 446 Id. at 2. 

447 Id. at 2, 3.

448 EEI Supplemental Comments at 8.
Docket No. RM16-6-000 - 147 -

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 

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 

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-

 449 Id.

450 Id. at 4.

451 APS Supplemental Comments at 10-11.

452 AES Companies Supplemental Comments at 42.
Docket No. RM16-6-000 - 148 -

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 

220. Finally, Sunrun states that even inverters certified to UL 1741 SA455 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

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 

 453 NRECA Supplemental Comments at 2-3.

454 SDG&E Supplemental Comments at 3-4.

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 Rule to distributed energy resources in 

Section II.H.3.

456 Sunrun Supplemental Comments at 3-4.
Docket No. RM16-6-000 - 149 -

a size threshold is necessary so that small generators will not be forced to forego 

interconnection because the cost of including primary frequency response capability 

outweighs the benefit of interconnection.457 However, WIRAB states that costs for 

inverters capable of providing primary frequency response have declined. WIRAB 

submits that in 2013, the cost between a traditional inverter and an inverter capable of 

providing primary frequency response was less than 1 percent of the overall project. 

WIRAB adds that it is now standard practice to install such inverters for all utility scale, 

non-synchronous generating facilities because operational changes and updates can be 

made through software changes.458 Further, WIRAB states that if the Commission 

determines that small generating facilities may experience disproportionate cost impacts 

associated with the proposed requirement, the Commission should establish an exemption 

that would allow small generators to provide a demonstration of disproportionate costs to 

its utility to be exempt from the primary frequency response requirements.459 SoCal 

Edison agrees that given significant technological advances in generation facilities and 

equipment, including inverters, the proposed primary frequency response requirements 

for small generating facilities will not present a barrier to entry.460

 457 NRECA Supplemental Comments at 4.

458 WIRAB Supplemental Comments at 6-7.

459 Id. at 7.

460 SoCal Edison Supplemental Comments at 3.
Docket No. RM16-6-000 - 150 -

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 nonsynchronous 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

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 

 461 ISO-RTO Supplemental Comments at 6.

462 Id. at 7.

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).
Docket No. RM16-6-000 - 151 -

requirements of this Final Rule 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 Rule on small generators would be disproportionately costly or otherwise unduly 

burdensome.

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 

 464 APPA et al. Comments at 5.

465 EEI Comments at 8.

466 SoCal Edison Comments at 3.
Docket No. RM16-6-000 - 152 -

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

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

 467 ISO-RTO Council Supplemental Comments at 7.

468 NRECA Comments at 8.

469 Id.

470 Id. at 9.
Docket No. RM16-6-000 - 153 -

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

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 

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 

 471 AES Companies Comments at 12.

472 NRECA Comments at 6.

473 Id. at 8-9.
Docket No. RM16-6-000 - 154 -

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 Rule.474 We clarify that this 

Final Rule 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 

Rule.

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

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 Rule 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, 

 474 Id. at 7.
Docket No. RM16-6-000 - 155 -

more efficient generating facilities that may be developed in the future, nothing in this 

Final Rule 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 Rule, 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 Rule, or seek “independent entity variations” from the proposed 

revisions to the pro forma LGIA and pro forma SGIA.475

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 

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 

 475 NOPR, 157 FERC ¶ 61,122 at P 59. See Order No. 2003, FERC Stats. & Regs. 

¶ 31,146 at PP 822-827.

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.
Docket No. RM16-6-000 - 156 -

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 Rule. 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 Rule; and (3) “independent entity variations” filed by 

RTOs/ISOs.477

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 

 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.

478 See Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 546.
Docket No. RM16-6-000 - 157 -

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

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.

 479 Xcel Comments at 9-10.

480 Examples of these other accounts are described in Appendix C of this Final 

Rule.
Docket No. RM16-6-000 - 158 -

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 headroom 

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

b. Commission Determination

239. We decline in this Final Rule 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 

 481 Union of Concerned Scientists Comments at 3.

482 Id. at 8.

483 Id. at 7-8.
Docket No. RM16-6-000 - 159 -

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 

Rule is meant to discourage or prevent them from doing so. 

3. Primary Frequency Response Obligations and Pools

a. Comments

240. AES Companies state that NERC’s Essential Reliability Services Task Force 

recommended that all new generating facilities should support the capability to manage 

frequency control, not that they should provide primary frequency response 

themselves.484 As a result, AES Companies suggest that the Commission modify the 

NOPR proposal to allow the interconnection customer to demonstrate that they can 

provide its proportional share of primary frequency response, either through self-supply 

from other generating facilities within its fleet or via procurement from a third party.485 

AES Companies further suggest that utilities and other generation owners should then be 

allowed to form pools and/or aggregate their resources to meet an allocated proportionate 

share of their primary frequency response responsibility.486

 484 AES Companies Comments at 12.

485 Id.

486 Id.
Docket No. RM16-6-000 - 160 -

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

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 Rule, 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

 487 NOPR, 157 FERC ¶ 61,122 at P 52.

488 Id. P 53.

489 AES Companies Comments at 15.
Docket No. RM16-6-000 - 161 -

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.490 The 

revisions, with single underline redlined modifications from 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 

 490 Appendix D of this Final Rule has double underlined redlined modifications 

from the NOPR proposal.
Docket No. RM16-6-000 - 162 -

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.

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 overfrequency deviations) linearly in proportion to the magnitude of the 
Docket No. RM16-6-000 - 163 -

frequency deviation; or (2) in accordance with an approved NERC 

Reliability Standard providing for an equivalent or more stringent 

parameter. Interconnection Customer shall notify Transmission Provider 

that the primary frequency response capability of the Large Generating 

Facility has been tested and confirmed during commissioning. Once 

Interconnection Customer has synchronized the Large Generating Facility 

with the Transmission System, Interconnection Customer shall operate the 

Large Generating Facility consistent with the provisions specified in 

Sections 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 
Docket No. RM16-6-000 - 164 -

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 nearbalanced 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 
Docket No. RM16-6-000 - 165 -

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 underfrequency 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.491 The revisions, with single 

underline redlined modifications from the pro forma SGIA are as follows: 

1.8 Reactive Power and Primary Frequency Response 

 491 Appendix D of this Final Rule has double underlined redlined modifications 

from the NOPR proposal.
Docket No. RM16-6-000 - 166 -

1.8.4 Primary Frequency Response. Interconnection Customer shall 

ensure the primary frequency response capability of its Small Generating 

Facility by installing, maintaining, and operating a functioning governor or 

equivalent controls. The term “functioning governor or equivalent controls” 

as used herein shall mean the required hardware and/or software that 

provides frequency responsive real power control with the ability to sense 

changes in system frequency and autonomously adjust the Small 

Generating Facility’s real power output in accordance with the droop and 

deadband parameters and in the direction needed to correct frequency 

deviations. Interconnection Customer is required to install a governor or 

equivalent controls with the capability of operating: (1) with a maximum 5

percent droop and ±0.036 Hz deadband; or (2) in accordance with the 

relevant droop, deadband, and timely and sustained response settings from 

an approved NERC Reliability Standard providing for equivalent or more 

stringent parameters. The droop characteristic shall be: (1) based on the 

nameplate capacity of the Small Generating Facility, and shall be linear in 

the range of frequencies between 59 to 61 Hz that are outside of the 

deadband parameter; or (2) based an approved NERC Reliability Standard 

providing for an equivalent or more stringent parameter. The deadband 

parameter shall be: the range of frequencies above and below nominal (60 

Hz) in which the governor or equivalent controls is not expected to adjust 

the Small Generating Facility’s real power output in response to frequency 

deviations. The deadband shall be implemented: (1) without a step to the 

droop curve, that is, once the frequency deviation exceeds the deadband 

parameter, the expected change in the Small Generating Facility’s real 

power output in response to frequency deviations shall start from zero and 

then increase (for under-frequency deviations) or decrease (for overfrequency 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 
Docket No. RM16-6-000 - 167 -

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 
Docket No. RM16-6-000 - 168 -

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 nearbalanced 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 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 
Docket No. RM16-6-000 - 169 -

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 underfrequency 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.
Docket No. RM16-6-000 - 170 -

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

LGIP as indicated below:

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.492

252. We reiterate that the requirements of this Final Rule 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 Rule as 

 492 18 CFR 35.28(f)(1) (2017).
Docket No. RM16-6-000 - 171 -

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 Rule. 

We are not requiring changes to existing interconnection agreements that were executed, 

or filed unexecuted, prior to the effective date of this Final Rule.

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 Rule in the Federal Register.493 The compliance filing 

must demonstrate that it meets the requirements set forth in this Final Rule. 

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.494 Where these 

provisions would be modified by this Final Rule, public utility transmission providers 

must either comply with this Final Rule or demonstrate that these previously-approved 

 493 For purposes of this Final Rule, 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.

494 See Order No. 792, 145 FERC ¶ 61,159 at P 270.
Docket No. RM16-6-000 - 172 -

variations continue to be consistent with or superior to the pro forma LGIA and pro 

forma SGIA as modified by this Final Rule or continue to be permissible under the 

independent entity variation standard or regional Reliability Standard.495

255. We find that transmission providers that are not public utilities must adopt the 

requirements of this Final Rule as a condition of maintaining the status of their safe 

harbor tariff or otherwise satisfying the reciprocity requirement of Order No. 888.496

IV. Information Collection Statement

256. The following collection of information contained in this Final Rule 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).497 The Paperwork Reduction Act 

(PRA)498 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 

 495 See 18 CFR 35.28(f)(1)(i).

496 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).

497 44 U.S.C. 3507(d) (2012).

498 44 U.S.C. 3501-3520 (2012).
Docket No. RM16-6-000 - 173 -

the approval of certain information collection requirements imposed by agency rules.499 

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.

257. This Final Rule revises the Commission’s pro forma LGIA and pro forma SGIA 

in accordance with section 35.28(f)(1) of the Commission’s regulations,500 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 Rule 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 Rule. 

Generating facilities subject to this Final Rule 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 Rule would require filings of pro forma LGIAs and pro 

forma SGIAs with the Commission. We anticipate the revisions required by this Final 

 499 5 CFR 1320.11 (2017).

500 18 CFR 35.28(f)(1) (2017).
Docket No. RM16-6-000 - 174 -

Rule, 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 Rule, they can demonstrate their 

compliance in the filing required 70 days after the effective date of this Final Rule. The 

Commission will submit the proposed reporting requirements to OMB for its review and 

approval under section 3507(d) of the Paperwork Reduction Act.501 In the NOPR, the 

Commission used FERC-516Bas a temporary “placeholder” information collection 

number.502 The Commission is now using FERC-516 information collection because it is 

no longer pending at OMB in any actions.

258. While the Commission expects the revisions adopted in this Final Rule 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 Estimate503: Costs to Comply with Paperwork Requirements: The estimated 

 501 44 U.S.C. 3507(d).

502 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 Rule are included under FERC516 (OMB Control No. 1902-0096). 

503 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 
Docket No. RM16-6-000 - 175 -

annual costs are as follows: FERC-516: 74 entities * 1 response/entity (10 

hours/response * $74.50/hour) = $56,610.504

FERC 516 in Final Rule, RM16-6

No. of 

Respondents

505

(1)

Annual No. 

of 

Responses 

Per 

Respondent

(2)

Total No. 

of 

Responses 

(1)*(2)=(3)

Average 

Burden 

(Hrs.) & 

Cost ($) Per 

Response

(4)

Total 

Annual 

Burden Hrs. 

& Total 

Annual Cost 

($)

(3)*(4)=(5)

LGIA & 

SGIA 

changes / 

revisions

74 1 74 10 hours; 

$765.00

740 hours;

$56,610.00 

Total 74 740 hours; 

$56,610.00

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

Action: Revision of currently approved collection of information.

OMB Control No.: 1902-0096

 

(e.g., in compiling and maintaining business records) will be excluded from the “burden” 

if the agency demonstrates that he reporting, recordkeeping, or disclosure activities 

needed to comply are usual and customary. 

504 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. 

505 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. 
Docket No. RM16-6-000 - 176 -

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 revising its regulations 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. To implement these 

requirements, the pro forma LGIA and the pro forma SGIA must be revised. 

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], 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
Docket No. RM16-6-000 - 177 -

262. Comments on the collection of information and the associated burden estimate in 

the Final Rule 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 e-mail address: 

oira_submission@omb.eop.gov. 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)506 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.

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

January 22, 2014) for electric utilities from a standard based on megawatt hours to a 

standard based on the number of employees, including affiliates. Under SBA’s 

standards, some transmission owners will fall under the following category and 

associated size threshold: electric bulk power transmission and control, at 500 

employees.507

 506 5 U.S.C. 601-612 (2012).

507 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121 (Electric Bulk 
Docket No. RM16-6-000 - 178 -

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 74.508 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.”509 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 Rule would not have a significant 

economic impact on a substantial number of small entities.

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 

 

Power Transmission and Control) (2017).

508 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. 

509 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.
Docket No. RM16-6-000 - 179 -

interconnections would be small entities.510 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).511 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).512 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 

 510 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).

511 These costs are not relevant to the Paperwork Reduction Act.

512 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.
Docket No. RM16-6-000 - 180 -

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.

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.513 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 Rule under section 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 

 513 Regulations Implementing National Environmental Policy Act, Order No. 486, 

FERC Stats. & Regs. ¶ 30,783 (1987) (cross-referenced at 41 FERC ¶ 61,284).
Docket No. RM16-6-000 - 181 -

that affect rates, charges, classifications, and services.514 The revisions adopted in this 

Final Rule would update and clarify the application of the Commission’s standard 

interconnection requirements to large and small generating facilities. 

268. Therefore, this Final Rule 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 

 514 18 CFR 380.4(a)(15) (2017).
Docket No. RM16-6-000 - 182 -

free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

VIII. Effective Date and Congressional Notification

272. The Final Rule is effective [INSERT DATE 70 days from publication in 

FEDERAL REGISTER]. However, as noted above, the requirements of this Final Rule 

will apply only to all newly interconnecting large and small generating facilities that 

execute or request the unexecuted filing of an LGIA or SGIA on or after the effective 

date of this Final Rule 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 Rule. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB, that this 

Final Rule is not a “major rule” as defined in section 351 of the Small Business 

Regulatory Enforcement Fairness Act of 1996. This Final Rule is being submitted to the 

Senate, House, Government Accountability Office, and Small Business Administration.

By the Commission.

( S E A L )

Kimberly D. Bose,

Secretary.
Docket No. RM16-6-000 - 183 -

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 MidKansas

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.
Docket No. RM16-6-000 - 184 -

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
Docket No. RM16-6-000 - 185 -

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.
Docket No. RM16-6-000 - 186 -

IV. Appendix D: Modifications to NOPR Proposal

This Appendix contains the totality of the revisions to the proposed pro forma 

LGIA and pro forma SGIA text from the NOPR. The revisions, with double underline 

redlined modifications to the proposed pro forma LGIA text 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.

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 
Docket No. RM16-6-000 - 187 -

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 overfrequency deviations) linearly in proportion to the magnitude of the 

frequency deviation; or (2) in accordance with an approved NERC 

Reliability Standard providing for an equivalent or more stringent 

parameter. Interconnection Customer shall notify Transmission Provider 

that the primary frequency response capability of the Large Generating 

Facility has been tested and confirmed during commissioning. Once 

Interconnection Customer has synchronized the Large Generating Facility 

with the Transmission System, Interconnection Customer shall operate the 

Large Generating Facility consistent with the provisions specified in 

Sections 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. Nothing in Sections 

9.6.4, 9.6.4.1 and 9.6.4.2 shall require the Large 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.

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 
Docket No. RM16-6-000 - 188 -

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’s system 

operator, or its designated representative 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 without undue delay 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 and 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 stable value within the deadband 

setting of the governor or equivalent controls. A Commissionapproved 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 
Docket No. RM16-6-000 - 189 -

is sized-to-load (i.e., the thermal load and the generation are nearbalanced 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 
Docket No. RM16-6-000 - 190 -

increase (for over-frequency deviations) or decrease (for underfrequency 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.

The revisions, with double underline redlined modifications to the proposed 

pro forma SGIA text are as follows: 

1.8 Reactive Power and Primary Frequency Response 

1.8.4 Primary Frequency Response. Interconnection Customer shall 

ensure the primary frequency response capability of its Small Generating 

Facility by installing, maintaining, and operating a functioning governor or 

equivalent controls. The term “functioning governor or equivalent controls” 

as used herein shall mean the required hardware and/or software that 

provides frequency responsive real power control with the ability to sense 

changes in system frequency and autonomously adjust the Small 

Generating Facility’s real power output in accordance with the droop and 

deadband parameters and in the direction needed to correct frequency 

deviations. Interconnection Customer is required to install a governor or 

equivalent controls with the capability of operating: (1) with a maximum 5 

percent droop and ±0.036 Hz deadband;. or (2) in accordance with the 

relevant droop, deadband, and timely and sustained response settings from 

an approved NERC Reliability Standard providing for equivalent or more 

stringent parameters. The droop characteristic shall be: (1) based on the 

nameplate capacity of the Small Generating Facility, and shall be linear in 

the range of frequencies between 59 to 61 Hz that are outside of the 

deadband parameter; or (2) based an approved NERC Reliability Standard 

providing for an equivalent or more stringent parameter. The deadband 

parameter shall be: the range of frequencies above and below nominal (60 

Hz) in which the governor or equivalent controls is not expected to adjust 

the Small Generating Facility’s real power output in response to frequency 

deviations. The deadband shall be implemented: (1) without a step to the 

droop curve, that is, once the frequency deviation exceeds the deadband

parameter, the expected change in the Small Generating Facility’s real 

power output in response to frequency deviations shall start from zero and 

then increase (for under-frequency deviations) or decrease (for overfrequency deviations) linearly in proportion to the magnitude of the 

frequency deviation; or (2) in accordance with an approved NERC 
Docket No. RM16-6-000 - 191 -

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. Nothing in Sections 

1.8.4, 1.8.4.1 and 1.8.4.2 shall require the Small 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.

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’s system 

operator, or its designated representative 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 
Docket No. RM16-6-000 - 192 -

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 without undue delay 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 and 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 stable value within the deadband 

setting of the governor or equivalent controls. A Commissionapproved 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 nearbalanced 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. 
Docket No. RM16-6-000 - 193 -

Attachment 5 shall specify whether the operating range is static or 

dynamic, and shall consider: (1) the expected magnitude of 

frequency deviations in the interconnection; (2) the expected 

duration that system frequency will remain outside of the deadband 

parameter in the interconnection; (3) the expected incidence of 

frequency deviations outside of the deadband parameter in the 

interconnection; (4) the physical capabilities of the electric storage 

resource; (5) operational limitations of the electric storage resource 

due to manufacturer specifications; and (6) any other relevant factors 

agreed to by Transmission Provider and Interconnection Customer, 

and in consultation with the relevant transmission owner or 

balancing authority as appropriate. If the operating range is 

dynamic, then Attachment 5 must establish how frequently the 

operating range will be reevaluated and the factors that may be 

considered during its reevaluation. 

Interconnection Customer’s electric storage resource is required to 

provide timely and sustained primary frequency response consistent 

with Section 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 underfrequency 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.

The NOPR did not propose to revise the pro forma LGIP and pro forma SGIP. 

Revisions as a result of the Final Rule are listed below. To implement the 

accommodations for electric storage resources, the Commission is modifying the 

following sections of the pro forma LGIP as indicated below:
Docket No. RM16-6-000 - 194 -

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: 

Similarly, the Commission is modifying the following sections of the pro forma

SGIP as indicated below:

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: