157 FERC ¶ 61,122

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM16-6-000]

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

Response

(Issued November 17, 2016)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes to 

revise its regulations to require all newly interconnecting large and small generating 

facilities, both synchronous and non-synchronous, to install and enable primary 

frequency response capability as a condition of interconnection. To implement these 

requirements, the Commission proposes to revise the pro forma Large Generator 

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

Agreement (SGIA). The proposed changes are designed to address the increasing 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. The Commission also seeks comment on whether its proposals in this 

Notice of Proposed Rulemaking are sufficient at this time to ensure adequate levels of 

primary frequency response, or whether additional reforms are needed.
Docket No. RM16-6-000 - 2 -

DATES: Comments are due [INSERT DATE 60 days after publication in the 

FEDERAL REGISTER]

ADDRESSES: Comments, identified by docket number, may be filed in the following 

ways: 

• Electronic Filing through http://www.ferc.gov. Documents created electronically 

using word processing software should be filed in native applications or print-toPDF format and not in a scanned format.

• Mail/Hand Delivery: Those unable to file electronically may mail or hand-deliver 

comments to: Federal Energy Regulatory Commission, Secretary of the 

Commission, 888 First Street, NE, Washington, DC 20426.

Instructions: For detailed instructions on submitting comments and additional 

information on the rulemaking process, see the Comment Procedures Section of this 

document.

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.Bennett@ferc.gov
Docket No. RM16-6-000 - 3 -

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

NOTICE OF PROPOSED RULEMAKING

(Issued November 17, 2016)

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory 

Commission (Commission) proposes to modify 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 proposed modifications 

would require all new large and small generating facilities, including both synchronous 

and non-synchronous, interconnecting with a LGIA or SGIA to install, maintain and 

operate equipment capable of providing primary frequency response as a condition of 

interconnection. The Commission also proposes to establish certain operating 

requirements, including maximum droop and deadband parameters in the pro forma

LGIA and pro forma SGIA. The Commission does not propose to apply these

requirements to generating facilities regulated by the Nuclear Regulatory Commission.

 1 16 U.S.C. 824e (2012).
Docket No. RM16-6-000 - 2 -

In addition, the Commission does not propose in these reforms to impose a headroom 

requirement for new generating facilities. The Commission also does not propose to 

mandate that new generating facilities receive any compensation for complying with the 

proposed requirements in this NOPR.

2. The proposed revisions 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 have enabled new non-synchronous generating facilities to now have

primary frequency response capabilities. Further, the Commission believes that it may be 

unduly discriminatory or preferential to impose primary frequency response requirements 

only on new large generating facilities but not on new small generating facilities, and the 

reforms proposed here would impose comparable primary frequency response 

requirements on both new large and small generating facilities.

3. In addition, and as discussed below in paragraph 57, the Commission also seeks 

comment on whether its proposals in this NOPR are sufficient at this time to ensure 

adequate levels of primary frequency response, or whether additional reforms are needed.

4. The Commission seeks comment on the proposed reforms and requests for 

comment sixty (60) days after publication of this NOPR in the Federal Register. 
Docket No. RM16-6-000 - 3 -

I. Background

A. Frequency Response

5. Reliable operation of an Interconnection2 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.3

6. 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.

4 Primary frequency response actions begin within 

 2 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.

3 UFLS is designed for use 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) (Order No. 763 NOPR) 

at PP 4-10.

4 In the Notice of Inquiry issued in Docket No. RM16-6-000 on Feb. 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 

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

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.

5

 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,6 during large disturbances, to remain above the 

first stage of UFLS set points within an Interconnection.

7. 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 

 

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).

5 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, despite their differences. See Id. n.66.

6 The point at which the frequency decline is arrested (following the sudden loss of 

generation) is called the frequency nadir, and represents the point at which the net 

primary frequency response (real power) output from all generating units and the 

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

loss of generation (in megawatts (MW)).
Docket No. RM16-6-000 - 5 -

provided by generators within an Interconnection has a significant impact on the overall 

frequency response. NERC Reliability Standard BAL-003-1.1 defines the amount of 

frequency response needed from balancing authorities7 to maintain Interconnection 

frequency within predefined bounds and includes requirements for the measurement and 

provision of frequency response.8

 While NERC Reliability Standard BAL-003-1.1 

establishes requirements for balancing authorities, it does not include any requirements 

for individual generator owners or operators.

9

8. Unless otherwise required by tariffs or interconnection agreements, generator 

owners and operators can independently decide whether units are configured to provide 

primary frequency response.10 The magnitude and duration of a generator’s response to 

 7 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.”

8 Frequency Response and Frequency Bias Setting Reliability Standard, Order 

No. 794, 146 FERC ¶ 61,024 (2014). 

9 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).

10 See NOI, 154 FERC ¶ 61,117 at PP 18-19.
Docket No. RM16-6-000 - 6 -

frequency deviations is generally determined by the settings of the unit’s governor11 (or 

equivalent controls) and other plant level (e.g., “outer-loop”) control systems. 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 or “outer-loop” 

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 setpoint.12 In 2010, NERC conducted a survey of generator owners and operators and 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.13 This suggests that many generators 

 11 A governor is an electronic or mechanical device that implements primary 

frequency response on a generator 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 establishes a minimum 

frequency deviation (e.g., ±0.036 Hz) from nominal that must be exceeded in order for 

the governor to act. 

12 For more discussion on “premature withdrawal” of primary frequency response, 

see NOI, 154 FERC ¶ 61,117 at PP 49-50.

13 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.
Docket No. RM16-6-000 - 7 -

within the Interconnection disable or otherwise set their governors or outer-loop controls 

such that they provide little to no primary frequency response.14

9. Declining frequency response performance has been an industry concern for many 

years. NERC, in conjunction with EPRI, initiated its first examination of declining 

frequency response and governor response in 1991.15 More recently, as noted in the NOI,

while the three U.S. Interconnections currently exhibit adequate frequency response 

performance above their Interconnection Frequency Response Obligations,16 there has 

been a significant decline in the frequency response performance of the Western and 

Eastern Interconnections.17

 14 However, as noted below, some commenters note that nuclear generating units 

are restricted by their U.S. Nuclear Regulatory Commission operating licenses regarding 

the provision of primary frequency response.

15 NERC Frequency Response Initiative Report at 22. 

16 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.

17 NOI, 154 FERC ¶ 61,117 at P 20.
Docket No. RM16-6-000 - 8 -

B. Prior Commission Actions

10. In Order Nos. 200318 and 2006,

19 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 providers20 to file revised OATTs 

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 

 18 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).

19 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).

20 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 -

capacity of no more than 20 MW). The pro forma LGIA and pro forma SGIA have since 

been revised through various subsequent proceedings.21 

11. As relevant here, the pro forma LGIA and pro forma SGIA are largely silent on 

any requirements with respect to primary frequency response. In particular, the only 

requirement in the pro forma LGIA or pro forma SGIA related to primary frequency 

response is contained within current Article 9.6.2.1 of the pro forma LGIA (Governors 

and Regulators), which provides that if speed governors are installed, they should be 

operated in automatic mode.22 A speed governor implements the primary frequency 

response provided by a synchronous generating facility; however, Article 9.6.2.1 does not 

address governor settings or plant-level controls, which also affect the ability of a 

generating facility to provide primary frequency response. In addition, Article 9.6.2.1 

does not require the installation of the necessary equipment for frequency response 

capability (i.e., governors or equivalent controls). Finally, the pro forma SGIA does not 

contain any provisions related to primary frequency response.

 21 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, 

81 Fed. Reg. 40,793 (Jun. 23, 2016), 155 FERC ¶ 61,277 (2016); Requirements for 

Frequency and Voltage Ride Through Capability of Small Generating Facilities, Order 

No. 828, 81 Fed. Reg. 50,290 (Aug. 1, 2016), 156 FERC ¶ 61,062 (2016).

22 Article 9.6.2.1 of the pro forma LGIA.
Docket No. RM16-6-000 - 10 -

C. Efforts to Evaluate the Impacts of the Changing Resource Mix

12. The Commission’s pro forma generator interconnection agreements and 

procedures were developed at a time when traditional synchronous generating facilities 

with standard governor controls and large rotational inertia were the predominant sources 

of electricity generation. However, the nation’s resource mix has undergone significant 

change since the issuance of Order Nos. 2003 and 2006. This transformation has been 

characterized by the retirement of baseload, synchronous generating facilities and the 

integration of more distributed generation, demand response, and natural gas generating 

facilities, and the rapid expansion of non-synchronous variable energy resources (VERs) 

such as wind and solar.23 For example, the U.S. Energy Information Administration 

(EIA) has observed that the U.S. added approximately 13 gigawatts (GW) of wind, 

6.2 GW of utility scale solar photovoltaic (PV), and 3.6 GW of distributed solar PV 

generating facilities in 2014 and 2015.

24 Conversely, NERC has reported25 that almost 

42 GW of synchronous generating facilities (e.g., coal, nuclear, and natural gas) have 

 23 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 (2012).

24 See, U.S. electric generation capacity additions, 2015 vs. 2014, EIA (March 

2016), https://www.eia.gov/todayinenergy/detail.php?id=25492. 

25 See NERC 2015 LTRA (Dec. 2015), 

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015LTRA%20-

%20Final%20Report.pdf.
Docket No. RM16-6-000 - 11 -

retired between 2011 and 2014, and the EIA recently reported that nearly 14 GW of 

coal and 3 GW of natural gas generating facilities retired in 2015.26

13. While 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 nonsynchronous generating facilities. Moreover, wind and solar generating facilities

typically operate at their maximum operating output, leaving no capacity (or 

“headroom”) 27 to provide primary frequency response during under-frequency 

conditions.

14. Given the changes in the resource mix and concerns about the significant decline 

in frequency response for the Eastern and Western Interconnections,28 NERC has 

undertaken several initiatives to evaluate the impacts of the changing resource mix, 

particularly with respect to primary frequency response. For example, in 2014, NERC 

initiated the Essential Reliability Services Task Force (Task Force) to analyze and better 

 26 See Electricity generating capacity retired in 2015 by fuel and technology, EIA

(May 2016), http://www.eia.gov/todayinenergy/detail.php?id=25272.

27 Headroom refers to the difference between the current operating point of a 

generator and its maximum operating capability, and represents the potential amount of 

additional energy that can be provided by the generating facility in real-time.

28 See 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. (NERC 2015 Frequency Response Webinar). See also 

LBNL 2010 Report at pp xiv-xv.
Docket No. RM16-6-000 - 12 -

understand the impacts of the changing resource mix and develop technical assessments 

of essential reliability services.29 The Task Force focused on three essential reliability 

services: frequency support, ramping capability, and voltage support.30 The Task Force 

considered the seven ancillary services31 adopted by the Commission in Order Nos. 88832

 29 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.

30 Essential Reliability Services Task Force Measures Report, at 22 (Dec. 2015), 

http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20

Report%20-%20Final.pdf.

31 The seven pro forma ancillary services set forth in Order Nos. 888 and 890 are: 

(1) Scheduling, System Control and Dispatch Service; (2) Reactive Supply and Voltage 

Control from Generation Sources Service; (3) Regulation and Frequency Response 

Service; (4) Energy Imbalance Service; (5) Operating Reserve - Spinning Reserve 

Service; (6) Operating Reserve - Supplemental Reserve Service; and (7) Generator 

Imbalance Service.

32 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 

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

and 89033 as a subset of the essential reliability services that may need to be augmented 

by additional services as the Bulk-Power System34 characteristics change. 

15. The Task Force did not recommend new reliability standards or specific actions to 

alter the existing suite of ancillary services; however, it did make certain conclusions 

with regard to primary frequency response. Specifically, the Task Force concluded that it 

is prudent and necessary to ensure that primary frequency response capabilities are 

present in the future generation resource mix, and recommended that all new generators 

support the capability to manage frequency.35 

16. In addition, as part of its ongoing analysis of primary frequency response 

concerns, NERC observed in a 2012 report that a number of generators implemented 

deadband settings that were so wide as to effectively defeat the ability to provide primary 

 33 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC 

Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 

(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, 

Order No. 890-D, 129 FERC ¶ 61,126 (2009).

34 Section 215(a)(1) of the Federal Power Act (FPA), 16 U.S.C. § 824o(a)(1) 

(2012) defines “Bulk-Power System” as those “facilities and control systems necessary 

for operating an interconnected electric energy transmission network (or any portion 

thereof) [and] electric energy from generating facilities needed to maintain transmission 

system reliability.” The term does not include facilities used in the local distribution of 

electric energy. See also Mandatory Reliability Standards for the Bulk-Power System, 

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 76, order on reh’g, Order No. 693-A, 

120 FERC ¶ 61,053 (2007).

35 Essential Reliability Services Task Force Measures Report at vi.
Docket No. RM16-6-000 - 14 -

frequency response.36 The report also notes that many generators provide frequency 

response in the wrong direction during a disturbance.37 Additionally, in February 2015, 

NERC issued an Industry Advisory that determined that a significant portion of 

generators within the Eastern Interconnection use deadbands or governor control settings 

that either inhibit or prevent the provision of primary frequency response.38 Moreover, as 

noted in the NOI, NERC observed in 2015 that in many conventional steam plants, 

deadband settings exceed ±0.036 Hz, resulting in primary frequency response that is not 

sustained, and that the vast majority of the gas turbine fleet is not frequency responsive.39 

In response to these issues and other concerns, NERC’s Operating Committee approved a 

voluntary Primary Frequency Control Guideline that contains recommended settings for 

generator governors and other plant control systems, and encourages generators within 

the three U.S. Interconnections to provide sustained and effective primary frequency 

 36 NERC Frequency Response Initiative Report at 92.

37 NERC Frequency Response Initiative Report at 96-97.

38 NERC Generator Governor Frequency Response Industry Advisory (Feb. 2015), 

http://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A2015-02-05-01%20Generator%20Governor%20Frequency%20Response.pdf.

39 NOI, 154 FERC ¶ 61,117 at P 50 (citing to NERC 2015 Frequency Response 

Webinar at 1). 
Docket No. RM16-6-000 - 15 -

response.40 NERC’s Guideline recommends maximum 5 percent droop and ±0.036 Hz 

deadband settings for most generating facilities.

41

D. Initiatives by Individual Transmission Providers

17. While the pro forma LGIA and pro forma SGIA do not provide specific 

requirements related to frequency response, some public utility transmission providers 

have included provisions related to primary frequency response in their LGIA, SGIA, 

OATTs, and/or business practice manuals. 

18. For example, ISO New England Inc. (ISO-NE) and New York Independent 

System Operator, Inc. (NYISO) have adopted provisions to their LGIAs that establish 

more specific requirements for governor operation.

42 In particular, ISO-NE requires each 

generator within its region with a capability of 10 MW or more, including VERs, to 

operate with a functioning governor with specified droop and deadband settings, 

i.e., maximum 5 percent droop and ±0.036 Hz deadband, and to also ensure that the 

 40 See NERC Primary Frequency Control Guideline Final Draft (Dec. 2015), 

http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_C

ontrol_final.pdf (NERC Primary Frequency Control Guideline). See also NERC 

Operating Committee Meeting Minutes (Jan. 2016), 

http://www.nerc.com/comm/OC/AgendasHighlightsMinutes/Operating%20Committee%

20Minutes%20-%20Dec%2015-16%202015-Final.pdf.

41 See NERC Primary Frequency Control Guideline at 7-9.

42 See ISO-NE, Transmission, Markets and Services Tariff, Schedule 22 Large 

Generator Interconnection Procedures (9.0.0), Appendix 6, § 9.6.2.2; NYISO, NYISO 

Tariffs, NYISO OATT, 30.14 OATT Att. X Appendices (8.0.0), Appendix 6, § 9.5.4.
Docket No. RM16-6-000 - 16 -

provision of primary frequency response is not inhibited by the effects of outer-loop 

controls.43

19. PJM Interconnection, L.L.C. (PJM) has implemented governor droop and 

deadband requirements, i.e., maximum 5 percent droop and ±0.036 Hz deadband, for all 

generating facilities excluding nuclear facilities with a gross plant/facility aggregate 

nameplate rating greater than 75 MVA.44 PJM also recently added new interconnection 

requirements requiring new non-synchronous generators to interconnect with “enhanced 

inverters” that have various capabilities including, among other things, the ability to 

provide primary frequency response.45

20. Midcontinent Independent System Operator, Inc. (MISO) requires governor 

operation as a condition for providing regulating reserve but does not require specific 

settings.46 Also, the Commission recently accepted tariff provisions proposed by the 

 43 See ISO-NE’s Operating Procedure No. 14 § I (Governor Control), 

http://www.iso-ne.com/rules_proceds/operating/isone/op14/op14_rto_final.pdf.

44 PJM’s pro forma interconnection agreements obligate interconnection 

customers within its region to abide by all PJM rules and procedures, including rules set 

forth in PJM’s Manuals (See PJM Tariff, Attachment O § 8.0). See also PJM Manual 

14D § 7.1.1 (Generator Real-Power Control), 

http://www.pjm.com/~/media/documents/manuals/m14d.ashx.

45 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097, at n.58 (2015).

46 See MISO, FERC Electric Tariff, Module C, Energy and Operating Reserve 

Markets § 39.2.1B (34.0.0) (“All Regulation Qualified Resources in the Day-Ahead 

Energy and Operating Reserve Market must be capable of automatically responding to 

and alleviating frequency deviations through a speed governor or similar device in 

accordance with the Applicable Reliability Standards.”).
Docket No. RM16-6-000 - 17 -

California Independent System Operator Corporation (CAISO) to require governor 

operation, specified droop and deadband settings, i.e., maximum 5 percent droop and 

±0.036 Hz deadband, and provisions for sustained primary frequency response for its 

participating generators that have traditional governor controls.47

E. Notice of Inquiry

1. Summary

21. On February 18, 2016, the Commission issued the NOI to explore issues regarding 

essential reliability services and the evolving Bulk-Power System.48 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 VERs 

that do not typically contribute to system inertia or have primary frequency response 

capabilities, the net amount of frequency responsive generation online will be reduced.

49 

The Commission also explained that these developments and their potential impacts 

could challenge system operators in maintaining reliability.50 Further, the Commission 

explained that NERC Reliability Standard BAL-003-1.1 and the pro forma LGIA and pro 

 47 CAISO, 156 FERC ¶ 61,182, at PP 10-12 and 17 (2016).

48 NOI, 154 FERC ¶ 61,117.

49 Id. P 12.

50 Id. P 14.
Docket No. RM16-6-000 - 18 -

forma SGIA do not specifically address a generator’s ability to provide frequency 

response.51 The Commission noted, however, that while in previous years many nonsynchronous generating facilities were not designed with primary frequency response 

capabilities, the technology now exists for new non-synchronous generating facilities to 

install primary frequency response capability.

52

22. 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.53 Second, the Commission sought comment on the 

performance of existing generating facilities and whether primary frequency response 

requirements for these facilities are warranted.54 Finally, the Commission sought 

comment on compensation for primary frequency response.55

 51 Id. P 41.

52 Id. P 43.

53 Id. PP 2 and 44-45.

54 Id. PP 2, 46, and 52.

55 Id. PP 2, 53-54. 
Docket No. RM16-6-000 - 19 -

2. Comments on modifying the pro forma LGIA and pro forma 

SGIA

23. The Commission received a robust response from industry, with 47 entities 

collectively submitting nearly 700 pages of comments that provided responses to some or 

all of the questions posed by the NOI.56 Relevant to the proposed revisions considered in 

this NOPR, the Commission received numerous comments on whether the pro forma

LGIA and pro forma SGIA should be revised to include requirements for all newly 

interconnecting generating facilities, whether synchronous or non-synchronous, to install 

primary frequency response capability.57

a. Comments in support of modifying the pro forma LGIA 

and pro forma SGIA

24. Most commenters support, or are not opposed to, revising the pro forma LGIA and 

SGIA to impose primary frequency response capability requirements on all new 

generating facilities as suggested in the NOI.58 Several commenters indicate that the 

 56 The Appendix lists the entities that submitted comments and the shortened 

names that are used throughout this NOPR. 

57 NOI, 154 FERC ¶ 61,117 at P 45.

58 APPA, et al. Comments at 6; Bonneville Comments at 6; CAISO Comments 

at 2; California Cities Comments at 2; ELCON Comments at 5; EEI Comments at 12; 

EPSA, et al. Comments at 8; Howard F. Illian Comments at 43; Idaho Power Comments 

at 1; IEEE-PES Comments at 1; Indicated ISOs/RTOs Comments at 3; ITC, et al.

Comments at 1; MISO Comments at 4; MISO TOs Comments at 6; NARUC Comments 

at 3; NERC Comments at 17; North American Generator Forum Comments at 2; Peak 

Reliability Comments at 4; PG&E Comments at 2; SoCal Edison Comments at 4; 

Southern Company Comments at 2; Tri-State Generation Comments at 3; WIRAB 

Comments at 3.

(continued ...)
Docket No. RM16-6-000 - 20 -

nation’s changing resource mix could create reliability concerns related to the provision 

of primary frequency response. For example, PJM Utilities Coalition states that while 

newer generating facilities are not installing frequency response capability, the existing 

generating facilities that do provide this essential reliability service have more limited 

capability, due to the cost of operation and planned retirements, placing the grid at further 

risk.59 Peak Reliability, the reliability coordinator for the Western Interconnection, states 

that as baseload generation retires, the number of generators providing primary frequency 

response is reduced and may present reliability challenges for system operators, as fewer 

options are available to reduce frequency deviations following an unexpected loss of 

generation or load.60 CAISO asserts that due to the increased proportion of renewable 

generating facilities operating in CAISO’s balancing authority area, there may not be 

sufficient frequency responsive capacity online when the system has high renewable 

output and low load levels.61 Bonneville states that the trend of declining frequency 

response capability will continue with a changing resource mix, unless provisions are put 

in place to assure that adequate inertial and primary frequency response capability are 

 

59 PJM Utilities Coalition Comments at 3.

60 Peak Reliability Comments at 4.

61 CAISO Comments at 2.
Docket No. RM16-6-000 - 21 -

available in the future.62 NERC states that the rapidly changing resource mix may reduce 

the level of available frequency capability.63

25. Numerous commenters assert that they recognize the benefits of revising the 

pro forma LGIA and pro forma SGIA to require primary frequency response capabilities 

for new generators. NERC, for example, asserts that new primary frequency response 

requirements for generators will improve operator flexibility for system restoration and 

island capability and help balancing authorities meet their frequency response 

obligations.

64 NERC also asserts that revisions to the pro forma LGIA and pro forma

SGIA would result in measurable, clear requirements applicable to all new generating 

facilities in a fair and equitable manner.65 NERC points out, however, that primary 

frequency response capability, by itself, would not require a resource to respond if called

upon to help a balancing authority meet its frequency response obligation, and that, as a 

result, it is important to have mechanisms to ensure that sufficient frequency response 

capability is not only available but ready to respond at all times.66 CASIO, Indicated 

ISOs/RTOs, MISO, and a number of trade associations also support modifications to the 

 62 Bonneville Comments at 2.

63 NERC Comments at 17.

64 Id. 

65 Id.

66 Id. at 18.
Docket No. RM16-6-000 - 22 -

pro forma LGIA and pro forma SGIA for new generating facilities to install primary 

frequency response capability.

67 PJM Utilities Coalition states that, with all new 

generating facilities (both synchronous and non-synchronous) being fully capable of 

providing primary frequency response, requiring this capability will ensure that system 

operators have the ability to reliably operate the grid of the future.68 Peak Reliability

states that it supports modifications to the pro forma LGIA and pro forma SGIA and that 

requiring generating facilities to install or provide frequency response in the initial stages 

of the interconnection process will ensure that the grid is able to maintain this essential 

service even as the resource mix changes.69 

26. Other commenters also express support for revising the pro forma LGIA and 

pro forma SGIA. Bonneville points out that selling primary frequency response 

capability would not provide sufficient incentive for new generating facilities to invest 

in such capability, and argues that the only way to ensure that there is enough primary 

frequency response capability is to require new generators to install it.70 WIRAB advises

that while current studies do not indicate that there is a shortage of primary frequency 

 67 APPA, et al. Comments at 2; CAISO Comments at 2; EEI Comments at 3; 

EPSA, et al. Comments at 8; Indicated ISOs/RTOs Comments at 3; MISO Comments 

at 4; North American Generator Forum Comments at 2.

68 PJM Utilities Coalition Comments at 4-5.

69 Peak Reliability Comments at 4-5.

70 Bonneville Comments at 21.
Docket No. RM16-6-000 - 23 -

response in the Western Interconnection and that all generators do not need to provide 

primary frequency response all of the time, the Commission should, however, require that 

all new generator owners install primary frequency response capability because of the 

changing resource mix in the Western Interconnection and the associated uncertainty 

regarding the future provision of primary frequency response.71

27. Several commenters that generally support revising the pro forma LGIA and 

pro forma SGIA also express certain concerns. For example, Southern Company 

expresses support for revising the pro forma LGIA and pro forma SGIA, but caveats its 

support by arguing that new regulations for primary frequency response should include 

an “opt-out” provision that would allow balancing authorities that do not anticipate 

frequency response shortfalls to delay the implementation of the new pro forma LGIA 

and pro forma SGIA requirements until these needs are actually anticipated in their 

regions in order to avoid higher costs.

72 EPSA, et al. state that while they do not fully 

oppose amending the pro forma LGIA and pro forma SGIA, they recommend that the 

Commission explore more effective and cost efficient ways to address the range of issues 

posed in the NOI and consider a measured approach before mandating governors for all 

prospective interconnecting generation.

73

 71 WIRAB Comments at 5-6.

72 Southern Company Comments at 2-3. 

73 EPSA, et al. Comments at 8-9.
Docket No. RM16-6-000 - 24 -

28. Some commenters that support modifying the pro forma LGIA and pro forma

SGIA also assert that the costs of implementing primary frequency response capability 

for new generating facilities are low.74 For example, APPA, et al. state that the capability 

for providing primary frequency response is almost always installed in synchronous 

generation, and that the inclusion of this additional control for new non-synchronous 

generating facilities would likely add only nominal costs.75 EEI asserts that all new 

generating facilities coming online can be fully capable of providing primary frequency 

response and that the associated cost of installing such capability during initial 

manufacturing or construction of a new VER is small when considering the overall cost 

of the new generating facility.

76 

29. In contrast to new generating facilities, some entities, however, explain that the 

costs of retrofitting existing generating facilities with primary frequency response 

capability could be significant in some cases.77 For example, WIRAB states that the high 

 74 APPA, et al. Comments at 6; Bonneville Comments at 8; California Cities 

Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at 5; MISO 

Comments at 4; SoCal Edison Comments at 2.

75 APPA, et al. Comments at 6.

76 EEI Comments at 13.

77 APPA, et al. Comments at 6; Bonneville Comments at 8; California Cities 

Comments at 8; EEI Comments at 14; Idaho Power Comments at 4; WIRAB Comments 

at 6.
Docket No. RM16-6-000 - 25 -

cost of retrofitting existing generators to install the necessary control equipment supports 

limiting the requirement to new generators and taking early action now.78

30. In regards to nuclear generating facilities, some commenters indicate that nuclear 

plants have separate licensing requirements under the Nuclear Regulatory Commission 

and should not be required to provide primary frequency response. For example, the 

Nuclear Energy Institute asserts that while nearly all new generating facilities should be 

able to provide primary frequency response, nuclear plants are not well-suited to provide 

primary frequency response due to restrictions by their operating licenses issued by the 

Nuclear Regulatory Commission.79 The Nuclear Energy Institute also asserts that turbine 

controls on most nuclear units are designed to maintain the internal steam pressure and 

are not intended to react to changes in the grid.80 Similarly, the MISO TOs assert that 

requiring nuclear units to have primary frequency response capability would be contrary 

to Nuclear Regulatory Commission licensing requirements, and could have a detrimental 

effect on the safety of the nuclear fleet.81

31. In the NOI, the Commission also sought comment on whether it would be 

appropriate to include recommended governor settings contained within NERC’s Primary

 78 WIRAB Comments at 6.

79 Nuclear Energy Institute Comments at 1 and 4.

80 Nuclear Energy Institute Comments at 4.

81 MISO TOs Comments at 7.
Docket No. RM16-6-000 - 26 -

Frequency Control Guideline in the pro forma LGIA and pro forma SGIA.82 Numerous 

commenters express support for including NERC’s recommended governor control 

settings in the pro forma LGIA and pro forma SGIA.83 Some commenters note that 

NERC’s Guideline is consistent with existing regulations or practices in certain regions.84 

Indicated ISOs/RTOs point out that common primary frequency response settings for 

generators in an Interconnection will enhance reliability by reducing maneuvering by 

individual generators.85 MISO asserts that NERC’s Guideline provides a sound 

baseline.86 NERC notes that its Guideline was developed by technical committees with 

expertise and judgment of the electric industry, and accordingly, the Guideline is the 

“most advanced set of nation-wide best practices and information currently available to 

support frequency response capability.”87

32. However, not all entities that support modifying the pro forma LGIA and 

pro forma SGIA endorse the inclusion of NERC’s recommended governor settings. For 

example, EEI states that it does not support including prescriptive performance 

 82 NOI, 154 FERC ¶ 61,117 at P 45.

83 See e.g., Bonneville Comments at 7; IEEE-PES Comments at 1; Indicated 

ISOs/RTOs Comments at 4; California Cities Comments at 2; WIRAB Comments at 7.

84 Indicated ISOs/RTOs Comments at 4; SoCal Edison Comments at 4; Peak 

Reliability Comments at 7; Manitoba Comments at 8.

85 Indicated ISOs/RTOs Comments at 5.

86 MISO Comments at 4.

87 NERC Comments at 12.
Docket No. RM16-6-000 - 27 -

requirements for governor control settings or other performance indicators in the 

pro forma LGIA or pro forma SGIA due to the physical, technical, or operational 

limitations of new generating facilities to provide primary frequency response.88 

Similarly, APPA, et al. state that they do not support revising the pro forma LGIA and 

pro forma SGIA to include the recommended settings contained within NERC’s 

Guideline at this time.89 MISO TOs state that some transmission owners in MISO

believe that NERC’s recommended governor settings are appropriate for traditional 

synchronous generating facilities, but recommend additional consideration for other 

generation technologies.90 On the other hand, MISO TOs state that other transmission 

owners in MISO request flexibility and assert that specified governor settings should not 

be “hard-wired” or dictated in the pro forma LGIA and pro forma SGIA.

91

b. Comments opposed to modifying the pro forma LGIA and 

pro forma SGIA

33. Other commenters contend that the pro forma LGIA and pro forma SGIA should 

not be modified to require primary frequency response capability from new generating

 88 EEI Comments at 15-17.

89 APPA, et al. Comments at 8.

90 MISO TOs Comments at 8.

91 MISO TOs Comments at 8.
Docket No. RM16-6-000 - 28 -

facilities.

92 Some commenters argue that requiring all new generating facilities to have 

primary frequency response capability will result in extra costs above those necessary to 

ensure reliability.93 For example, APS argues that a global mandate to provide primary 

frequency response or to require generating facilities to be primary frequency response 

capable would result in significantly increased costs while providing a disproportionately 

minor impact on improving reliability.94 Powerex asserts that modifying the pro forma

LGIA and pro forma SGIA to include minimum primary frequency response 

requirements will increase the cost of entry for new generators, particularly VERs, which 

typically are not designed with such capability.95 Several commenters note that there 

would be a significant opportunity cost for certain generating facilities to reserve 

headroom for the provision of primary frequency response.96

 92 AES Companies Comments at 6; Apex Comments at 6; APS Comments at 6; 

AWEA Comments at 12; Chelan County Comments at 2; ESA Comments at 2; Grid 

Storage Consulting Comments at 2; Microgrids Resources Coalition Comments at 3; 

NRECA Comments at 9; Powerex Comments at 5; SDG&E Comments at 3; SolarCity 

Comments at 1; TVA Comments at 2. 

93 Apex Comments at 5-6; APS Comments at 6; AWEA Comments at 12; Chelan 

County Comments at 2; Powerex Comments at 5; Solar City Comments at 1.

94 APS Comments at 6. It is unclear whether the increased costs referenced by 

APS refer only to the costs for the necessary equipment to provide primary frequency 

response or the costs associated with maintaining the headroom necessary to provide 

primary frequency response. 

95 Powerex Comments at 5.

96 Apex Comments at 7; Solar City Comments at 1; AWEA Comments at 6.
Docket No. RM16-6-000 - 29 -

34. Some of the commenters that are opposed to modifying the pro forma LGIA and 

pro forma SGIA assert that they prefer a market-based approach instead of a requirement 

for new generating facilities to install primary frequency response capability.97 For

example, AWEA asserts that, initially, the pro forma LGIA and pro forma SGIA should 

not be revised to require new generating facilities to have primary frequency response

capability, and only if market-based steps do not satisfactorily address the need for 

primary frequency response, then the Commission could consider an additional 

requirement for new generating facilities to have such capability as a final step.98

35. Other commenters oppose mandatory requirements and prefer a voluntary 

approach to improving primary frequency response performance.99 For example, TVA 

asserts that if current voluntary actions fail to show improvement in primary frequency 

response, then the pro forma LGIA and pro forma SGIA could be revised to contain a 

general primary frequency response requirement, similar to reactive power, but that 

NERC should be directed to establish governor settings and performance requirements 

through the NERC Standards Development Process instead of the Commission including 

such requirements in the pro forma LGIA and pro forma SGIA.100 Some commenters 

 97 Apex Comments at 6; AWEA Comments at 12; Chelan County Comments at 2; 

ESA Comments at 2; SDG&E Comments at 3.

98 AWEA Comments at 12.

99 APS Comments at 8; NRECA Comments at 6; TVA Comments at 2.

100 TVA Comments at 2-3 and 5.
Docket No. RM16-6-000 - 30 -

assert that governor control details are better left to individual balancing authorities.101 

For example, APS argues that the Commission should allow balancing authorities to 

determine the type and magnitude of generating facilities within its balancing authority 

area that are frequency-response enabled.102 APS also points out that any need to install 

frequency response capability or otherwise support frequency response performance can 

and should be evaluated and agreed upon between a generating facility and the 

transmission provider during the interconnection study process.103

II. Discussion

A. Primary Frequency Response Requirements

1. The Need for Reform

36. Pursuant to FPA section 206, the Commission preliminarily finds that conditions 

have changed since the issuance of Order Nos. 2003 and 2006 and certain aspects of the 

pro forma LGIA and pro forma SGIA may now be unjust, unreasonable, unduly 

discriminatory, or preferential.104 Specifically, as discussed above, the record indicates 

that while the frequency response performance of the Eastern and Western 

Interconnections is currently adequate, the frequency response performance of both 

 101 APS Comments at 8; AES Companies Comments at 8.

102 APS Comments at 8.

103 Id. at 15.

104 The Commission routinely evaluates the effectiveness of its regulations and 

policies in light of changing industry conditions to determine if changes are necessary. 

See, e.g., Order No. 764, FERC Stats. & Regs. ¶ 31,331.
Docket No. RM16-6-000 - 31 -

Interconnections has significantly declined from historic values.

105 Furthermore, the 

record shows that there is an ongoing evolution of the nation’s generation resource mix, 

including significant retirements of baseload generation and an increasing proportion of 

VERs interconnecting to the electric grid.106 Several commenters point out that there is 

significant risk that the rapidly changing resource mix may reduce the level of available 

frequency response capability online.

107 This is in part because, as noted in the NOI, 

VERs have not been consistently designed with primary frequency response 

capabilities.

108 The record suggests, however, that VER manufacturers have made 

significant technological advancements in recent years to develop primary frequency 

response capability for VERs.109 In addition, NERC, in conjunction with various 

industry stakeholders, has developed more robust technical guidance for the operation of 

governors or equivalent controls.110 As a result of the evolving resource mix and the 

potential for adverse impacts on primary frequency response, the Commission is 

concerned that there may be potential reliability impacts if it does not undertake the 

reforms proposed in this NOPR. Moreover, the Commission is concerned that certain 

aspects of the existing pro forma LGIA and pro forma SGIA may no longer be just and 

reasonable.

 105 See NERC 2015 Frequency Response Webinar at 10, NERC Frequency 

Response Initiative Report at 22, and LBNL 2010 Report at pp xiv-xv.

106 See, e.g., P 12, supra (describing recent and ongoing changes in the nation’s 

generation mix).

107 See, e.g., Bonneville Comments at 2; CAISO Comments at 2; NERC 

Comments at 17; Peak Reliability Comments at 4; PJM Utilities Coalition Comments 

at 3.

108 NOI, 154 FERC ¶ 61,117 at PP 42-43.

109 See, e.g., PJM Utilities Comments at 4-5; EEI Comments at 13. See also PJM 

Interconnection, L.L.C., Docket No. ER15-1193-000 (March 6, 2015) Transmittal Letter 

at 11. See also NERC 2014 LTRA, at 27 (Nov. 2014), 

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014LTRA_ERA

TTA.pdf.

110 See P 16, supra.
Docket No. RM16-6-000 - 32 -

37. First, the current requirements for governor controls in the pro forma LGIA do not 

reflect advances in technology or the latest recommended operating practices. 

Specifically, current Article 9.6.2.1 states that “speed governors,” if installed, must be 

operated in automatic mode. However, many of the new generating facilities 

interconnecting to the grid, such as wind and solar, do not utilize traditional speed 

governors; instead they utilize enhanced inverters and other plant supervisory control

technology that can be designed to include primary frequency response capability.

111 

Therefore, due to advancements in technology, the Commission preliminarily finds that 

the existing references to “speed governors” in Article 9.6.2.1 that apply only to 

synchronous resources are outdated, and therefore may no longer be just and reasonable. 

38. Second, since the issuance of Order No. 2003 and the establishment of the 

pro forma LGIA, NERC, in conjunction with industry stakeholders, has amassed a 

significant body of knowledge in regards to the operation of generator governors and 

plant control systems. For example, as noted above, NERC observed in 2012 that a 

number of generators implemented deadband settings that were so wide as to effectively 

defeat the ability to provide primary frequency response, and that many generators 

 111 See Electric Power Research Institute, Recommended Settings for Voltage and 

Frequency Ride Through of Distributed Energy Resources (May 2015) at 27, 

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.
Docket No. RM16-6-000 - 33 -

provide frequency response in the wrong direction during a disturbance.112 Additionally, 

as noted above, NERC observed in 2015 that in many conventional steam plants, 

deadband settings exceed a ±0.036 Hz dead band, resulting in primary frequency 

response that is not sustained, and that the vast majority of the gas turbine fleet is not 

frequency responsive.

113

39. The record here suggests that the actual governor and plant control system settings 

that are being implemented by some generator owners and/or operators may be defeating 

the intent of Article 9.6.2.1 of the pro forma LGIA. In response to these issues, NERC, 

through the work of its various task forces, subcommittees, and initiatives, has developed 

a voluntary Guideline that includes recommended droop and deadband settings based on 

significant investigation.

114 However, the pro forma LGIA does not currently reflect 

these updated recommended practices for governor and plant control system settings of 

generating facilities.

40. Third, given the nation’s evolving resource mix and the potential adverse impacts

on primary frequency response as noted in the NOI and pointed out by several 

commenters, the Commission believes that changes to the pro forma LGIA and 

pro forma SGIA may be necessary to provide for the continued reliable operation of the 

 112 See P 16, supra.

113 Id.

114 See NERC Primary Frequency Control Guideline. 
Docket No. RM16-6-000 - 34 -

power system. As noted above, the Task Force concluded that all new generating 

facilities should be required to be capable of providing primary frequency response.115 

However, the pro forma LGIA does not currently require large generating facilities to 

install such capability; rather, it only requires governor operation in “automatic mode” if

a “speed governor” is installed.

116

41. In addition, the Commission is concerned that the current pro forma SGIA may be 

unduly discriminatory or preferential because it does not establish any specific 

requirements with respect to the installation or operation of governors or equivalent 

frequency control equipment. In particular, the pro forma SGIA does not have a similar 

provision to Article 9.6.2.1 of the pro forma LGIA. The Commission has previously 

acted under FPA section 206 to remove inconsistencies between the pro forma LGIA and 

pro forma SGIA when there is no economic or technical basis for treating large and small 

generating facilities differently.117 Similarly, in this instance, the record developed from

the NOI appears to suggest that small generating facilities are capable of installing and 

 115 See P 15, supra.

116 Article 9.6.2.1 of the pro forma LGIA. 

117 See Requirements for Frequency and Voltage Ride Through Capability of Small 

Generating Facilities, Order No. 828, 81 FR 50,290 (Aug. 1, 2016), 156 FERC ¶ 61,062 

(2016), (The Final Rule revised 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 - 35 -

enabling governors at low cost in a manner comparable to large generating facilities.

118 

As discussed above, the record indicates that there have been significant advances in 

technology, as well as the development of more robust technical guidance for the 

operation of governors or equivalent controls for both large and small generating 

facilities.

119 In particular, the IEEE-P1547 Working Group noted that its new IEEE-1547 

standard for interconnecting distributed generation will likely include certain 

requirements for providing primary frequency response.120 Given these low-cost 

technological advances, the Commission does not anticipate that these additional 

requirements added in the pro forma SGIA will present a barrier to entry 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 believes that there is a need to add these requirements to the pro forma

SGIA to help ensure adequate primary frequency response capability.

42. Moreover, as noted above, a number of commenters assert that costs for new 

generating facilities to install the capability of providing primary frequency response are 

 118 IEEE-P1547 Working Group Comments at 1, 5, and 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. 

119 See PP 13, 36, supra.

120 IEEE-P1547 Working Group Comments at 1, 5, and 7.
Docket No. RM16-6-000 - 36 -

low, suggesting that there is not a financial barrier to small generating facilities installing 

the capability to provide frequency response.121 PJM’s recent changes to require both 

small and large non-synchronous generating facilities to use enhanced inverters, which 

include primary frequency response capability, among other functions, further support 

this notion.122

2. Commission Proposal

43. To remedy the potentially unjust, unreasonable, and unduly discriminatory or 

preferential practices described above, the Commission preliminarily finds that revisions 

to the pro forma LGIA and pro forma SGIA are appropriate. The Commission believes

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 proposed requirements described below, will help to ensure adequate 

primary frequency response capability as the 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 NERC Reliability 

 121 See, e.g., APPA, et al. Comments at 2; EEI Comments at 13; Indicated 

ISOs/RTOs Comments at 5; SoCal Edison Comments at 2.

122 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097 at P 28 (the Commission 

stated that it “find[s] that PJM’s proposal will not present a barrier to non-synchronous 

resources.”).
Docket No. RM16-6-000 - 37 -

Standard BAL-003-1.1, and help improve reliability during system restoration and 

islanding situations.

123

44. In particular, the Commission proposes to revise the pro forma LGIA and 

pro forma SGIA to include the following: (1) 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; (2) requirements for governor or equivalent controls to be operated, 

at a minimum, with maximum 5 percent droop and ±0.036 Hz deadband settings; 

(3) requirements to ensure the timely and sustained response to frequency deviations, 

including provisions to prevent plant-level (i.e., outer-loop) control equipment from 

inhibiting primary frequency response and resulting in premature withdrawal; and (4) a 

requirement for droop parameters to be based on nameplate capability with a linear 

operating range of 59 to 61 Hz. Additionally, as informed by NOI commenters, the 

Commission believes that it is not necessary to impose a generic headroom requirement 

or subject newly interconnecting nuclear generating facilities to the new requirements.

The Commission does not propose to mandate any separate compensation related to the 

proposed requirements. The Commission seeks comment on the proposed reforms, as 

discussed more fully below.

 123 See NERC Comments at 17. See also NERC Essential Reliability Services 

Task Force Measures Framework Report at iv. 
Docket No. RM16-6-000 - 38 -

45. Specifically, the Commission proposes to revise existing sections 9.6 and 9.6.2.1 

of the pro forma LGIA and to include proposed new sections 9.6.4, 9.6.4.1, 9.6.4.2, and 

9.6.4.3. Similarly, the Commission proposes to revise existing section 1.8 of the pro 

forma SGIA and add proposed new sections 1.8.4, 1.8.4.1, 1.8.4.1.1, 1.8.4.1.2, and 

1.8.4.1.3.124

46. The Commission’s proposed revisions to the pro forma LGIA and pro forma

SGIA would apply 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 in Docket No. RM16-6-000. The Commission also proposes 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 in Docket No. RM16-6-000, but that takes 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 any Final Rule in Docket 

No. RM16-6-000. 

47. In particular, the proposed revisions to the pro forma LGIA and pro forma SGIA 

would require new large and small generating facilities to install, maintain, and operate a 

functioning governor or equivalent controls, which the Commission proposes to define 

as the required hardware and/or software that provides frequency responsive real power 

 124 The specific proposed modifications and additions to the pro forma LGIA and 

pro forma SGIA are set forth at PP 52-53, below.
Docket No. RM16-6-000 - 39 -

control with the ability to sense changes in system frequency and autonomously adjust 

the generating facility’s real power output in accordance with the proposed maximum

droop and deadband parameters and in the direction needed to correct frequency 

deviations. The Commission seeks comment on this proposal.

48. The Commission also proposes to require new large and small 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. As noted above, the Commission sought comment in 

the NOI on whether NERC’s recommended guidance for governor settings related to 

droop and deadband should be included in the pro forma LGIA and pro forma SGIA, 

and numerous commenters agreed stating that NERC’s Guideline provides a sound 

baseline.125 Therefore, the Commission preliminarily finds that a maximum droop 

setting of 5 percent and deadband setting of ±0.036 Hz are appropriate to include in 

the pro forma LGIA and pro forma SGIA as interconnection requirements for new 

generating facilities. 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 

 125 See e.g., Bonneville Comments at 7; California Cities Comments at 2; IEEEPES Comments at 2; Indicated ISOs/RTOs Comments at 4; MISO Comments at 4; 

WIRAB Comments at 7.
Docket No. RM16-6-000 - 40 -

so.126 The Commission seeks comment on these proposed requirements for droop and

deadband settings. 

49. The Commission also proposes 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 as discussed below. The lack of coordination 

between governor and plant-level control systems can result in premature withdrawal of 

primary frequency response by allowing additional plant control systems to reverse the 

action of the governor to return the unit to operating at a pre-selected target set-point.

127 

NERC’s 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.”128 Accordingly, the Commission proposes to require new 

generating facilities that respond to frequency deviations to not inhibit primary frequency 

response, such as by coordinating plant-level, outer-loop control equipment with the 

governor or equivalent controls, except under certain operational constraints including,

 126 Moreover, the Commission proposes that nothing in these requirements would 

prohibit the implementation of asymmetrical droop settings (i.e., different droop settings 

for under-frequency and over-frequency conditions), provided that each segment has a 

droop value of no more than 5 percent. 

127 NERC Frequency Response Initiative Report at 31. See also NOI, 154 FERC 

¶ 61,117 at P 49 (stating 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”).

128 NERC Primary Frequency Control Guideline at 4.
Docket No. RM16-6-000 - 41 -

but not limited to, ambient temperature limitations, outages of mechanical equipment, or

regulatory requirements. The Commission also proposes to require new generating

facilities to respond to frequency deviations without undue delay and to sustain the 

response until at least system frequency returns to a stable value within the governor’s 

deadband setting. The Commission believes this proposed requirement for sustained 

response is consistent with the current requirements of PJM and ISO-NE as well as

similar OATT revisions recently implemented by CAISO.129 The Commission seeks

comment on the proposed requirements for sustained response. In particular, the 

Commission seeks comment on whether these provisions will be sufficient to prevent 

plant-level (i.e., outer-loop) controls from inhibiting primary frequency response.

50. Regarding droop settings, in its comments to the NOI, MISO proposed that a 

linear droop should be available between 59 to 61 Hz.130 The Commission believes 

that this is reasonable because it would allow for new generating facilities that remain 

connected during frequency deviations to provide a proportional response within this 

range of frequencies. Accordingly, the Commission proposes to require the droop 

parameter to be based on the nameplate capability of the unit and linear in operating 

range between 59 to 61 Hz. The Commission seeks comment on these proposed 

requirements for droop settings.

 129 See, e.g., ISO-NE Operating Procedure OP-14 and PJM Manual 14D. See also

CAISO, 156 FERC ¶ 61,182 at PP 10-12 and 17.

130 MISO Comments at 4.
Docket No. RM16-6-000 - 42 -

51. Several NOI commenters expressed concern about possible generic headroom 

requirements131 that could result in significant opportunity costs.132 The Commission 

clarifies that nothing in these proposed reforms will impose a generic headroom 

requirement for new generating facilities or affect the unit commitment and dispatch 

decisions of balancing authorities. Therefore, if a generating facility that is subject to 

these proposed requirements has been dispatched by its balancing authority to a set-point 

at which there is no available operating range to increase or decrease its output in 

response to frequency deviations, it would not be in violation of the proposed 

requirements in regards to providing sustained response. The Commission believes 

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. The Commission also agrees with NOI commenters regarding 

the unique operating characteristics and regulatory requirements of nuclear generating 

facilities regulated by the Nuclear Regulatory Commission, and therefore proposes to 

exempt such generating facilities from the proposed reforms.133 The Commission seeks 

 131 A generic headroom requirement would require generating facilities to operate 

below maximum output at all times to ensure sufficient ability to increase their real 

power output in response to under-frequency conditions.

132 See, e.g., Apex Comments at 7; Solar City Comments at 1; AWEA Comments 

at 6.

133 See, e.g., Nuclear Energy Institute Comments at 1, 4; MISO TOs Comments 

at 7.
Docket No. RM16-6-000 - 43 -

comment on the proposal to not impose a generic headroom requirement and to not apply 

the new requirements to nuclear generating facilities.

52. In light of the above discussion, the Commission proposes to modify sections 9.6 

and 9.6.2.1 of the pro forma LGIA and add new sections 9.6.4, 9.6.4.1,9.6.4.2, and 

9.6.4.3 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 
Docket No. RM16-6-000 - 44 -

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 with a maximum 5 percent droop and ±0.036 

Hz deadband. The droop characteristic shall be based 

on the nameplate capacity of the Large Generating 

Facility, and shall be linear in the range of 59 to 61 Hz. 

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. 

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 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 or 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 
Docket No. RM16-6-000 - 45 -

shall, in coordination with Transmission Provider, set 

the deadband parameter to a maximum of ±0.036 Hz 

and set the droop parameter to a maximum of 5 

percent. Interconnection Customer shall be required to 

provide the status and settings of the governor or 

equivalent controls to Transmission Provider 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. Interconnection Customer shall make 

Reasonable Efforts to return its governor or equivalent 

controls into service as soon as practicable. 

9.6.4.2 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 provided 

without undue delay, and ensure that the response is 

not inhibited, except under certain operational 

constraints including, but not limited to, ambient 

temperature 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.

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.

53. Similarly, the Commission proposes to modify section 1.8 of the pro forma SGIA 

and add new sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 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, 
Docket No. RM16-6-000 - 46 -

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 with a maximum 5 percent droop and ±0.036 Hz 

deadband. The droop characteristic shall be based on the 

nameplate capacity of the Small Generating Facility, and shall 

be linear in the range of 59 to 61 Hz. 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. 

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, in coordination with Transmission Provider, set 

the deadband parameter to a maximum of ± 0.036 Hz 

and set the droop parameter to a maximum of 5 
Docket No. RM16-6-000 - 47 -

percent. Interconnection Customer shall be required to 

provide the status and settings of the governor or 

equivalent controls to Transmission Provider 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. Interconnection Customer shall make 

Reasonable Efforts to return its governor or equivalent 

controls into service as soon as practicable.

1.8.4.2 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 provided 

without undue delay, and ensure that the response is 

not inhibited, except under certain operational 

constraints including, but not limited to, ambient 

temperature 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.

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, 1.8.4.2 of this Agreement.

54. The Commission proposes to apply the primary frequency response requirements 

to any new large or small generating facility that executes or requests the unexecuted 

filing of a LGIA or SGIA on or after the effective date of any Final Rule issued in this 

proceeding. In addition, the Commission proposes 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 in Docket 
Docket No. RM16-6-000 - 48 -

No. RM16-6-000, but that takes 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 any Final Rule in Docket 

No. RM16-6-000. The Commission seeks comment on the proposed effective date

including whether applying these requirements to existing 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 any Final Rule in Docket No. RM16-6-000 would be unduly burdensome.

55. The Commission does not propose in this NOPR to require that the 

interconnection customer receive any compensation for these proposed requirements. 

The 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.134 While the Commission has not required compensation 

for similar requirements in the past, it clarifies that nothing in this NOPR is meant to 

prohibit a public utility from filing a proposal for primary frequency response 

compensation under FPA section 205, if it so chooses.135

 134 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097, at n.58 (2015); CAISO, 

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).

135 16 U.S.C. 824d (2012).
Docket No. RM16-6-000 - 49 -

B. Request for Comment

56. The Commission seeks 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; (4) requirement for 

droop parameters to be based on nameplate capability with a linear operating range of 

59 to 61 Hz; (5) exemptions for new nuclear units; and (6) effective dates as discussed 

above. The Commission also seeks comment on its proposal to not impose a generic 

headroom requirement or mandate compensation related to the proposed reforms.

57. In the NOI, the Commission also sought comment on the performance of existing 

resources and whether primary frequency response requirements for these resources are 

warranted.136 At this time, the Commission proposes only to adopt the reforms included 

in this NOPR regarding newly interconnecting large and small generating facilities. 

However, the Commission seeks comment regarding whether the reforms proposed in 

this NOPR are sufficient to ensure adequate levels of primary frequency response, or 

whether additional reforms are needed. In particular, the Commission seeks comment on 

whether additional primary frequency response performance or capability requirements 

for existing resources are needed, and if so, whether the Commission should impose 

those requirements by: (1) directing the development or modification of a reliability 

 136 NOI, 154 FERC ¶ 61,117 at PP 2, 46-52.
Docket No. RM16-6-000 - 50 -

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.

C. Proposed Compliance Procedures

58. The Commission proposes to require all public utility transmission providers to 

adopt the requirements of any Final Rule in Docket No. RM16-6-000 as revisions to the 

LGIA and SGIA in their OATTs within 60 days after the publication of the Final Rule in 

the Federal Register. 

59. Some public utility transmission providers may have provisions in their 

existing LGIAs and SGIAs that the Commission has found to be consistent with or 

superior to the pro forma LGIA and pro forma SGIA. Where these provisions would be 

modified by the Final Rule, public utility transmission providers must either comply with 

the Final Rule or demonstrate that these previously-approved variations continue to be 

consistent with or superior to the pro forma LGIA and pro forma SGIA as modified by 

the Final Rule. The Commission also proposes to permit appropriate entities to seek 

“independent entity variations” from the proposed revisions to the pro forma LGIA and 

pro forma SGIA.137

60. The Commission would assess whether each compliance filing satisfies the 

proposed requirements stated above and issue additional orders as necessary to ensure 

 137 See, e.g., Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 827.
Docket No. RM16-6-000 - 51 -

that each public utility transmission provider meets the requirements of the subsequent 

Final Rule.

61. The Commission also proposes that transmission providers that are not public 

utilities would have to adopt the requirements of this proposal and subsequent Final Rule 

as a condition of maintaining the status of their safe harbor tariff or otherwise satisfying 

the reciprocity requirement of Order No. 888.138

III. Information Collection Statement

62. The Paperwork Reduction Act (PRA)139 requires each federal agency to seek and 

obtain Office of Management and Budget (OMB) approval before undertaking a 

collection of information directed to ten or more persons, or contained in a rule of general 

applicability. OMB’s regulations require the approval of certain information collection 

requirements imposed by agency rules.140 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 are subject to the proposed revisions to the 

pro forma LGIA and SGIA.

 138 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,760-63.

139 44 U.S.C. 3501-3520 (2012).

140 5 CFR 1320.11 (2016).
Docket No. RM16-6-000 - 52 -

63. In this NOPR, the Commission proposes to amend its pro forma LGIA and 

pro forma SGIA in accordance with section 35.28(f)(1) of its regulations.

141 The 

proposed revisions to the pro forma LGIA and pro forma SGIA would require new large 

and small generating facilities to install, maintain, and operate a functioning governor or 

equivalent controls which the Commission proposes to define as the required hardware 

and/or software that provides frequency responsive real power control with the ability to 

sense changes in system frequency and autonomously adjust the generating facility’s real 

power output in accordance with the proposed maximum droop and dead band 

parameters and in the direction needed to correct frequency deviations. The NOPR 

proposes to require each public utility transmission provider to amend its pro forma

LGIA and pro forma SGIA to require that all newly interconnecting large and small 

generating facilities, 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, to adhere to the proposed 

requirements, on or after the effective date of any Final Rule issued in this proceeding.

64. The reforms in this NOPR would require filings of pro forma LGIAs and 

pro forma SGIAs with the Commission. The Commission anticipates the proposed 

reforms, once implemented, would not significantly change currently existing burdens on 

an ongoing basis. With regard to those public utility transmission providers that believe 

 141 18 CFR § 35.28(f)(1) (2016).
Docket No. RM16-6-000 - 53 -

that they already comply with the proposed reforms in this NOPR, they could 

demonstrate their compliance in the filing required 60 days after publication of the Final 

Rule in the Federal Register. The Commission will submit the proposed reporting 

requirements to OMB for its review and approval under section 3507(d) of the Paperwork 

Reduction Act.142 The Commission will use FERC-516Bas a temporary “placeholder” 

information collection number.

143

 142 44 U.S.C. 3507(d) (2012).

143 The reporting requirements in this NOPR would normally be included under 

FERC-516 (OMB Control No. 1902-0096). However, FERC-516 is pending review at 

OMB in an unrelated action. Because only one item per OMB Control No. can be 

pending OMB review at a time, the Commission is temporarily using the information 

collection number FERC-516B (OMB Control No. 1902-0286) to ensure timely submittal 

of this NOPR to OMB.
Docket No. RM16-6-000 - 54 -

Burden Estimate144: The Commission believes that the burden estimates below are 

representative of the average burden on respondents. The estimated burden and cost for 

the requirements contained in this NOPR follow.145

FERC 516B, in NOPR in RM16-6

No. of 

Respondents

146

(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; 

$745.00

740 hours;

$55,130.00 

Total 74 740 hours; 

$55,130.00

 144 Burden means the total time, effort, or financial resources expended by persons 

to generate, maintain, retain, disclose or provide information to or for a Federal agency, 

including: The time, effort, and financial resources necessary to comply with a collection 

of information that would be incurred by persons in the normal course of their activities 

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

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

needed to comply are usual and customary. 

145 For this information collection, the Commission staff estimates that industry 

is similarly situated in terms of hourly cost (wages plus benefits). Based on the 

Commission’s average cost (wages plus benefits) for 2016, the Commission is using 

$74.50/hour.

146 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 - 55 -

There are no maintenance cost, installation cost or any additional cost or requirements 

after year 1.

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

Action: Revision of currently approved collection of information.

OMB Control No.: 1902-0286

Respondents for this Rulemaking: Businesses or other for profit and/or not-for-profit 

institutions.

Frequency of Information: One-time during year 1.

Necessity of Information: The Commission proposes to revise 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 Commission proposes to revise the pro forma LGIA and the pro forma

SGIA.

Internal Review: The Commission has reviewed the proposed 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.

65. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 
Docket No. RM16-6-000 - 56 -

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.

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

the proposed 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 refer to OMB Control No. 1902-0286 

in your submission.

IV. Environmental Analysis

67. 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.147 The Commission concludes that neither an Environmental 

Assessment or an Environmental Impact Statement is required for proposed revisions 

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, 

 147 Order No. 486, Regulations Implementing the National Environmental Policy 

Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986-1990 ¶ 30,783 

(1987).
Docket No. RM16-6-000 - 57 -

contracts and regulations that affect rates, charges, classifications, and services.148 The 

revisions proposed in this NOPR update and clarify the application of the Commission’s 

standard interconnection requirements to synchronous and non-synchronous generators. 

Therefore, this NOPR falls within the categorical exemptions provided in the 

Commission’s regulations, and therefore neither an Environmental Assessment nor an 

Environmental Impact Statement is required.

V. Regulatory Flexibility Act

68. The Regulatory Flexibility Act of 1980 (RFA)149 generally requires a description 

and analysis of proposed 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.

69. 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 

 148 18 CFR 380.4(a)(15) (2015).

149 5 U.S.C. 601-612 (2012).
Docket No. RM16-6-000 - 58 -

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

500 employees.150

70. The Commission estimates that the total number of transmission providers, both 

public and non-public, affected by this NOPR is 74.151 Of these, the Commission 

estimates that approximately 27.5 percent are small entities. The Commission estimates 

the average total cost to each of these entities will be minimal, requiring on average 

10 hours, or $745.00. 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.”152 The Commission 

does not consider the estimated burden to be a significant economic impact. As a result, 

the Commission believes this NOPR would not have a significant economic impact on a 

substantial number of small entities.

71. 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 

 150 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121 (Electric Bulk 

Power Transmission and Control).

151 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.

152 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 - 59 -

NOPR would be approximately 200, representing approximately 5,000 MW of installed 

capacity. Of these, the Commission estimates that the majority are small entities. The 

Commission estimates the average total cost to each of these entities will be minimal, 

requiring on average approximately $3,300 per MW of installed capacity. 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.153 Additionally, the Commission does not believe that there will 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. Accordingly, the Commission believes that this NOPR 

would not have a significant economic impact on a substantial number of small entities.

VI. Comment Procedures

72. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

 153 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), 

http://www.nrel.gov/docs/fy15osti/64746.pdf.
Docket No. RM16-6-000 - 60 -

proposals that commenters may wish to discuss. Comments are due [INSERT DATE 

60 days after publication in the FEDERAL REGISTER]. Comments must refer to 

Docket No. RM16-6-000, and must include the commenter's name, the organization they 

represent, if applicable, and their address in their comments.

73. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing.

74. Commenters that are not able to file comments electronically must send an 

original of their comments to: Federal Energy Regulatory Commission, Secretary of the 

Commission, 888 First Street NE, Washington, DC 20426.

75. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters.

VII. Document Availability

76. 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 
Docket No. RM16-6-000 - 61 -

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

77. 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 excluding the last three digits of this 

document in the docket number field.

78. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from the Commission’s Online Support at (202) 502-6652 (toll 

free at 1-866-208-3676) or email at 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.

By direction of the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM16-6-000 - 62 -

Appendix

List of Commenters (Docket No. 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

Apex Apex Compressed Air Energy Storage

APS Arizona Public Service Company

Bonneville Bonneville Power Administration

CAISO California Independent System Operator

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 

EDP EDP Renewables North America

EPRI Electric Power Research Institute

EPSA, et al. 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

Grid Storage Consulting Grid Storage Consulting

Howard F. Illian Howard F. Illian

Idaho Power Idaho Power Company

Indicated ISOs/RTOs Independent Electricity System Operator/ISO New 

England/ New York Independent System 

Operator/PJM Interconnection/ Southwest Power Pool

IEEE-P1547 Working Group Institute of Electrical and Electronics Engineers

(IEEE) P1547 Standards Working Group

IEEE-PES IEEE Power and Energy Society Technical Council 

ITC, et al. International Transmission Company/Michigan 

Electric Transmission Company/ITC Great Plains/ITC 

Midwest

Manitoba Manitoba Hydro

Microgrids Resources 

Coalition

Microgrids Resources Coalition
Docket No. RM16-6-000 - 63 -

MISO Midcontinent Independent System Operator

MISO TOs Midcontinent Independent System Operator 

Transmission Owners

NARUC National Association of Regulatory Utility 

Commissioners

NRECA National Rural Electric Cooperative Association

NERC North American Electric Reliability Corporation

North American Generator 

Forum

North American Generator Forum

Nuclear Energy Institute Nuclear Energy Institute

PG&E Pacific Gas and Electric Company

Peak Reliability Peak Reliability

PJM Utilities Coalition PJM Utilities Coalition

Powerex Powerex Corp.

Public Interest Organizations Public Interest Organizations

Ralph D. Masiello Ralph D. Masiello

SDG&E San Diego Gas & Electric Company

Solar City Solar City Corporation

SoCal Edison Southern California Edison Company 

Southern Company Southern Company

Steel Producers Steel Producers

Tacoma Power Tacoma Power

TVA Tennessee Valley Authority

Tri-State Generation Tri-State Generation and Transmission Association

Union of Concerned Scientists Union of Concerned Scientists

WIRAB Western Interconnection Regional Advisory Body