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

Federal RegisterMar 6, 2018

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

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

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Final action.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is modifying the

pro forma

Large Generator Interconnection Agreement (LGIA) and

pro forma

Small Generator Interconnection Agreement (SGIA) to require newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. These changes are designed to address the potential reliability impact of the evolving generation resource mix, and to ensure that the relevant provisions of the

pro forma

LGIA and

pro forma

SGIA are just, reasonable, and not unduly discriminatory or preferential.

DATES:

This final action will become effective May 15, 2018.

FOR FURTHER INFORMATION CONTACT:

Jomo Richardson (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-6281,

Jomo.Richardson@ferc.gov.

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

Mark.Bennet@ferc.gov.

SUPPLEMENTARY INFORMATION:

Order No. 842

Final Action

(Issued February 15, 2018)

Table of Contents

Paragraph Nos.

I. Background

A. Frequency Response

B. Prior Commission Actions

C. Notice of Inquiry

D. Notice of Proposed Rulemaking

E. Notice of Request for Supplemental Comments

II. Discussion

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

1. NOPR Proposal

2. Comments

3. Commission Determination

B. Including Operating Requirements for Droop and Deadband in the

Pro Forma

LGIA and

Pro Forma

SGIA

1. NOPR Proposal

2. Comments

3. Commission Determination

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

1. NOPR Proposal

2. Comments

3. Commission Determination

D. Proposal Not To Mandate Headroom

106

1. NOPR Proposal

106

2. Comments

107

3. Commission Determination

109

E. Proposal Not To Mandate Compensation

111

1. NOPR Proposal

111

2. Comments

112

3. Commission Determination

119

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

126

1. NOPR Proposal

126

2. Comments

127

3. Commission Determination

131

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

135

1. NOPR Proposal

135

2. Comments

136

3. Commission Determination

142

H. Requests for Exemption or Special Accommodation

147

1. Combined Heat and Power Facilities

147

2. Electric Storage Resources

156

3. Distributed Energy Resources

189

4. Nuclear Generating Facilities

197

5. Wind Generating Facilities

203

6. Surplus Interconnection

207

7. Small Generating Facilities

210

8. Requests To Establish a Waiver Process and Consider Potential Impact on Load and New Technology

224

I. Regional Flexibility

231

1. NOPR Proposal

231

2. Comments

232

3. Commission Determination

233

J. Miscellaneous Comments

235

1. Uniform System of Accounts

235

2. Capability of Load To Provide Primary Frequency Response

237

3. Primary Frequency Response Obligations and Pools

239

K. Specific Revisions to the

Pro Forma

LGIA and

Pro Forma

SGIA

241

1. NOPR Proposal

241

2. Comments

242

3. Commission Determination

243

III. Compliance and Implementation

250

IV. Information Collection Statement

255

V. Regulatory Flexibility Act

262

VI. Environmental Analysis

266

VII. Document Availability

268

VIII. Effective Date and Congressional Notification

271

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

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

III. Appendix C: Uniform System of Accounts

162 FERC ¶ 61,128

United States of America

Federal Energy Regulatory Commission

Before Commissioners:

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

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

Order No. 842

Final Action

(Issued February 15, 2018)

1. In this final action, the Commission modifies the

pro forma

Large Generator Interconnection Agreement (LGIA) and the

pro forma

Small Generator Interconnection Agreement (SGIA), pursuant to its authority under section 206 of the Federal Power Act (FPA), to ensure that rates, terms and conditions of jurisdictional service remain just and reasonable and not unduly discriminatory or preferential.

The modifications require new large and small generating facilities, including both synchronous and non-synchronous, interconnecting through a LGIA or SGIA to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. The Commission also establishes certain uniform minimum operating requirements in the

pro forma

LGIA and

pro forma

SGIA, including maximum droop and deadband parameters and provisions for timely and sustained response.

16 U.S.C. 824e.

2. These requirements apply to newly interconnecting generation facilities that execute, or request the unexecuted filing of, an LGIA or SGIA on or after the effective date of this final action. These requirements also apply to existing large and small generating facilities that take any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date of this final action. These requirements do not apply to existing generating facilities,

a subset of combined heat and power (CHP) facilities, or generating facilities regulated by the Nuclear Regulatory Commission (NRC). In addition, the Commission does not impose a headroom requirement for new generating facilities, and does not mandate that new generating facilities receive compensation for complying with the primary frequency response requirements.

As discussed below in Section II.G, we will not impose primary frequency response requirements on existing generating facilities that do not submit new interconnection requests that result in an executed or unexecuted interconnection agreement at this time.

3. The modifications address the Commission's concerns that the existing

pro forma

LGIA contains limited primary frequency response requirements that apply only to synchronous generating facilities and do not account for recent technological advancements that now enable new non-synchronous generating facilities to have primary frequency response capabilities. Further, the Commission believes that it is unduly discriminatory or preferential to impose primary frequency response requirements only on new large generating facilities but not on new small generating facilities. The reforms adopted here impose comparable primary frequency response requirements on both new large and small generating facilities.

I. Background

A. Frequency Response

4. Reliable operation of an Interconnection

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.

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.

UFLS is designed to be activated in extreme conditions to stabilize the balance between generation and load. Under frequency protection schemes are drastic measures employed if system frequency falls below a specified value.

See Automatic Underfrequency Load Shedding and Load Shedding Plans Reliability Standards,

Notice of Proposed Rulemaking, 76 FR 66220 (Oct. 26, 2011), FERC Stats. & Regs. ¶ 32,682, at PP 4-10 (2011).

5. Mitigation of frequency deviations after the sudden loss of generation or load is driven by three primary factors: inertial response, primary frequency response, and secondary frequency response.

Primary frequency response actions begin within seconds after system frequency changes and are mostly provided by the automatic and autonomous actions (

i.e.,

outside of system operator control) of turbine-governors, while some response is provided by frequency responsive loads.

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,

during large disturbances, to remain above the first stage of UFLS set points within an Interconnection.

In the Notice of Inquiry issued in Docket No. RM16-6-000 on February 8, 2016, the Commission provided detailed discussion of how inertia, primary frequency response, and secondary frequency response interact to mitigate frequency deviations.

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

154 FERC ¶ 61,117, at PP 3-7 (2016) (NOI).

See also Use of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable Integration of Variable Renewable Generation,

Lawrence Berkeley National Laboratory, at 13-14 (Dec. 2010),

http://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf

(LBNL 2010 Report).

NOI, 154 FERC ¶ 61,117 at P 6. The Commission also noted that regulation service is different than primary frequency response because generating facilities that provide regulation respond to automatic generation control signals and regulation service is centrally coordinated by the system operator, whereas primary frequency response service, in contrast, is autonomous and is not centrally coordinated. Schedule 3 of the

pro forma

Open Access Transmission Tariff (OATT) bundles these different services together.

See id.

n.66.

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)).

6. Frequency response is a measure of an Interconnection's ability to arrest and stabilize frequency deviations following the sudden loss of generation or load, and is affected by the collective responses of generation and load throughout the Interconnection. When considered in aggregate, the primary frequency response provided by generators within an Interconnection has a significant impact on the overall frequency response. Reliability Standard BAL-003-1.1 defines the amount of frequency response needed from balancing authorities

to maintain Interconnection frequency within predefined bounds and includes requirements for the measurement and provision of frequency response.

While Reliability Standard BAL-003-1.1 establishes requirements for balancing authorities, it does not include any requirements applicable to individual generator owners or operators.

NERC's Glossary of Terms defines a balancing authority as “(t)he responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a balancing authority area, and supports Interconnection frequency in real time.” NERC's Glossary of Terms is available at:

http://www.nerc.com/files/glossary_of_terms.pdf.

Frequency Response and Frequency Bias Setting Reliability Standard,

Order No. 794, 146 FERC ¶ 61,024 (2014).

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).

7. Unless otherwise required by tariffs or interconnection agreements, generator owners and operators can independently decide whether to configure their generating facilities to provide primary frequency response.

The magnitude and duration of a generating facility's response to frequency deviations is generally determined by the settings of the facility's governor

(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 controls, unless properly configured, can override or nullify a generator's governor response and return the unit to operate at a scheduled pre-disturbance megawatt set-point.

In 2010, NERC conducted a survey of generator owners and operators and found that only approximately 30 percent of generating facilities in the Eastern Interconnection provided primary frequency response, and that only approximately 10 percent of generating facilities provided sustained primary frequency response.

This suggests that many generating facilities within the Eastern Interconnection disable or otherwise set their governors or plant-level controls such that they provide little to no primary frequency response.

See

NOI, 154 FERC ¶ 61,117 at PP 18-19.

A governor is an electronic or mechanical device that implements primary frequency response on a generating facility via a droop parameter. Droop refers to the variation in real power (MW) output due to variations in system frequency and is typically expressed as a percentage (

e.g.,

5 percent droop). Droop reflects the amount of frequency change from nominal (

e.g.,

5 percent of 60 Hz is 3 Hz) that is necessary to cause the main prime mover control mechanism of a generating facility to move from fully closed to fully open. A governor also has a deadband parameter which represents a minimum frequency deviation (

e.g.,

±0.036 Hz) from nominal system frequency (

i.e.,

60 Hz in North America) that must be exceeded in order for the generating facility to provide primary frequency response.

These controls are known as plant-level or outer-loop controls to distinguish them from more direct, lower-level control of the generator operations.

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

see

NOI, 154 FERC ¶ 61,117 at PP 49-50.

See

NERC,

Frequency Response Initiative Report: The Reliability Role of Frequency Response

(Oct. 2012),

http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf

(NERC Frequency Response Initiative Report) at 95. For the purposes of this final action, as indicated below in the revised

pro forma

language in Section K, sustained response refers to a generating facility responding to an abnormal frequency deviation outside of the deadband parameter, and holding (

i.e.,

not prematurely withdrawing) the response until system frequency returns to a value that is within the deadband.

However, as noted below, some commenters note that nuclear generating facilities are restricted by their NRC operating licenses regarding the provision of primary frequency response.

8. Declining frequency response performance has been an industry concern for many years. NERC, in conjunction with the Electric Power Research Institute (EPRI), initiated its first examination of declining frequency response and governor response in 1991.

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,

there has been a decline in the frequency response performance of the Western and Eastern Interconnections from historic values.

NERC Frequency Response Initiative Report at 22.

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.

NOI, 154 FERC ¶ 61,117 at P 20.

B. Prior Commission Actions

9. In Order Nos. 2003

and 2006,

the Commission adopted standard procedures for the interconnection of large and small generating facilities, including the development of standardized

pro forma

generator interconnection agreements and procedures. The Commission required public utility transmission providers

to file revised OATTs containing these standardized provisions, and use the LGIA and SGIA to provide non-discriminatory interconnection service to Large Generators (

i.e.,

generating facilities having a capacity of more than 20 MW) and Small Generators (

i.e.,

generators having a capacity of no more than 20 MW). The

pro forma

LGIA and

pro forma

SGIA have since been revised through various subsequent proceedings.

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

FERC,

475 F.3d 1277 (D.C. Cir. 2007),

cert. denied,

552 U.S. 1230 (2008).

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).

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.

E.g., Small Generator Interconnection Agreements and Procedures,

Order No. 792, 145 FERC ¶ 61,159 (2013),

clarifying,

Order No. 792-A, 146 FERC ¶ 61,214 (2014);

Reactive Power Requirements for Non-Synchronous Generation,

Order No. 827, FERC Stats. & Regs. ¶ 31,385 (2016) (cross-referenced at 155 FERC ¶ 61,277) (2016);

Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities,

Order No. 828, 156 FERC ¶ 61,062 (2016).

C. Notice of Inquiry

10. On February 18, 2016, the Commission issued the NOI to explore issues regarding essential reliability services and the evolving Bulk-Power System.

In particular, the Commission asked a broad range of questions on the need for reform of its requirements regarding the provision of and compensation for primary frequency response. The Commission explained that there is a significant risk that, as conventional synchronous generating facilities retire or are displaced by increased numbers of variable energy resources (VERs),

which typically do not contribute to system inertia

or have primary frequency response capabilities, the net amount of frequency responsive generation online will be reduced.

NOI, 81 FR 9182 (Feb. 24, 2016), 154 FERC ¶ 61,117.

The term VER is defined as a device for the production of electricity that is characterized by an energy source that: (1) Is renewable; (2) cannot be stored by the facility owner or operator; and (3) has variability that is beyond the control of the facility owner or operator.

See, e.g., Integration of Variable Energy Resources,

Order No. 764, FERC Stats. & Regs. ¶ 31,331 at P 210,

order on reh'g and clarification,

Order No. 764-A, 141 FERC ¶ 61,232 (2012),

order on clarification and reh'g,

Order No. 764-B, 144 FERC ¶ 61,222 (2013).

Inertial response, or system inertia, involves the release or absorption of kinetic energy by the rotating masses of online generation and load within an Interconnection, and is the result of the coupling between the rotating masses of synchronous generation and load and the electric system.

See

NOI, 154 FERC ¶ 61,117 at PP 3-7 for a more detailed discussion of how inertia, primary frequency response, and secondary frequency response interact to mitigate frequency deviations.

NOI, 154 FERC ¶ 61,117 at P 12.

11. In the NOI, the Commission also explained that these developments and their potential impacts could challenge system operators in maintaining system frequency within acceptable bounds following system disturbances.

Further, the Commission explained that Reliability Standard BAL-003-1.1 and the

pro forma

LGIA and

pro forma

SGIA do not specifically address a generator's ability to provide frequency response.

The Commission noted, however, that while in previous years many non-synchronous 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.

Id.

P 14.

Id.

P 41.

Non-synchronous generating facilities are “connected to the bulk power system through power electronics, but do not produce power at system frequency (60 Hz).” They “do not operate in the same way as traditional generators and respond differently to network disturbances.”

PJM Interconnection, L.L.C.,

151 FERC ¶ 61,097, at P 1 n.3 (2015) (citing

Interconnection for Wind Energy,

Order No. 661, FERC Stats. & Regs. ¶ 31,198, at P 3 n.4 (2005)). Wind and solar photovoltaic generating facilities as well as electric storage resources are examples of non-synchronous generating facilities.

NOI, 154 FERC ¶ 61,117 at P 43.

12. Accordingly, the Commission requested comments on three main sets of issues. First, the Commission sought comment on whether amendments to the

pro forma

LGIA and

pro forma

SGIA are warranted to require all new generating facilities, both synchronous and non-synchronous, to have primary frequency response capabilities as a precondition of interconnection.

Second, the Commission sought comment on the performance of existing generating facilities and whether primary frequency response requirements for these facilities are warranted.

Finally, the Commission sought comment on compensation for primary frequency response.

Id.

PP 2 and 44-45.

Id.

PP 2, 46, and 52.

Id.

PP 2, 53-54.

D. Notice of Proposed Rulemaking

13. On November 17, 2016, the Commission issued a Notice of Proposed Rulemaking that proposed to revise the

pro forma

LGIA and the

pro forma

SGIA to require all newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install and enable primary frequency response capability as a condition of interconnection.

The Commission also proposed to establish certain operating requirements in the

pro forma

LGIA and

pro forma

SGIA, including maximum droop and deadband parameters, and provisions for timely and sustained response.

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

Notice of Proposed Rulemaking, 81 FR 85176 (Nov. 25, 2016), 157 FERC ¶ 61,122 (2016) (NOPR).

14. The Commission sought comment on the proposed: (1) Requirements for new large and small generating facilities to install, maintain, and operate a governor or equivalent controls; (2) requirements for droop and deadband settings of 5 percent and ±0.036 Hz, respectively; (3) requirements for timely and sustained response, and in particular whether the proposed requirements will be sufficient to prevent plant-level controls from inhibiting primary frequency response; (4) requirement for droop parameters to be based on nameplate capability with a linear operating range of 59 to 61 Hz; and (5) exemptions for new nuclear units. The Commission also sought comment on its proposal to not impose a generic headroom requirement or mandate compensation related to the proposed reforms.

15. Twenty-eight entities submitted comments in response to the NOPR and are listed in Appendix A to this final action.

E. Notice of Request for Supplemental Comments

16. On August 18, 2017, the Commission issued a Notice of Request for Supplemental Comments (Supplemental Notice) to augment the record on the potential impacts of the NOPR proposals on electric storage resources

and small generating facilities.

In particular, the Commission stated that the NOPR did not contain any special consideration or provisions for electric storage resources, and that some commenters raised concerns that, by failing to address electric storage resources' unique technical attributes, the proposed requirements could pose an unduly discriminatory burden on electric storage resources.

In response to commenters' concerns, the Commission asked several questions to augment the record on possible impacts to electric storage facilities.

For the purposes of this final action, we define an electric storage resource as a resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid. This definition is also used in a concurrently-issued Final Rule, published elsewhere in this issue of the

Federal Register

, concerning electric storage resources entitled

Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators,

162 FERC ¶ 61,127 (2018).

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

Notice of Request for Supplemental Comments, 82 FR 40081 (Aug. 24, 2017), 160 FERC ¶ 61,011 (2017).

Id.

P 4.

Id.

P 6.

17. In addition, the Commission stated that the NOPR proposed that small generating facilities be subject to new primary frequency response requirements in the

pro forma

SGIA, and that some commenters raised concerns that small generating facilities could face disproportionate costs to install primary frequency response capability,

while other commenters requested that the Commission consider adopting a size limitation.

In response to commenters' concerns, the Commission asked several questions to augment the record on small generating facilities.

Id.

P 8.

Id.

P 9.

Id.

P 10.

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

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

II. Discussion

19. For the reasons discussed below, the Commission adopts the NOPR proposal and will require newly interconnecting large and small generating facilities that interconnect pursuant to the

pro forma

LGIA or

pro forma

SGIA, to install, maintain, and operate a functioning governor or equivalent controls capable of providing primary frequency response. The reforms adopted here build upon Order Nos. 2003 and 2006 by accounting for the effect upon primary frequency response from the ongoing changes to the nation's generation resource mix, including significant retirements of conventional generating facilities and an increasing proportion of VERs interconnecting to the Bulk-Power System.

Another important consideration is that the frequency response performance of the Eastern and Western Interconnections, while currently adequate, has significantly declined from historic values.

NERC has found that “increasing levels of non-synchronous resources installed without controls that enable frequency response capability, coupled with retirement of conventional generating facilities that have traditionally provided primary frequency response, have contributed to the decline in primary frequency response.”

Finally, the record in this proceeding indicates that VER equipment manufacturers have made significant technological advancements in developing primary frequency response capability for VERs, and that the costs of this capability have declined over time.

For all of these reasons, we find that the

pro forma

LGIA and

pro forma

SGIA are no longer just and reasonable, and are unduly discriminatory or preferential, and thus need to be revised to ensure that all newly interconnecting large and small generating facilities have primary frequency response capability as a condition of interconnection.

Section 215(a)(1) of the FPA, 16 U.S.C. 824o(a)(1) (2012) defines “Bulk-Power System” as those “facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) [and] electric energy from generating facilities needed to maintain transmission system reliability.” The term does not include facilities used in the local distribution of electric energy.

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

Order No. 693, FERC Stats. & Regs. ¶ 31,242, at P 76 (cross-referenced at 118 FERC ¶ 61,218),

order on reh'g,

Order No. 693-A, 120 FERC ¶ 61,053 (2007).

See

NOPR, 157 FERC ¶ 61,122 at P 36 (citing NERC Frequency Response Initiative Industry Advisory—Generator Governor Frequency Response, at slide 10 (Apr. 2015),

http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. See also

NERC Frequency Response Initiative Report at 22, and LBNL 2010 Report at xiv-xv).

NERC Comments at 5. NERC's Essential Reliability Services Task Force has determined that primary frequency response is an “essential reliability service.” Essential reliability services are referred to as elemental reliability building blocks from resources (generation and load) that are necessary to maintain the reliability of the Bulk-Power System.

See

Essential Reliability Services Task Force Scope Document, at 1 (Apr. 2014),

http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.

NOPR, 157 FERC ¶ 61,122 at PP 28, 36.

16 U.S.C. 824e. The Commission routinely evaluates the effectiveness of its regulations and policies in light of changing industry conditions to determine if changes in these conditions and policies are necessary.

See, e.g.,

Order No. 764, FERC Stats. & Regs. ¶ 31,331.

20. We find that the current requirements for governor controls in the

pro forma

LGIA do not reflect NERC's currently recommended operating practices or recent advances in technology for non-synchronous generating facilities, as discussed below.

21. First, Article 9.6.2.1 of the

pro forma

LGIA does not address the settings of governors or equivalent controls (

i.e.,

deadband and droop), nor does Article 9.6.2.1 address plant-level controls, which if not properly coordinated on a generating facility, can lead to the premature withdrawal of primary frequency response during disturbances. Furthermore, the substantial body of knowledge regarding the operation of generator governors and plant control systems amassed by NERC and industry stakeholders since the

pro forma

LGIA was promulgated under Order No. 2003 raises concerns that Article 9.6.2.1 of the

pro forma

LGIA allows too much discretion for generator owners and operators. For example, in 2012, NERC found that a number of generators implemented deadband settings that were so wide as to effectively disable themselves from providing primary frequency response, and also that many generators provide frequency response in the wrong direction during a disturbance.

In addition, in 2015, NERC observed that: (1) For many conventional steam plants, deadband settings exceeded ±0.036 Hz; (2) several generating facilities failed to sustain primary frequency response; and (3) the vast majority of the gas turbine fleet was not frequency responsive.

NERC Frequency Response Initiative Report at 92, 96-97.

NOI, 154 FERC ¶ 61,117 at P 50 (citing NERC Generator Governor Frequency Response Advisory—Webinar Questions and Answers at 1 (April 2015),

http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_QandA_April_2015.pdf.).

22. Second, existing Article 9.6.2.1 of the

pro forma

LGIA states that “speed governors,” if installed, must be operated in automatic mode. However, instead of utilizing traditional speed governors to implement primary frequency response capability, many new non-synchronous generating facilities interconnecting to the grid, such as wind, solar, and electric storage resources, utilize enhanced inverters and other plant control technology that can be designed to include primary frequency response capability.

We find that due to these recent technological advancements that allow new large non-synchronous generating facilities to install primary frequency response capability at low cost, as well as the expected overall increase of the proportion of the resource mix that are non-synchronous generating facilities, it is unduly discriminatory and preferential to only require synchronous generators to provide primary frequency response. The references to “speed governors” in existing Article 9.6.2.1 of the

pro forma

LGIA, which are only applicable to large synchronous generating facilities, are outdated and should be expanded to include both synchronous and non-synchronous generators.

See

Electric Power Research Institute,

Recommended Settings for Voltage and Frequency Ride-Through of Distributed Energy Resources

at 27(May 2015),

http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002006203. See also

National Renewable Energy Labs (NREL),

Advanced Grid-Friendly Controls Demonstration Project for Utility-Scale PV Power Plants,

at 1-2 (Jan. 2016),

http://www.nrel.gov/docs/fy16osti/65368.pdf.

23. Investigation by various NERC task forces and subcommittees has led to a voluntary NERC Primary Frequency Control Guideline that includes recommended droop and deadband settings for generating facilities within all three U.S. Interconnections.

However, as noted in the NOPR, the

pro forma

LGIA and

pro forma

SGIA do not currently reflect these updated recommended practices by NERC for governor and plant control system settings of generating facilities.

See

NERC's Primary Frequency Control Guideline.

NOPR, 157 FERC ¶ 61,122 at P 39.

24. We also find that revisions to the

pro forma

LGIA and

pro forma

SGIA are necessary to provide for the continued reliable operation of the Bulk-Power System by addressing the potential adverse impacts on primary frequency response of the nation's evolving generation resource mix described in the NOI.

As noted in the NOPR,

NERC's Essential Reliability Services Task Force concluded that primary frequency response capability should be required of all new generating facilities.

However, the

pro forma

LGIA and the

pro forma

SGIA do not currently require generating facilities to install such capability.

NOI, 154 FERC ¶ 61,117 at PP 13-17 (citing to the Essential Reliability Services Task Force Measures Report at iv).

NOPR, 157 FERC ¶ 61,122 at P 15.

25. Further, the limited references to primary frequency response in the Commission's requirements apply only to large generating facilities. Based on the absence of a technical or economic basis for the different requirements imposed on small and large generating facilities, and the significant technological advancements that manufacturers have made in developing primary frequency response capability for VERs, we find that the absence of any similar provisions in the current

pro forma

SGIA is unduly discriminatory or preferential.

26. The Commission has previously acted under FPA section 206 to remove inconsistencies between the

pro forma

LGIA and

pro forma

SGIA when there is no economic or technical basis for treating large and small generating facilities differently.

As discussed more fully below in Section II.H.7, the record developed in this proceeding indicates that small generating facilities are capable of installing and enabling governors or equivalent controls at a low cost and in a manner comparable to large generating facilities.

Given these low-cost technological advances, we do not anticipate that these additional requirements added to the

pro forma

SGIA will present a barrier to entry for small generating facilities. Thus, in light of the need for additional primary frequency response capability and an increasingly large market penetration of small generating facilities, we believe that there is a need to add these requirements to the

pro forma

SGIA to help ensure adequate primary frequency response capability.

See

Order No. 828, 156 FERC ¶ 61,062 (revising the

pro forma

SGIA such that small generating facilities have frequency and voltage ride through requirements comparable to large generating facilities).

See, e.g.,

IEEE-P1547 Working Group NOI Comments at 1, 5, and 7; ISO-RTO Council Supplemental Comments at 7; SoCal Edison Supplemental Comments at 3; WIRAB Supplemental Comments at 7. Moreover, the Commission notes that other commenters stated costs of installing primary frequency response capability are generally low, but did not differentiate between small and large generating facilities.

See, e.g.,

APPA,

et al.

Comments at 6; California Cities Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at 3-5; SoCal Edison Comments at 2.

27. Accordingly, we find that revising the

pro forma

LGIA and

pro forma

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

NOPR, 157 FERC ¶ 61,122 at P 43.

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

1. NOPR Proposal

28. In the NOPR, the Commission proposed to revise the

pro forma

LGIA and

pro forma

SGIA to include requirements for new large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection.

In particular, the Commission explained that the proposed revisions would require new large and small generating facilities to install, maintain, and operate a functioning governor or equivalent controls, which the Commission proposed to define as the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the generating facility's real power output in accordance with the proposed maximum droop and deadband parameters and in the direction needed to correct frequency deviations.

Id.

P 44.

Id.

P 47.

2. Comments

29. The proposed requirement for new generating facilities to install the necessary equipment for primary frequency response capability as a condition of interconnection received broad support from commenters.

For example, APPA et al. state that requiring newly interconnecting generating facilities to install governors or equivalent control devices is a relatively low-cost way to prevent the erosion of the Interconnections' collective frequency response capability as the generation resource mix evolves.

APPA et al. state that primary frequency response capability should be a standard feature and part of the “rules of the road” for all new generating facilities, similar to how all new cars come equipped with anti-lock brakes.

Bonneville asserts that the trend of declining frequency response capability will continue with a changing generation resource mix (namely, the integration of large amounts of VERs), unless provisions are put in place to ensure that adequate primary frequency response capability is available in the future.

As a result, Bonneville believes that it is necessary to require newly interconnecting generating facilities to have primary frequency response capability.

EEI states that now that the technology is available and economical for non-synchronous generation facilities, it supports the proposed requirement for these facilities to install the equipment needed to provide primary frequency response.

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

APPA et al. Comments at 6.

Id.

Bonneville Comments at 2.

Id.

EEI Comments at 2.

30. NERC states that it has determined that increasing levels of non-synchronous generating facilities installed without controls that enable frequency response capability, coupled with retirement of conventional generating facilities that have traditionally provided primary frequency response, has contributed to the decline in primary frequency response.

NERC further states that a changing generation resource mix will further alter the dispatch of generating facilities, potentially resulting in operating conditions where frequency response capability could be diminished unless a sufficient amount of frequency responsive capacity is included in the dispatch.

NERC asserts that the NOPR's proposed revisions would apply measurable, clear requirements to newly interconnecting synchronous and non-synchronous generating facilities.

Tri-State comments that primary frequency response requirements for all generating facilities are necessary to address the

decline in frequency response and are in the best interest of industry.

ISO-RTO Council adds that a number of Regional Transmission Operators (RTOs) and Independent System Operators (ISOs) have, for several years, had similar requirements to those proposed in the NOPR, and as a result, the Commission's proposal does not create significant burdens as it merely extends these existing “best practices” nationwide.

SVP states that the NOPR proposals should not create a major hardship in terms of costs or other burdens related to installing frequency response capability.

SoCal Edison states that there is neither a technological nor an economic reason not to require primary frequency response capability of small and/or non-synchronous generating facilities.

NERC Comments at 5.

Id.

Tri-State Supplemental Comments at 3.

ISO-RTO Council Comments at 2.

SVP Comments at 2.

SoCal Edison Comments at 2.

31. On the other hand, some commenters do not support a requirement for new generating facilities to install, maintain, and operate primary frequency response capability as a condition of interconnection.

For example, API states that primary frequency response operation may not be required from

all

generating facilities since it is possible for balancing authorities to have a sufficient number of existing generating facilities with primary frequency response capability.

APS argues that more time is needed to measure and understand the effect of Reliability Standard BAL-003-1.1 on frequency response before mandating primary frequency response capability.

Chelan County adds that while it may be true that it is more cost effective to install primary frequency response capability during a generating facility's initial construction (as opposed to retrofitting an already-existing generating facility) and the costs of doing so may be nominal, the Commission should not require generating facilities to provide primary frequency response as a condition of interconnection.

NRECA asserts that the proposal could have adverse impacts on deployment of non-traditional generation sources without conferring reliability benefits that warrant such risks.

Therefore, NRECA asserts that if the Commission proceeds to require primary frequency response capability as a condition of interconnection, then the Commission should provide for flexibility to balance the reliability needs with possible costs and the desire to encourage new generating facilities by: (1) Considering a size threshold, whereby new generators under a certain size are not required to have primary frequency response capability; (2) establishing penetration level thresholds for primary frequency response requirements; or (3) allowing for a waiver process.

See, e.g.,

API Comments at 2; APS Supplemental Comments at 12; Chelan County Comments at 1; NRECA Comments at 2; Public Interest Organizations Comments at 4; R Street Comments at 2; SDG&E Comments at 1; Sunflower and Mid-Kansas Comments at 2.

API Comments at 4.

APS Supplemental Comments at 12.

Chelan County Comments at 1.

NRECA Comments at 6.

Id.

at 8-9.

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

See, e.g.,

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

3. Commission Determination

33. We adopt the NOPR proposal to revise the

pro forma

LGIA and

pro forma

34. We adopt the NOPR proposal to define “functioning governor or equivalent controls” as the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the generating facility's real power output in accordance with maximum droop and deadband parameters and in the direction needed to correct frequency deviations.

NOPR, 157 FERC ¶ 61,122 at P 47.

35. The proposal to require new generating facilities to install equipment capable of providing primary frequency response received broad support from commenters.

We find compelling these commenters' observations that requiring newly interconnecting generating facilities to install governors or equivalent control devices is a low cost way to address the erosion of the Interconnections' collective frequency response capability as the generation resource mix evolves. As assessments by NERC, the Essential Reliability Services Task Force, and others confirm, ongoing changes to the generation resource mix are altering the composition and dispatch of generating facilities across the daily and seasonal demand spectrum. The resulting operating conditions have affected frequency response capability and the amount of frequency responsive capacity online at any given moment. We believe that the revisions to the

pro forma

LGIA and

pro forma

SGIA adopted here will address this problem by providing that the future generation resource mix has frequency responsive capacity available for dispatch by system operators to maintain system reliability.

36. We acknowledge that some commenters do not support a requirement for all newly interconnecting generating facilities to install, maintain, and operate governors or equivalent controls.

Some of these commenters only support a requirement for newly interconnecting generating facilities to install primary frequency response capability as a condition of interconnection, but do not support including the proposed operating requirements in the

pro forma

LGIA and

pro forma

SGIA.

These commenters either advocate for regional flexibility (

i.e.,

allowing the transmission provider or the balancing authority to establish regional requirements) or request exemption or special accommodation of the requirements for particular technology types (

e.g.,

electric storage resources and CHP facilities). Comments that request regional flexibility for individual transmission providers or balancing authorities to establish operating requirements are addressed below in Section II.B. Comments that request a special accommodation for certain types of generating facilities, including but not limited to electric storage and CHP facilities are addressed below in Section II.H.

See, e.g.,

AES Companies Comments at 6; EEI Comments at 8; MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel Comments at 7.

37. Rather than uniform requirements in the

pro forma

LGIA and

pro forma

SGIA, some commenters prefer market-based or cost-based compensation mechanisms to ensure sufficient primary frequency response capability, and urge the Commission to consider the economic impacts of the proposed requirements on load. Comments related to compensation are addressed below in Section II.E. Comments related to the impacts on load are addressed below in Section II.H.8.

38. Finally, some commenters assert that the Commission should: (1) Consider a size threshold; (2) establish penetration level thresholds for primary frequency response requirements; (3) allow for a waiver process; and (4) establish primary frequency response pools. These comments are addressed below in Sections II.H and II.J.

39. Accordingly, as a result of this final action, new large and small generating facilities, will be required to install, maintain, and operate a functioning governor or equivalent controls with certain exemptions or accommodations for nuclear generating facilities, electric storage facilities, and combined heat and power facilities as discussed below.

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

1. NOPR Proposal

40. In the NOPR, the Commission proposed to include

minimum

operating requirements for droop and deadband for governors or equivalent controls.

In particular, the Commission proposed to require new generating facilities to install, maintain, and operate governor or equivalent controls with the ability to operate with a maximum 5 percent droop and ±0.036 Hz deadband parameter, consistent with NERC's recommended guidance.

NOPR, 157 FERC ¶ 61,122 at P 48.

Id.

41. The Commission also proposed to require the droop parameter to be based on the nameplate capability of the generating facility and linear in operating range between 59 and 61 Hz.

The Commission explained that this provision is reasonable because it would allow for new generating facilities that remain connected during frequency deviations (and have operating capability,

e.g.,

headroom;

or floor-room

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

Id.

P 50.

For the purposes of this final action, headroom refers to the difference between the current operating point of a generating facility and its maximum operating capability, and represents the potential amount of additional energy that can be provided by the generating facility in real-time.

See

NOPR, 157 FERC ¶ 61,122 at n.27.

For the purposes of this final action, floor-room refers to the difference between the current operating point of a generating facility and its minimum operating capability, and represents the potential amount of additional energy that can be withdrawn by the generating facility in real-time. Stated differently, a generating facility with floor-room will have the capability to reduce its MW output in response to a frequency deviation.

See

NOPR, 157 FERC ¶ 61,122 at P 50.

42. The Commission also proposed that if the interconnection customer

disables its governor or equivalent controls for any reason, it shall notify the transmission provider's system operator, or its designated representative, and shall make Reasonable Efforts

to return the governor or equivalent controls to service as soon as practicable.

In addition, the Commission proposed that the interconnection customer must provide the status and settings of the governor or equivalent controls to the transmission provider upon request.

The phrase “interconnection customer” shall have the meaning given it in the definitional sections of the

pro forma

LGIA and

pro forma

SGIA.

The

pro forma

LGIA and

pro forma

SGIA state that reasonable efforts “shall mean, with respect to an action required to be attempted or taken by a Party under the Standard Large Generator Interconnection Agreement, efforts that are timely and consistent with Good Utility Practice and are otherwise substantially equivalent to those a Party would use to protect its own interests.”

Pro forma

LGIA Art. 1 (Definitions).

Pro forma

SGIA Attachment 1 (Glossary of Terms).

NOPR, 157 FERC ¶ 61,122 at P 52, proposed Section 9.6.4 of the

pro forma

LGIA and Section 1.8.4 of the

pro forma

SGIA.

Proposed Section 9.6.4.1 of the

pro forma

LGIA and 1.8.4.1 of the

pro forma

SGIA.

2. Comments

a. Whether To Include Operating Requirements for Primary Frequency Response in the Pro Forma LGIA and Pro Forma SGIA

43. Several commenters support the NOPR proposal to include operating requirements (

i.e.,

droop, deadband, and timely and sustained response) in the

pro forma

LGIA and

pro forma

SGIA,

while other commenters either object to specific, uniform governor control setting requirements, prefer a market-based approach, or seek limited or full exemptions based on unique operating characteristics.

Several commenters agree that a maximum 5 percent droop and ±0.036 Hz deadband for newly interconnecting generating facilities is technically feasible.

APPA et al., AWEA, Bonneville, California Cities, Competitive Suppliers, First Solar, Idaho Power (for generating facilities larger than 10 MW), ISO-RTO Council, NERC, PG&E, SVP, and WIRAB state that they either support or do not object to the inclusion of the proposed operating requirements in the

pro forma

LGIA and

pro forma

SGIA.

AES Companies; API; EEI; ELCON; ESA; MISO TOs; R St. Institute; SoCal Edison; NRECA; and Xcel.

See, e.g.,

AWEA Comments at 4; Bonneville Comments at 3; ISO-RTO Council Comments at 4-5; NERC Comments at 6; NRECA Comments at 2-3.

44. Among those supporting the proposed operating requirements, NERC asserts that the “proposed minimum operating conditions should help ensure that frequency response capability is installed as well as available and ready to respond, regardless of the mix of resources in the dispatch,” and “should lead to tighter control and frequency stability.”

ISO-RTO Council states that, absent unique local requirements such as lower and more responsive droop values in some remote areas of the grid, NERC's guidelines provide a sound baseline and are consistent with current requirements in some regions, including ISO New England, Inc. (ISO-NE), New York Independent System Operator, Inc. (NYISO), and PJM Interconnection, L.L.C. (PJM).

While it supports the NOPR proposal, WIRAB also notes the relevance of regional differences, and recommends that the Commission ensure that NERC and the Regional Entities continue to monitor frequency response capability in each region and develop best practices that highlight regional differences in the electricity resource mix and the need for primary frequency response.

Further, WIRAB suggests that NERC and the Regional Entities periodically reevaluate the required maximum droop and deadband settings.

100

NERC Comments at 5.

ISO-RTO Council Comments at 4-5.

WIRAB Comments at 3.

100

Id.

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

101

NRECA Comments at 2.

46. Some commenters express concern that uniform, specific governor control settings in the

pro forma

LGIA and

pro forma

SGIA may fail to account for regional differences and unique operating characteristics of certain generating facilities and resource types, and could add unnecessary costs. These commenters assert that the

pro forma

LGIA and

pro forma

SGIA should only obligate new generating facilities to install and maintain governors or equivalent controls, and not establish specific operating requirements that

must be used.

102

While supporting revisions to the

pro forma

LGIA and

pro forma

SGIA to obligate newly interconnecting generators to install governors or equivalent controls to provide primary frequency response, EEI opposes including operating requirements. EEI asserts that tariffs, rather than interconnection agreements, are a more effective means of establishing operating requirements, since there are significant differences among generating facility types and interconnections as well as cost considerations, and because interconnection agreements “do not provide the necessary controls to ensure compliance.”

103

EEI further states that operating requirements for new generating facilities are better determined by individual balancing authorities on an as-needed basis or through voluntary guidance from NERC.

104

EEI also requests that, rather than mandating specific operating requirements, the Commission conduct a series of regional technical conferences to “allow for a more holistic evaluation of all [essential reliability services]”

105

and provides details regarding the proposed focus and scope of such conferences.

106

102

See, e.g.,

AES Companies Comments at 6; EEI Comments at 8; MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel Comments at 7.

103

EEI Comments at 9, 11.

104

Id.

at 11-12.

105

Id.

at 12.

106

Id.

at 4, n.5.

47. MISO TOs object to “rigid standards that do not allow for changes in technology or in the applicable NERC standards or guidelines.”

107

Rather, MISO TOs contend that flexibility can be achieved through a generic requirement for appropriate settings consistent with good utility practices. MISO TOs believe this approach would minimize the need to modify the

pro forma

LGIA and

pro forma

SGIA and expedite the implementation of needed changes for primary frequency response.

108

AES Companies also oppose the proposed operating requirement for droop and deadband settings, and believe that this requirement should not be a uniform standard that is applied to all new generating facilities.

109

AES Companies assert that NERC provides a primary frequency control guideline rather than a Reliability Standard because the guideline may need to differ based on the type of generating facility.

110

107

MISO TOs Comments at 9.

108

Id.

at 11.

109

AES Companies Comments at 6.

110

Id.

48. While it generally agrees with the specific proposed droop and deadband settings, NRECA supports allowing flexibility in the requirements “to the extent new generating facilities have differing operating, technical or other characteristics which make compliance with these standardized requirements unduly burdensome or impossible.”

111

APS, MISO TOs, SoCal Edison, Xcel and NYTOs add that the Commission should defer to balancing authorities or transmission providers to establish specified operating requirements for governor or equivalent controls.

112

Xcel states that regional system differences could justify different primary frequency response standards.

113

While the Commission should require that primary frequency response capabilities be installed on all new facilities, any final action should be flexible enough to allow for regional differences.

114

111

NRECA Comments at 3.

112

APS Supplemental Comments at 5-6; MISO TOs Comments at 2; SoCal Edison Comments at 3; Xcel Comments at 7; NYTOs Supplemental Comments at 3-4.

113

Xcel Comments at 7.

114

Id.

49. Some commenters that oppose including the proposed operating requirements in the

pro forma

LGIA and

pro forma

SGIA state that market-based procurement of primary frequency response service (in regions of the country with organized markets) would better ensure that the right amount and quality of primary frequency response service is available at a lower cost to consumers.

115

Also, NRECA is concerned that the costs of the Commission's proposal could outweigh the reliability benefits and delay the development of the types of alternative technologies supported by the Commission.

116

115

See, e.g.,

AES Companies Comments at 9; API Comments at 4; ELCON Supplemental Comments at 12, in support of R St Institute's Comments; Public Interest Organizations Comments at 2; R St Institute Comments at 4; SDG&E Comments at 5-6.

116

NRECA Comments at 3.

b. Whether To Incorporate a Reference to a Future NERC Reliability Standard in the Pro Forma LGIA and Pro Forma SGIA

50. ISO-RTO Council asserts that revisions to the

pro forma

LGIA and

pro forma

SGIA should account for the possibility that NERC may develop a reliability standard with more stringent specific droop and deadband parameters, and as a result, the

pro forma

LGIA and

pro forma

SGIA should be written to allow for this eventuality without a need to amend the

pro forma

agreements.

117

ISO-RTO Council asserts that a possible future reliability standard with more stringent droop and deadband parameters should supersede the

pro forma

interconnection requirements.

118

Specifically, ISO-RTO Council recommends that the Commission require new generating facilities to comply with the more stringent of the following requirements: (1) A maximum 5 percent droop and ±0.036 Hz deadband parameter and a droop parameter to be based on the nameplate capability of the unit and linear in operating range between 59 to 61 Hz as proposed in the NOPR; or (2) an approved NERC Reliability Standard providing for more stringent parameters.

119

117

ISO-RTO Council Comments at 5.

118

Id.

119

Id.

at 5-6.

c. Requirements for Droop and Deadband

51. Some commenters question the NOPR proposal to base a generating facility's droop parameter on its nameplate capacity. EEI asserts that the proposal is problematic because the mandated response from generating facilities is based on MW and Reactive Curves, and not mega volt-ampere (MVA) nameplate ratings.

120

Similarly, ISO-RTO Council urges the Commission to consider that nameplate capability of a unit may not be consistent with the rated capacity of a generating facility for purposes of obtaining interconnection service or for participation in an organized market.

121

In addition, ISO-RTO Council believes that the Commission should clarify that efficiency improvements to a resource increasing its output (

e.g.,

duct burners that allow for increased output from a steam generator) should be considered when calculating a generating unit's droop parameter.

122

120

EEI Comments at 14.

121

ISO-RTO Council Comments at 6.

122

Id.

52. While it supports the NOPR proposal for the droop parameter to be linear in the operating range between 59 to 61 Hz, WIRAB recommends that the Commission allow generating facilities to use faster, non-linear settings over the proposed linear operating range.

123

WIRAB explains that a linear setting over the proposed operating range will result in a 5 percent droop across the entire range, but that non-linear droop parameters may lead to faster responses.

124

More specifically, WIRAB explains that rather than a linear 5 percent droop across the entire operating range, “nonlinear or

piecewise droop parameters,” such as a 5 percent droop between 60.036 and 61.000 Hz and a 3 percent droop between 59.964 and 59.000 Hz, “may help to restore system frequency to normal faster and improve system resiliency.”

125

On the other hand, EEI recommends that the Commission not include in the

pro forma

interconnection agreements the proposed requirement for the droop characteristic to be linear in the operating between 59 to 61 Hz.

126

In support of its position, EEI contends that: (1) The proposed frequency range includes the deadband, where governors do not operate; and (2) actual generating facility response to frequency deviations may not be linear.

127

123

WIRAB Comments at 7.

124

Id.

125

Id.

126

EEI Comments at 14-15, 17.

127

Id.

at 14.

53. Regarding deadband parameters, NERC suggests that the Commission consider replacing the proposed requirements with the NERC Primary Frequency Control Guideline's recommendation

128

concerning the implementation of the deadband within the droop curve.

129

Specifically, NERC recommends that deadbands should be implemented without a step to the droop curve,

i.e.,

once frequency deviates outside the deadband, then change in the generating facility's MW output starts from zero and then proportionally increases with the input signal (

i.e.,

frequency).

130

128

NERC Primary Frequency Control Guideline at 6.

129

NERC Comments at 6.

130

Id.

d. Requirements for the Status and Settings of the Governor or Equivalent Controls

54. NERC recommends that the Commission require the interconnection customer to provide the status and settings of the governor or equivalent controls and plant level controls not only to the transmission provider (or its designated system operator) but also to the relevant balancing authority upon request, and notify the balancing authority when it needs to take the governor or equivalent controls and plant level controls out of service.

131

In support, NERC asserts that, as the entity with a compliance obligation under Reliability Standard BAL-003-1.1 for providing frequency response, the balancing authority needs to know the status and settings of the governor or equivalent controls and plant level controls in order to assess whether there is an appropriate amount of frequency response available.

132

NERC explains that providing this information to the balancing authority would support efforts to help ensure sufficient frequency response and compliance with Reliability Standard BAL-003-1.1.

133

131

Id.

132

Id.

at 6-7.

133

Id.

55. Regarding the disabling of an interconnection customer's governor or equivalent controls, Bonneville asserts that the proposed revisions to the

pro forma

LGIA and

pro forma

SGIA appear to give the interconnection customer complete discretion to take its governor or equivalent controls out of service, provided it gives the transmission provider notice.

134

To ensure the availability of frequency response when the balancing authority needs it, Bonneville suggests that such discretion be limited to operational constraints, “including, but not limited to, ambient temperature limitations, outages of mechanical equipment, or regulatory requirements.”

135

134

Bonneville Comments at 4.

135

Id.

at 4-5.

3. Commission Determination

a. Whether To Include Operating Requirements for Primary Frequency Response in the Pro Forma LGIA and Pro Forma SGIA

56. We disagree with commenters that argue the Commission should not establish minimum uniform operating requirements for primary frequency response.

136

Instead, we find that the establishment of minimum uniform operating requirements for all newly interconnecting generating facilities is preferable to the fragmented and inconsistent primary frequency response settings currently in place throughout the Eastern and Western Interconnections.

137

Assessments by NERC's Essential Reliability Services Task Force demonstrate that a lack of uniform, mandatory primary frequency response requirements has created the opportunity for generator owners/operators to implement operating settings that undermine the purpose and intent of Article 9.6.2.1 of the

pro forma

LGIA to promote and ensure the adequate provision of primary frequency response.

138

Article 9.6.2.1 of the

pro forma

LGIA requires a generating facility to operate its speed governors and voltage regulators in automatic operation mode when the facility is capable of such operation. Further, as the Commission observed in the NOPR, “[w]hile technological advancements have enabled wind and solar generating facilities to now have the ability to provide primary frequency response, this functionality has not historically been a standard feature that was included and enabled on non-synchronous generating facilities.”

139

Nothing in the record indicates that the Commission's observation was incorrect.

136

See, e.g.,

AES Companies Comments at 6; EEI Comments at 8; MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel Comments at 7.

137

The ERCOT Interconnection has uniform minimum requirements for primary frequency response, as generating facilities in Texas Reliability Entity Inc. are required to comply with the requirements of Regional Reliability Standard BAL-001-TRE-01.

138

See

NOPR, 157 FERC ¶ 61,122 at P 8. There, the NOPR explains that a 2010 NERC survey found that “only approximately 30 percent of generators in the Eastern Interconnection provided primary frequency response, and that only approximately 10 percent of generators provided sustained primary frequency response. This suggests that many generators within the Interconnection disable or otherwise set their governors or outer-loop controls such that they provide little to no primary frequency response.”

139

Id.

P 13.

57. We believe it is necessary to make these changes to the

pro forma

LGIA and

pro forma

SGIA now in order to ensure that the future generation mix will be capable of providing primary frequency response, and to arrest the general long-term declining trend for this essential reliability service. Adopting these requirements now is more prudent than waiting until the lack of primary frequency response undermines grid reliability, a point acknowledged by NERC's Essential Reliability Services Task Force.

58. Accordingly, we find that it is just and reasonable to include the proposed operating requirements of a maximum droop setting of 5 percent and deadband setting of ±0.036 Hz for primary frequency response in the

pro forma

LGIA and

pro forma

SGIA. We acknowledge that the needs of individual regions and balancing authority areas may warrant the adoption of different operating requirements in the future.

140

Therefore, the operating requirements for the

pro forma

LGIA and

pro forma

SGIA we adopt here are

minimum

interconnection requirements for new generating facilities based on the

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

141

NERC's Primary Frequency Control Guideline “reflect[s] the most advanced set of continent-wide best practices and information available in support of frequency response capability.”

142

140

See, e.g.,

Order No. 827, FERC Stats. & Regs. 31,385 (“Due to technological advancements, the cost of providing reactive power no longer represents an obstacle to the development of wind generation.”).

See also

Order No. 828, 156 FERC ¶ 61,062 at P 8 (modifying the

pro forma

SGIA to require interconnecting small generating facilities to ride through abnormal frequency and voltage events and not disconnect during such events because “the impact of small generating facilities on the grid has changed.”).

141

The Preamble to NERC's Primary Frequency Control Guideline states that “[t]hese guidelines are coordinated by the technical committees and include the collective experience, expertise and judgment of the industry. The objective of this reliability guideline is to distribute key best practices and information on specific issues critical to maintaining the highest levels of BES reliability.”

See

NERC Primary Frequency Control Guideline at 1.

142

NERC Comments at 6.

59. We disagree with the view of NRECA that this action is premature because, at present, primary frequency response at the Interconnection level may be acceptable.

143

Rather, we find, as stated by NERC, that increasing levels of generating facilities without primary frequency response capability, combined with the retirement of those generating facilities that have traditionally provided primary frequency response, “has contributed to the decline in primary frequency response.”

144

Further, we agree with NERC's Essential Reliability Services Task Force, which concluded that it is prudent and necessary to ensure that the future generation mix includes primary frequency response capabilities and recommends that all new generators support the capability to manage frequency.

145

143

NRECA Comments at 7.

144

NERC Comments at 5.

145

Essential Reliability Services Task Force Measures Report at vi.

60. AES Companies and MISO TOs contend that NERC “provides guidelines rather than standards because these guidelines may need to differ based on the type of resource,”

146

and that NERC's Primary Frequency Control Guideline was adopted rather than a Reliability Standard because “there are many current and anticipated reasons to deviate from” the Guideline.

147

We disagree and are persuaded instead by NERC and other commenters that minimum requirements are needed.

148

146

AES Comments at 6.

147

MISO TOs Comments at 11.

148

See, e.g.,

Bonneville Comments at 3; NERC Comments at 5; ISO-RTO Council Comments at 4-5.

61. We find ample support in the record to support this approach. For example, in its comments on the NOPR, NERC states that “the Commission's proposed revisions to the

pro forma

interconnection agreements are consistent with the results of recent NERC reliability assessment recommendations.”

149

Further, NERC supports the Commission's proposal, stating that “the NOPR's proposed minimum operating conditions should help ensure that frequency response capability is installed as well as available and ready to respond, regardless of the mix of resources in the dispatch” and notes its support for including the proposed droop and deadband settings in the

pro forma

LGIA and

pro forma

SGIA.

150

149

NERC Comments at 5.

150

Id.

at 5-6.

62. We disagree with EEI's assertion that the primary frequency response operating requirements should not be included in the

pro forma

LGIA and

pro forma

SGIA because the

pro forma

interconnection agreements lack “the necessary controls to ensure compliance.”

151

While this final action does not establish specific compliance procedures for new generating facilities, transmission providers are not prohibited from proposing such procedures in a FPA section 205 filing.

152

Also, the

pro forma

LGIA and

pro forma

SGIA contain Commission-approved directives that are legally enforceable obligations.

153

In any event, EEI's suggestion that transmission providers would neither detect nor address possible interconnection customer non-compliance with the new operating requirements is speculative and without support in the record.

151

EEI Comments at 11.

152

16 U.S.C. 824d (2012).

153

See NSTAR Elec. & Gas Corp.

FERC,

481 F.3d 794, 800 (D.C. Cir. 2007).

63. EEI, MISO TOs, and SoCal Edison request that the Commission not include the proposed operating requirements in the

pro forma

LGIA and

pro forma

SGIA, but instead defer to transmission providers or balancing authorities to establish operating requirements addressing reliability needs identified in regional studies.

154

For the reasons discussed above, we find that it is prudent to establish minimum uniform operating requirements as the foundational element of a framework for ensuring the adequacy and timeliness of primary frequency response. However, as noted immediately below and discussed in more detail in Section II.I below, the Commission establishes, with an addition and clarification, methods for proposing variations to this final action.

155

154

EEI Comments at 12; MISO TOs Comments at 9; SoCal Edison Comments at 3.

155

See

P 233 below, describing the following variation methods: (1) Variations based on Regional Entity reliability requirements; (2) variations that are “consistent with or superior to” the final action; and (3) “independent entity variations” filed by RTOs/ISOs.

64. While we are establishing uniform operating requirements, we also note that there is flexibility built into both the requirements themselves and the Commission's processes. First, we clarify that the requirements we adopt herein are

minimum

requirements. Thus, if an interconnection customer wishes to implement more stringent deadband and droop settings, it may do so.

156

Second, as also discussed in the next section, we have clarified the final action to allow for the possibility of a NERC Reliability Standard that has more stringent parameters than the requirements adopted here. Third, as discussed in Section II.I below, we continue the Commission's historic practice of allowing RTOs/ISOs to propose independent entity variations, as well as permitting other transmission providers to propose changes that are “consistent with or superior to” the

pro forma

language. Finally, in the event of a unique circumstance affecting specific resources, the transmission provider may file a non-conforming LGIA or SGIA, or the interconnection customer may request that the transmission provider file an unexecuted LGIA or SGIA.

156

See

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

65. Regarding EEI's request to conduct regional conferences, we do not believe that they are necessary at this time since: (1) The Commission has determined that minimum operating requirements are appropriate to include in the

pro forma

LGIA and

pro forma

SGIA; and (2) EEI's request to focus on other essential reliability services besides primary frequency response is beyond the scope of this proceeding.

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

pro forma

LGIA and

pro forma

SGIA are addressed below in Section II.E.

b. Whether To Include a Reference to a Future NERC Reliability Standard in the Pro Forma LGIA and Pro Forma SGIA

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

pro forma

LGIA and

pro forma

SGIA provisions that address any future NERC Reliability Standard that provides for more stringent parameters. The Commission agrees that the

pro forma

LGIA and

pro forma

SGIA (as applied to newly interconnecting generation facilities) should be written to allow for

the adoption of a future Reliability Standard with stricter operating requirements (droop and deadband parameters) without a need to further amend interconnection agreements.

68. Accordingly, as discussed below, we are modifying the NOPR proposal to allow for the possibility of a future NERC Reliability Standard that includes equivalent or more stringent operating requirements for droop, deadband, and/or timely and sustained response that would supersede the operating requirements for droop, deadband, and timely and sustained response adopted in this final action. We believe this approach will provide for the harmonization of the reliability-related provisions of the

pro forma

LGIA and

pro forma

SGIA with any future Reliability Standard, and will avoid potential conflicts between Reliability Standards and tariff provisions.

157

See

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

69. We clarify that interconnection customers that are required to comply with this final action will be required to do so until such time as the Commission approves a NERC Reliability Standard with equivalent or more stringent parameters.

158

If the Commission approves such a NERC Reliability Standard, interconnection customers subject to this final action will be required to comply with the operating requirements of the Reliability Standard if it applies to them. However, interconnection customers that are not Applicable Entities of the Reliability Standard will continue to be required to comply with the operating requirements contained within the

pro forma

LGIA and

pro forma

SGIA as adopted in this final action.

158

For example, such a Reliability Standard may have requirements for tighter droop (maximum 4 percent droop) and/or deadband settings (

e.g.,

±0.017 Hz).

c. Requirements for Droop and Deadband

70. We adopt the NOPR proposal to require newly interconnecting generating facilities to install, maintain, and operate a governor or equivalent with a maximum 5 percent droop and ±0.036 Hz deadband and for the droop characteristic to be based on the nameplate capacity.

71. As a threshold matter for this requirement, we clarify the term “nameplate capacity.” Some commenters raise concerns with the proposal to base the droop parameter on the nameplate capacity of a generating facility.

159

EEI asserts that basing droop characteristics on nameplate capacity is problematic since “resource response is based on MW and Reactive curves, and not MVA nameplate ratings.”

160

In response to this concern, we clarify that the use of the term “nameplate capacity” refers to the maximum MW rating of the facility as defined by the Energy Information Administration (EIA).

161

We note that EIA's definition of “nameplate capacity” utilizes units of MWs, not MVAs as suggested by EEI. In response to ISO-RTO Council's request for clarification on whether efficiency improvements to a generating facility that increase its output should be factored into the calculation of the droop parameter,

162

we clarify that if a modification to a generating facility causes its nameplate capacity to increase or decrease, then droop parameter should be based on the updated nameplate capacity value.

159

EEI Comments at 14; ESA Comments at 3-4.

160

EEI Comments at 14.

161

EIA defines nameplate capacity as “[t]he maximum rated output of a generator, prime mover, or other electric power production equipment under specific conditions designated by the manufacturer. Installed generator nameplate capacity is commonly expressed in MW and is usually indicated on a nameplate physically attached to the generator.”

See

EIA Glossary,

https://www.eia.gov/tools/glossary/index.php?id=G.

162

ISO-RTO Council Comments at 6.

72. The droop parameter is historically based on the percent change in frequency that would cause a 100 percent change in valve or gate position. This has been translated to the percent change in frequency that would cause a 100 percent change in power output, where a 100 percent change in power output is equivalent to the generator's nameplate capacity. The droop parameter also represents the slope of the MW response in proportion to the frequency deviation.

73. By requiring the droop parameter to be based on nameplate capacity, the Commission intends for a generating facility's expected MW response to frequency deviations to be a percentage of its nameplate capacity, and proportional to the magnitude of the frequency deviation. In particular, the magnitude of a generating facility's MW response to a frequency deviation will depend both on its nameplate capacity and on the magnitude of the frequency deviation. Generating facilities with larger nameplate capacities will provide more MW of primary frequency response per Hz of Interconnection frequency error compared to generating facilities with an equivalent percent droop parameter that have lower nameplate capacities. Accordingly, nameplate capacity is the “basis” of the droop parameter since this value will be used to calculate the expected proportional MW response to frequency deviations.

74. ISO-RTO Council points out that the nameplate capacity of a generating facility may not be consistent with its rated capacity for the purposes of obtaining interconnection service or for participation in an organized market. In addition, we recognize that during some operating conditions, the maximum steady state operating limit (

e.g.,

maximum sustainable MW limit) of a generating facility may be less than its nameplate capacity. Therefore, we clarify that for the purposes of calculating the expected amount of primary frequency response that is provided in response to frequency deviations, the calculation should still be based on a generating facility's full nameplate capacity even if the level of requested interconnection service or the steady state operating limit is below that nameplate capacity. We find that this approach is consistent with EPRI's statement that the droop setting is historically based on the percent change in frequency that would cause a 100 percent change in power output (where a 100 percent change in power output is equivalent to the nameplate capacity).

163

As an example, in the case of a generating facility with a 5 percent droop, as the Interconnection's frequency error changes from 0 to 3 Hz and as the system frequency transitions outside of the deadband parameter, the expected change in the generating facility's MW output should range from 0 MW to full nameplate capacity.

163

EPRI Supplemental Comments at 5.

75. We clarify that this final action will not require a generating facility that responds to frequency deviations to provide and sustain a value of primary frequency response that causes its MW output to exceed its maximum steady state operating limit.

164

For example, under-frequency conditions outside of the deadband parameter would result in an automatic increase in the generating facility's MW output. However, if the calculated incremental MW value that would be provided as primary

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

164

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

76. Similarly, over-frequency conditions would result in an automatic reduction in a generating facility's MW output. However, if the calculated value of primary frequency response would cause the facility's MW output to drop below its minimum operating MW limit, an interconnection customer will be permitted to limit the decrease in the facility's MW output such that the facility does not operate below its minimum steady state operating limit.

77. In addition, we are persuaded by NERC's suggestion to require the deadband parameter to be implemented without a step to the droop curve. We note that NERC's Primary Frequency Control Guideline references a 2013 IEEE Power & Energy Society (IEEE-PES) Technical Report stating that a droop curve (with a deadband) can be implemented in a generator governor in two possible ways: “Stepped” or “non-stepped.”

165

In its report, IEEE-PES points out that these two methodologies of implementing the deadband parameter can potentially have significantly different results in the response of a generating facility's governor control system to changes in system frequency.

166

According to IEEE-PES, if the deadband is implemented under the stepped approach, as soon as system frequency transitions outside of the deadband parameter (

e.g.,

±0.036 Hz), the generating facility will experience a sudden spike (increase or decrease) in its MW output, which IEEE-PES warns can be undesirable.

167

To account for this issue, NERC recommends in its Primary Frequency Control Guideline

168

and its comments to the NOPR

169

that the deadband should be implemented without a step to the droop curve. Under the non-stepped approach of implementing the deadband parameter, once frequency transitions outside of the deadband, the incremental change in the generating facility's MW output will start from zero and then increase linearly to the generating facility's nameplate capacity and in proportion to the Interconnection's frequency error.

170

165

NERC Primary Frequency Control Guideline at 6, referencing

Dynamic Models for Turbine-Governors in Power System Studie

s at Appendix B: Deadband, IEEE-PES (Jan 2013),

http://sites.ieee.org/fw-pes/files/2013/01/PES_TR1.pdf

(IEEE-PES Report).

166

IEEE-PES Report at Appendix B.

167

Id.

168

NERC Primary Frequency Control Guideline at 6.

169

NERC Comments at 6.

170

Id.

78. In consideration of this additional information, we agree with NERC and modify the NOPR proposal to require the deadband parameter to be implemented without a step. Accordingly, we are requiring the droop curve to be implemented in a manner such that as frequency transitions outside of the deadband (both for under-frequency and over-frequency conditions), the generating facility's expected MW response should start from 0 MW and increase linearly to the nameplate capacity of the generating facility, as the Interconnection's frequency error changes from 0 Hz to the generating facility's percentage droop multiplied by 60 Hz (

e.g.,

in the case of a 5 percent droop, this would be 3 Hz).

79. In response to EEI's concerns that: (1) The proposed frequency range of 59 to 61 Hz includes the deadband where governors do not operate; and (2) not all generating facilities respond in a linear manner, we are modifying the NOPR proposal and adopt in this final action that the droop parameter should be linear in the range of frequencies between 59 to 61 Hz that are outside of the deadband parameter. This is because the range of frequency values within the deadband do not trigger the operation of the governor or equivalent controls, and the slope of the droop curve that relates change in frequency to change in MW output should only apply to the range of frequencies outside of the deadband,

i.e.,

those frequencies where the generating facility's MW output is expected to change in proportion to frequency deviations. Regarding EEI's concern that not all generating facilities respond in a linear manner, we acknowledge that non-linear responses can and may occur. However, we believe that the existence of non-linear responses will not undermine the effectiveness of this final action. We expect that interconnection customers will take Reasonable Efforts to maximize and ensure their ability to provide a linear response in accordance with the droop parameter.

80. While we agree with WIRAB that the use of non-linear or piecewise droop parameters may lead to faster responses, we decline to adopt WIRAB's request to, on a generic basis, require prospective interconnection customers to implement non-linear or piecewise droop curves. While we require the droop curve to be linear (

e.g.,

5 percent) in the range of frequencies outside of the deadband between 59 to 61 Hz (

i.e.,

the response for both under-frequency and over-frequency conditions should be based on a maximum 5 percent droop), consistent with the NOPR proposal, we find that nothing in these requirements prohibit the implementation of asymmetrical droop settings (

i.e.,

different droop settings for under-frequency and over-frequency conditions), provided that each segment has a percent droop value of no more than 5 percent.

171

For example, our requirements would not prohibit the implementation of a droop curve that has a five percent droop for over-frequency conditions (

e.g.,

between 60.036 and 61.000 Hz) and a 3 percent droop for under-frequency conditions (

e.g.,

between 59.964 and 59.000 Hz).

172

171

See

NOPR, 157 FERC ¶ 61,122 at n.126.

172

See

WIRAB Comments at 7.

d. Requirements for the Status and Settings of the Governor or Equivalent Controls

81. We agree with NERC that the balancing authority should know the status and settings of the governor or equivalent controls and plant level controls in order to assess whether there is an appropriate amount of frequency reserve available.

173

In addition, the Commission agrees with NERC that providing this information to the balancing authority “would support [balancing authority] and [frequency response sharing group] efforts to help ensure sufficient frequency response and their compliance with Reliability Standard BAL-003-1.1.”

174

173

NERC Comments at 6-7.

174

Id.

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

governor or equivalent controls upon request or when the interconnection customer operates the generating facility with its governor or equivalent controls not in service. We determine that this is just and reasonable because it will help improve situational awareness by helping the balancing authority assess whether there is an appropriate amount of frequency responsive capacity online.

83. Regarding the process for an interconnection customer to disable its governor or equivalent controls, we share Bonneville's concern that the interconnection customer should not be allowed to operate its generating facility with its governor or equivalent controls not in service by merely notifying the transmission provider.

175

While we believe that it is not necessary to require the interconnection customer to meet specific operational conditions (

e.g.,

maintenance or outages of mechanical equipment) as a precondition to disabling the governor or equivalent controls as Bonneville suggests,

176

we are modifying the NOPR proposal to provide additional clarity on this issue.

175

Bonneville Comments at 4.

176

Id.

84. Specifically, we revise the

pro forma

LGIA and

pro forma

SGIA to require the interconnection customer to make Reasonable Efforts to keep outages of the generating facility's governor or equivalent controls to a minimum whenever it is operated in parallel with the Transmission System. The interconnection customer shall immediately notify the transmission provider and relevant balancing authority of its need to operate the generating facility without the governor or equivalent controls in service.

85. Accordingly, we will modify the

pro forma

LGIA and

pro forma

SGIA to state that when providing notice to the transmission provider of its intent to disable its governor or equivalent controls, the interconnection customer's notice shall include: (1) The operating status of the governor or equivalent controls (

i.e.,

whether it is currently out of service or when it will be taken out of service); (2) the reasons why the governor or equivalent controls are unable to be operated in service; and (3) a reasonable estimate as to when the governor or equivalent controls will be returned to service. The interconnection customer will be required to then make Reasonable Efforts to return its governor or equivalent controls to service as soon as practicable and notify the transmission provider and balancing authority when it has done so.

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

1. NOPR Proposal

86. In the NOPR, the Commission proposed to prohibit all new large and small generating facilities from taking any action that would inhibit the provision of primary frequency response, except under certain conditions, including but not limited to, ambient temperature limitations, outages of mechanical equipment, or regulatory requirements.

177

The Commission explained that the lack of coordination between governor and plant-level control systems can result in premature withdrawal of primary frequency response by allowing additional plant control systems to reverse the action of the governor to return the unit to operating at a pre-selected target set-point.

178

The Commission noted that NERC's Primary Frequency Control Guideline explains that “in order to provide sustained primary frequency response, it is essential that the prime mover governor, plant controls and remote plant controls are coordinated.”

179

177

NOPR, 157 FERC ¶ 61,122 at P 49.

178

Id.

179

Id.

(citing NERC Primary Frequency Control Guideline at 4).

87. Accordingly, the Commission proposed to require new generating facilities that respond to frequency deviations to not inhibit primary frequency response, such as by coordinating plant-level control equipment with the governor or equivalent controls.

180

In particular, the Commission proposed to include new Sections 9.6.4.2 of the

pro forma

LGIA and 1.8.4.2 of the

pro forma

SGIA to require that the real power response of new large and small generating facilities “to sustained frequency deviations outside of the deadband setting is provided without undue delay . . . until system frequency returns to a stable value within the deadband setting of the governor or equivalent controls.”

181

180

Id.

181

Id.

PP 52-53.

2. Comments

88. Several commenters support including the proposed provisions for timely and sustained response in the

pro forma

LGIA and

pro forma

SGIA.

182

NERC supports the minimum operating conditions proposed in the NOPR because “[s]uch requirements for the capability of `timely and sustained response to frequency deviations' should promote reliability and help avoid a scenario where the transforming resource mix reduces frequency response capability.”

183

ISO-RTO Council asserts that requiring primary frequency response to be sustained until frequency returns within the deadband parameter “is consistent with the current requirements of PJM and ISO-NE, as well as CAISO.”

184

182

Bonneville Comments at 2, First Solar Comments at 4; Idaho Power Comments at 1-2; ISO-RTO Council Comments at 5; NERC Comments at 5-6; WIRAB Comments at 5.

183

NERC Comments at 5-6.

184

ISO-RTO Council Comments at 5.

89. While acknowledging the importance of timely and sustained frequency response, EEI does not believe that such requirements should be included in the

pro forma

LGIA and

pro forma

SGIA because “the requirements do not consider the resource type or available capacity in requiring sustained response and therefore impose operating requirements for all governors or equivalent controls.”

185

EEI recommends that the Commission “limit its modifications of the

pro forma

LGIA and SGIA requirements to address resource capability (but not operational requirements) in order to allow regional needs and markets to address the issue of timely and sustained response for frequency deviations.”

186

Also, EEI believes that individual balancing authorities should determine operating requirements “on an as-needed basis or through compliance guidance” from NERC.

187

AES Companies agree, asserting that it is prudent for each balancing authority to determine appropriate criteria for timely and sustained response, because “the criteria for sustained and timely response may differ from system to system due to operating conditions, resource mix and more.”

188

185

EEI Comments at 9.

186

Id.

187

Id.

at 12.

188

AES Companies Comments at 14.

90. EEI raises an additional concern, stating that “requirements to provide timely and sustained frequency response cannot be implemented in a manner that is fair and non-discriminatory” because interconnection agreements “do not provide the necessary controls to ensure compliance . . . [or] effectively or fairly ensure compensation to those entities providing this support.”

189

EEI states that without a generic headroom requirement, a uniform requirement for timely primary frequency response “unfairly discriminates between those

resources that are capable of providing timely response due to their design or current operating status over resources that are not capable of providing a timely response.”

190

As an example, EEI states that renewables may not be able to provide a timely response to under-frequency deviations if they are operating at capacity or due to other technical limitations.

191

189

EEI Comments at 11.

190

Id.

191

Id.

91. WIRAB and EEI recommend certain modifications to the NOPR proposal for timely and sustained response. Both recommend that the Commission explicitly prohibit in the

pro forma

LGIA and

pro forma

SGIA the interconnection customer from blocking or otherwise inhibiting the ability of the governor or equivalent controls to respond.

192

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

92. In the NOPR, the Commission proposed to require that the real power response of new large and small generating facilities to sustained frequency deviations outside of the deadband setting is provided without undue delay . . . until system frequency returns to a stable value within the deadband setting of the governor or equivalent controls.”

193

WIRAB recommends that the term “without undue delay” be defined to require the generating facility to “provide immediate frequency response when system frequency deviates outside of the required deadband settings, and that no grace period be allowed that can postpone the response.”

194

Additionally, WIRAB recommends that “stable value” be defined as the “settled frequency response value achieved when frequency has rebounded and settled—after hitting the nadir—but possibly before reaching the normal frequency of 60 Hz.”

195

Also, WIRAB recommends that “[o]utside controls should not override a generator's frequency response until the system frequency has settled.”

196

WIRAB states that its recommended changes would ensure a consistent, timely, and sustained response from generating facilities providing primary frequency response.

197

193

NOPR, 157 FERC ¶ 61,122 at PP 52-53.

194

WIRAB Comments at 5.

195

Id.

at 5-6. WIRAB notes that NERC describes this settled frequency value in its Interconnection Frequency Response Obligation calculation used in Reliability Standard BAL-003-1.1 and labels the value “Value B” in the calculation.

Id.

at n.8.

196

Id.

at 6.

197

Id.

at 5.

93. AWEA asks the Commission to clarify that its proposed prohibition of actions “inhibiting” response does not restrict the ability of wind and other generating facilities to adjust the speed of their response in coordination with system operators to ensure a fair and coordinated response that best meets the needs of the system as a whole.

198

AWEA explains that the fast controls inherent in modern wind turbines allow them to respond to frequency deviations more quickly and accurately than many conventional generators, and that some generating facilities can respond so fast that slower-responding facilities cannot provide a coordinated response.

199

AWEA argues that there should be flexibility to ensure a fair and coordinated response (

i.e.,

allow wind generating facilities to respond more slowly than their full design capability) that meets the needs of the system and does not result in a disproportionate share of the response—and cost burden—being provided by facilities that can respond more rapidly (such as very fast-responding wind plants).

200

Accordingly, AWEA recommends that the Commission clarify that adjustments to the response speed of non-synchronous generating facilities, when done to ensure coordinated response for the system operator and fair distribution of cost impacts across generating facility types, do not “inhibit” response within the meaning of the NOPR, or if it does, are within the scope of the operational constraints permitted under the NOPR.

201

198

AWEA Comments at 8-9.

199

Id.

200

Id.

at 9.

201

Id.

3. Commission Determination

94. We determine that it is just and reasonable to include a requirement for timely and sustained response in the

pro forma

LGIA and

pro forma

SGIA. As stated in the NOI, premature withdrawal of primary frequency response “has the potential to degrade the overall response of the Interconnection and result in a frequency that declines below the original nadir.”

202

We are persuaded by the reliability assessments performed by NERC confirming a general decline in primary frequency response that, unless adequately addressed, could worsen as the generation resource mix continues to evolve.

203

The requirement for timely and sustained response would address that decline and more specifically would address concerns raised by NERC and others about the premature withdrawal of primary frequency response following a system disturbance, which is a significant concern in the Eastern Interconnection and a somewhat smaller issue in the Western Interconnection.

204

This phenomenon stems from generating facilities that do not sustain the response until system frequency returns to within the deadband parameter; instead they withdraw the response soon after it is provided.

205

In adopting this requirement, we agree with commenters who stated that there should be a clear requirement for primary frequency response to be timely and sustained.

206

202

See

NOI, 154 FERC ¶ 61,117 at P 49.

203

See

NERC Comments at 5. NERC states that it “has determined that increasing levels of non-synchronous resources installed without controls that enable frequency response capability, coupled with retirement of conventional resources that have traditionally provided primary frequency response, has contributed to the decline in primary frequency response” and that “a changing resource mix will further alter the dispatch of resources and combinations of resources . . . potentially resulting in systems operating states where frequency response capability could be diminished unless a sufficient amount of frequency responsive capacity is included in the dispatch.”

204

See

NOI, 154 FERC ¶ 61,117 at PP 49-50.

See also Frequency Response and Frequency Bias Setting Reliability Standard,

Notice of Proposed Rulemaking, 78 FR 45479 (July 29, 2013), 144 FERC ¶ 61,057, at PP 35-38 (2013).

205

In the NOI, the Commission stated that primary frequency response withdrawal “has the potential to degrade the overall response of the Interconnection and result in a frequency that declines below the original nadir.”

See

NOI, 154 FERC ¶ 61,117 at P 49.

206

See, e.g.,

Bonneville Comments at 2; ISO-RTO Council Comments at 5; NERC Comments at 5-6; WIRAB Comments at 6.

95. We are not persuaded by EEI's and AES Companies' view that timely and sustained response requirements should be part of regional solutions rather than be included in the

pro forma

LGIA and

pro forma

SGIA. NERC's assessments and conclusions do not indicate that the fundamental concerns about declining primary frequency response or the premature withdrawal of primary frequency response are unique or limited to individual regions. In addition, we note that frequency response is an Interconnection-wide phenomenon. Accordingly, we find that minimum, uniform primary frequency response requirements, including timely and sustained response, are just and reasonable.

96. EEI comments that without a provision to “fairly ensure adequate compensation,” and a mandate that each new generating facility operate with headroom at all times, the proposed requirements for timely and sustained primary frequency response “cannot be implemented in a manner that is fair and non-discriminatory.”

207

EEI asserts that “requiring all resources to have a timely operating response, but

failing to require necessary headroom, unfairly discriminates between those resources that are capable of providing a timely response due to their design or current operation status over resources that are not capable of providing a timely response.”

208

We disagree. We are imposing operating requirements on all newly interconnecting generating facilities (with limited exemptions) but not mandating headroom or compensation for any generating facilities. Any headroom maintained by these facilities is not required by this final action, and does not render our operating requirements unduly discriminatory. If future conditions necessitate a headroom requirement, we will then consider any appropriate compensation.

207

EEI Comments at 11.

208

Id.

97. As noted in Section II above, one of the Commission's concerns with the current lack of clear, uniform primary frequency response requirements is NERC's finding indicating that a number of generator owners/operators have implemented operating settings that have effectively removed the availability of their generating facilities from providing timely and sustained primary frequency response (

e.g.,

wide deadband settings, uncoordinated plant-level controls).

209

The reforms adopted in this final action, to be applied uniformly to new generating facilities, are intended to eliminate these practices. Accordingly, the Commission determines that the requirements are just, reasonable and not unduly discriminatory or preferential.

209

Id.

PP 8-9, 39.

98. Further, while it is true that generating facilities that are operated with no headroom at the time of an under-frequency deviation will provide little or no response in the upward direction, they will still be available to support the reliability of the power system by responding in the downward direction during abnormal over-frequency system conditions. Since the timing of an abnormal frequency deviation outside of the deadband parameter—and when a generating facility will thus be required to respond—is unpredictable, it is possible that these generating facilities will have operating capability in the upward direction to respond to some abnormal under-frequency deviations.

99. We agree with the suggestions of EEI and WIRAB to explicitly prohibit interconnection customers from blocking or otherwise inhibiting the governor's or equivalent controls' ability to respond.

210

Accordingly, as discussed below in Section II.K.3, the Commission will modify in this final action the NOPR proposal to require interconnection customers to not block or otherwise inhibit the governor or equivalent controls' ability to respond.

210

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

100. AWEA, ESA, and WIRAB ask the Commission to clarify the proposed timely and sustained response provisions, and their comments raise the following questions: (1) How soon should a generating facility begin to provide primary frequency response following a disturbance; and (2) how long, at a minimum, should the response be sustained?

101. Regarding how soon a generating facility should begin to provide primary frequency response following a disturbance, the Commission agrees with WIRAB that the definition of “without undue delay” should be clarified.

211

Accordingly, we clarify that the NOPR proposal for generating facilities to respond “without undue delay” is intended to address the concern that an interconnection customer could program an intentional delay of several seconds or minutes to effectively avoid contributing to the support of power system reliability following a disturbance. Following the sudden loss of generation or load, primary frequency response must be delivered as promptly as possible, within the physical characteristics of the generating facility, in order to avoid, for example, Interconnection frequency declining to a level where UFLS relays are activated or to a lower level where generation under-speed protection relays activate, resulting in additional generation trips or cascading outages. Accordingly, in response to WIRAB's request to clarify when a generating facility should respond to a frequency deviation, we will modify the NOPR proposal and adopt in this final action the requirement that generating facilities respond

immediately

after system frequency deviates outside of the deadband parameter, to the extent that they have available operating capability in the direction needed to correct frequency deviation at the time of the disturbance.

212

211

See

WIRAB Comments at 5.

212

The Commission accepted similar tariff language proposed by CAISO.

See Cal. Indep. Sys. Operator Corp.,

156 FERC ¶ 61,182, at P 17 (2016) (accepting, among other things, CAISO's proposed changes to s Section 4.6.5.1 of its tariff, which provides in pertinent part that “Participating Generators with governor controls that are synchronized to the CAISO Controlled Grid must respond immediately and automatically.”).

102. We agree with WIRAB that no grace period should be allowed that can postpone the response. Accordingly, we deny AWEA's request to coordinate response times between interconnection customers and system operators.

213

Instead, we require generating facilities to respond immediately, consistent with the technical capabilities of the generating facility and its control equipment.

213

See

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

103. Regarding the minimum period of time that a response should be sustained, we will not establish in this final action a minimum timeframe in minutes that the response to frequency deviations should be sustained since the amount of time that Interconnection frequency remains outside of the deadband varies by event.

104. We determine that rather than using the term “stable” used in the NOPR concerning the sustained response requirement, it is preferable to require primary frequency response to be sustained until such time that system frequency returns to a value within the deadband. Therefore, we find that WIRAB's recommendation to adopt its definition of “stable value” is moot. Accordingly, we clarify that with the exception of certain operational constraints described in Section 9.6.4.2 of the

pro forma

LGIA and Section 1.8.4.2 of the

pro forma

SGIA, generating facilities that respond to abnormal and sustained frequency deviations outside of the deadband parameter are required to provide and sustain primary frequency response until system frequency has returned to a value within the deadband parameter. If frequency recovers to within the deadband but suddenly deviates outside of the deadband parameter again, the interconnection customer will be required to provide and sustain its response until such time that frequency returns to a value within the deadband.

105. Comments related to electric storage resources pertaining to the timely and sustained response provisions are addressed below in Section II.H.2.

D. Proposal Not To Mandate Headroom

1. NOPR Proposal

106. In the NOPR, the Commission clarified that the proposed requirements did not impose a generic headroom requirement, but sought comment on such a requirement.

214

The Commission stated its belief that the reliability benefits from the proposed

modifications to the

pro forma

LGIA and

pro forma

SGIA do not require imposing additional costs that would result from a generic headroom requirement.

215

214

NOPR, 157 FERC ¶ 61,122 at P 51.

215

Id.

2. Comments

107. Several commenters state that the Commission should not create a mandatory headroom requirement.

216

Idaho Power asserts that a generic headroom requirement is not necessary at this time.

217

AWEA, Public Interest Organizations, and SDG&E state that there are significant opportunity costs involved in maintaining headroom.

218

WIRAB adds that not every generating facility needs to provide primary frequency response all the time; instead the decision of whether a generating facility provides primary frequency response and the necessary amount of headroom should be determined by economic considerations rather than by generic requirements.

219

EEI supports the NOPR proposal not to include a generic headroom requirement in the

pro forma

LGIA and

pro forma

SGIA “since these requirements go beyond capability (

i.e.,

equipment specifications.)”

220

However, EEI also asserts that

not

requiring headroom while requiring all primary frequency responses to be timely and sustained would be discriminatory, because all generating facilities are not capable of timely responses.

221

We address this assertion above in Section II.C.3.

216

EEI, Public Interest Organizations, AWEA, ESA, ISO-RTO Council, Xcel, Idaho Power, WIRAB, NERC, First Solar.

217

Idaho Power Comments at 2.

218

AWEA Comments at 2; Public Interest Organizations Comments at 4; SDG&E Comments at 2.

219

WIRAB Comments at 9.

220

EEI Comments at 13.

221

Id.

at 11.

108. AWEA requests that the Commission consider expanding on the NOPR proposal by finding that it would be unjust and unreasonable for a transmission provider to impose a requirement for all generating facilities to reserve headroom to provide primary frequency response due to the large inefficiency and cost of such a requirement.

222

ESA asserts that it interprets the Commission's proposal as an explicit prohibition against requiring interconnection customers to reserve headroom as a condition of interconnection.

223

222

AWEA Comments at 3.

223

ESA Comments at 2.

3. Commission Determination

109. We will not mandate a headroom requirement at this time. We continue to believe that the reliability benefits from the proposed modifications to the

pro forma

LGIA and

pro forma

SGIA do not require imposing additional costs that would result from a generic headroom requirement.

224

NOPR, 157 FERC ¶ 61,122 at P 44.

110. We decline to address AWEA's request to find it unjust and unreasonable for a transmission provider to impose a requirement for all generating facilities to reserve headroom to provide primary frequency response. Instead, in response to AWEA and ESA, we clarify that this final action does not prohibit a transmission provider from arguing to the Commission that headroom should be required as a condition of interconnection in a particular factual circumstance and proposing an associated compensation mechanism. We will evaluate any such filings on a case-by-case basis. Finally, we revise proposed Article 9.6.4 of the

pro forma

LGIA and Article 1.8.4 of the

pro forma

SGIA to delete the following reference: “Nothing shall require the generating facility to operate above its minimum operating limit, below its maximum operating limit, or otherwise alter its dispatch to have headroom to provide primary frequency response.” We believe that this phrase is unnecessary and that it is clear without it that we are not requiring headroom as a condition of interconnection.

E. Proposal Not To Mandate Compensation

1. NOPR Proposal

111. The Commission did not propose to mandate compensation related to the new primary frequency response requirements, stating “the Commission has previously accepted changes to transmission provider tariffs that similarly required interconnection customers to install primary frequency response capability or that established specific governor settings, without requiring any accompanying compensation.”

225

Further, the Commission clarified that the absence of a compensation mandate is not intended to prohibit a public utility from filing a proposal for primary frequency response compensation under section 205 of the FPA.

226

225

Id.

P 55 (citing

PJM Interconnection, L.L.C.,

151 FERC ¶ 61,097 at n.58;

Cal. Indep. Sys. Operator Corp.,

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

New England Power Pool,

109 FERC ¶ 61,155 (2004),

order on reh'g,

110 FERC ¶ 61,335 (2005)).

226

Id.

2. Comments

112. Many commenters support not mandating compensation.

227

On the other hand, a few commenters reject the NOPR's overarching approach, asserting instead that a market-based approach or a centralized forward procurement process is needed.

228

Other commenters qualify their support of the NOPR's approach to compensation on future efforts to establish forward procurement or market mechanisms.

229

227

ISO-RTO Council; WIRAB; Xcel; PG&E; APPA et al.; EEI; MISO TOs; NRECA; California Cities; and SoCal Edison.

228

AES; SDG&E; API; Chelan County; R St. Institute; and CESA.

229

AWEA; ELCON; Public Interest Organizations; and First Solar.

113. Some commenters believe that compensation issues are best decided at the regional level.

230

ISO-RTO Council asserts that not mandating compensation is reasonable because “[f]undamentally, the costs of providing primary frequency response by all registered generators should be viewed simply as a cost of reliable generator operation (similar to, for example, maintenance, staffing, metering, software, and communications).

231

APPA et al. agrees, stating that primary frequency response capability should be a standard feature of new generating facilities.

232

APPA et al. also notes that the Commission recently recognized imposing requirements for generating facilities with governor controls without additional compensation is a just and reasonable condition of participation in wholesale markets.

233

In addition, SoCal Edison believes that the costs of primary frequency response capability are already adequately recovered through existing bilateral or market-based capacity contracts.

234

230

Xcel Comments at 7; PG&E Comments at 2; EEI Comments at 11; MISO TOs Comments at 14.

231

ISO-RTO Council Comments at 10.

232

APPA et al. Comments at 6.

233

Id.

(citing

Cal. Indep. Sys. Operator Corp.,

156 FERC ¶ 61,182 at P 17 (2016)).

234

SoCal Edison Comments at 4.

114. AWEA states that the cost of attaining primary frequency response capability for new generators is low

235

but asserts that the Commission's decision not to address compensation for primary frequency response capability in the proposed rulemaking is not a major concern, so long as there is no headroom requirement.

236

California Cities compares primary frequency response with a number of interconnection requirements for generating facilities in which the recovery of capital costs and operating

expenses are not necessarily ensured.

237

California Cities states that developers of new generating facilities have the opportunity to recover capital costs for primary frequency response capability in the same ways they recover other capital costs associated with generation resources and can factor the costs of primary frequency response into their economic assessment of project viability under anticipated market conditions and into their negotiations for capacity sales.

238

235

AWEA Comments at 1.

236

Id.

at 9.

237

California Cities Comments at 4.

238

Id.

115. ELCON supports not mandating compensation, expressing its expectation that such costs should be low, observing that the administrative costs of a compensation scheme may outweigh the costs of providing mandated service.

239

Further, ELCON joins APPA et al. in noting that this is consistent with prior Commission decisions requiring the installation of primary frequency response capability or specifying governor settings, without mandating compensation.

240

ELCON emphasizes that its comments regarding compensation are limited to the currently proposed limited applicability of new requirements to new generation facilities because a broader approach would trigger more significant costs and should focus on market-based solutions such as that under Order No. 819.

241

239

ELCON Comments at 6.

240

Id.

n.4 (citing

PJM Interconnection, L.L.C.,

151 FERC ¶ 61,097 at n.58;

Cal. Indep. Sys. Operator Corp.,

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

New England Power Pool,

109 FERC ¶ 61,155 (2004),

order on reh'g,

110 FERC ¶ 61,335 (2005)).

241

Id.

at 7.

116. In support of compensation, several commenters state that the proposed requirements are inefficient or uneconomic because, among other points, they require new generating facilities to install and operate a governor or equivalent controls when the necessary primary frequency response could be provided at lower cost by another generating facility (

e.g.,

battery storage or existing generating facility).

242

These commenters believe that market-based procurement will create opportunities for transmission providers to obtain higher-quality frequency response at a lower cost compared to a mandatory primary frequency response requirement for all newly interconnecting generating facilities. Rather than the mandatory requirements proposed in the NOPR, some commenters prefer market-based compensation to incent the “right” level of primary frequency response.

243

242

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

243

API Comments at 3-4; Chelan County Comments at 1-2; Public Interest Organizations Comments at 6-7; R St Institute's Comments at 2-3; and SDG&E Comments at 3.

117. Other commenters believe that generating facilities should not be required to provide primary frequency response without compensation for their costs of providing the service.

244

SDG&E asserts that the NOPR proposals will not address the Commission's concerns regarding the decline in primary frequency response because “uncompensated costs are at the root of poor historical performance.”

245

Further, AWEA raises concerns that it is unjust and unreasonable to mandate that new generation incur investment and maintenance costs to be primary frequency response capable without being provided a real opportunity to recover such costs.

246

Competitive Suppliers assert that “[a]ll resources that provide essential reliability services such as primary frequency response

and

inertia should be explicitly compensated rather than mandating generators provide them without distinct and additional compensation.”

247

Competitive Suppliers urge the Commission to address compensation in a final rule or additional NOPR.

248

First Solar encourages the Commission to require compensation for the configuration and additional communication, software and control technologies required to operate the equipment at a solar PV generation facility to provide essential reliability services.

249

First Solar believes that the Commission should also require ISOs and RTOs develop a funding mechanism and operational and market rules to accommodate the headroom requirements for these facilities to provide frequency response.

250

244

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

245

SDG&E Comments at 3.

246

AWEA Comments at 10.

247

Competitive Suppliers Comments at 5.

248

Id.

249

First Solar Comments at 4.

250

Id.

118. ESA raises concerns that, without compensation, the primary frequency response requirement for electric storage “may produce disproportionate adverse economic impacts.”

251

Therefore, ESA recommends that the Commission “direct RTOs/ISOs to use pay-for-performance principles to price primary frequency response provision.”

252

ESA relies on Order No. 755, where the Commission found that frequency regulation compensation practices that do not compensate performance result in rates that are unjust, unreasonable, and unduly discriminatory or preferential. ESA contends that the same argument applies to frequency response compensation.

253

251

ESA Comments at 4.

252

Id.

at 6.

253

ESA Comments at 6-7 (citing

Frequency Regulation Compensation in Organized Wholesale Power Markets,

Order No. 755, FERC Stats. & Regs. ¶ 31,324, at P 2 (2011) (crossed referenced at 137 FERC ¶ 61,064).

3. Commission Determination

119. We will not mandate compensation for primary frequency response service in this final action. We are not persuaded by comments that assert: (1) Generating facilities should not be required to provide a service if there is not explicit compensation; (2) market-based compensation would be more efficient than the NOPR proposal; (3) inertia should be compensated in this final action; and (4) that frequency regulation compensation under Order No. 755 requires that primary frequency response be compensated. We address each of these points below.

120. Commenter assertions that the Commission is improperly requiring the provision of a service without compensation are misplaced. While we are requiring newly interconnecting generating facilities to install equipment capable of providing frequency response and adhere to specified operating requirements, we are not mandating headroom, which is a necessary component for the provision of primary frequency response service. In addition, as stated in the NOPR, “[t]he Commission has previously accepted changes to transmission provider tariffs that similarly required interconnection customers to install primary frequency response capability or that established specified governor settings, without requiring any accompanying compensation.”

254

Further, we agree

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

254

NOPR, 157 FERC ¶ 61,122 at P 55 (citing

PJM Interconnection, L.L.C.,

151 FERC ¶ 61,097 at n.58;

Cal. Indep. Sys. Operator Corp.,

156 FERC ¶ 61,182 at PP 10-12 and 17;

New England Power Pool,

109 FERC ¶ 61,155,

order on reh'g,

110 FERC ¶ 61,335). The Commission reiterated this approach in

Indianapolis Power & Light Company

Midcontinent Indep. Sys. Operator, Inc.,

158 FERC ¶ 61,107, at PP 36-37 (2017) (

Indianapolis Power

) (denying Indianapolis Power's request that the Commission find MISO's Tariff to be unjust, unreasonable, and unduly discriminatory or preferential because it does not compensate suppliers of primary frequency response).

121. On balance, we find that the record indicates that the cost of installing, maintaining, and operating a governor or equivalent controls is minimal.

255

Also, the greatest cost associated with providing primary frequency response results from maintaining headroom, as noted by several commenters.

256

No commenter provided any evidence suggesting that the costs of providing primary frequency response are greater than those indicated in the NOPR.

257

While the Commission has approved specific compensation for discrete services that require substantial identifiable costs, such as for frequency regulation and operating reserves, the Commission has not required specific compensation for all reliability-related costs. We agree with those commenters who observe that minimal reliability-related costs such as those incurred to provide primary frequency response, are reasonably considered to be part of the general cost of doing business, and are not specifically compensated.

255

See

NOPR, 157 FERC ¶ 61,122 at PP 62-71;