Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response, 85176-85190 [2016-28321]

Download as PDF 85176 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules format and not in a scanned format. Commenters filing electronically do not need to make a paper filing. 27. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426. 28. All comments will be placed in the Commission’s public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters are not required to serve copies of their comments on other commenters. IV. Document Availability 29. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and print the contents of this document via the Internet through the Commission’s Home Page (http:// www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 30. From the Commission’s Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number (excluding the last three digits) in the docket number field. 31. User assistance is available for eLibrary and the Commission’s Web site during normal business hours from the Commission’s Online Support at 202– 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202)502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. By direction of the Commission. Issued: November 17, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. ehiers on DSK5VPTVN1PROD with PROPOSALS [FR Doc. 2016–28193 Filed 11–23–16; 8:45 am] BILLING CODE 6717–01–P VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM16–6–000] Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response Federal Energy Regulatory Commission, Department of Energy. ACTION: Notice of proposed rulemaking. AGENCY: The Federal Energy Regulatory Commission (Commission) proposes to revise its regulations to require all newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install and enable primary frequency response capability as a condition of interconnection. To implement these requirements, the Commission proposes to revise the pro forma Large Generator Interconnection Agreement (LGIA) and the pro forma Small Generator Interconnection Agreement (SGIA). The proposed changes are designed to address the increasing impact of the evolving generation resource mix and to ensure that the relevant provisions of the pro forma LGIA and pro forma SGIA are just, reasonable, and not unduly discriminatory or preferential. The Commission also seeks comment on whether its proposals in this Notice of Proposed Rulemaking are sufficient at this time to ensure adequate levels of primary frequency response, or whether additional reforms are needed. DATES: Comments are due January 24, 2017. SUMMARY: Comments, identified by docket number, may be filed in the following ways: • Electronic Filing through http:// www.ferc.gov. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. • Mail/Hand Delivery: Those unable to file electronically may mail or handdeliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426. Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures Section of this document. FOR FURTHER INFORMATION CONTACT: Jomo Richardson (Technical Information), Office of Electric ADDRESSES: PO 00000 Frm 00013 Fmt 4702 Sfmt 4702 Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502– 6281, Jomo.Richardson@ferc.gov. Mark Bennett (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502–8524, Mark.Bennett@ferc.gov. SUPPLEMENTARY INFORMATION: 1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) proposes to modify the pro forma Large Generator Interconnection Agreement (LGIA) and the pro forma Small Generator Interconnection Agreement (SGIA), pursuant to its authority under section 206 of the Federal Power Act (FPA) to ensure that rates, terms and conditions of jurisdictional service remain just and reasonable and not unduly discriminatory or preferential.1 The proposed modifications would require all new large and small generating facilities, including both synchronous and non-synchronous, interconnecting with a LGIA or SGIA to install, maintain and operate equipment capable of providing primary frequency response as a condition of interconnection. The Commission also proposes to establish certain operating requirements, including maximum droop and deadband parameters in the pro forma LGIA and pro forma SGIA. The Commission does not propose to apply these requirements to generating facilities regulated by the Nuclear Regulatory Commission. In addition, the Commission does not propose in these reforms to impose a headroom requirement for new generating facilities. The Commission also does not propose to mandate that new generating facilities receive any compensation for complying with the proposed requirements in this NOPR. 2. The proposed revisions address the Commission’s concerns that the existing pro forma LGIA contains limited primary frequency response requirements that apply only to synchronous generating facilities and do not account for recent technological advancements that have enabled new non-synchronous generating facilities to now have primary frequency response capabilities. Further, the Commission believes that it may be unduly discriminatory or preferential to impose primary frequency response requirements only on new large generating facilities but not on new small generating facilities, and the reforms proposed here would impose 1 16 E:\FR\FM\25NOP1.SGM U.S.C. 824e (2012). 25NOP1 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules comparable primary frequency response requirements on both new large and small generating facilities. 3. In addition, and as discussed below in paragraph 57, the Commission also seeks comment on whether its proposals in this NOPR are sufficient at this time to ensure adequate levels of primary frequency response, or whether additional reforms are needed. 4. The Commission seeks comment on the proposed reforms and requests for comment sixty (60) days after publication of this NOPR in the Federal Register. I. Background ehiers on DSK5VPTVN1PROD with PROPOSALS A. Frequency Response 5. Reliable operation of an Interconnection 2 depends on maintaining frequency within predetermined boundaries above and below a scheduled value, which is 60 Hertz (Hz) in North America. Changes in frequency are caused by changes in the balance between load and generation, such as the sudden loss of a large generator or a large amount of load. If frequency deviates too far above or below its scheduled value, it could potentially result in under frequency load shedding (UFLS), generation tripping, or cascading outages.3 6. Mitigation of frequency deviations after the sudden loss of generation or load is driven by three primary factors: inertial response, primary frequency response, and secondary frequency response.4 Primary frequency response actions begin within seconds after system frequency changes and are mostly provided by the automatic and autonomous actions (i.e., outside of system operator control) of turbine2 An Interconnection is a geographic area in which the operation of the electric system is synchronized. In the continental United States, there are three Interconnections, namely the Eastern, Texas, and Western Interconnections. 3 UFLS is designed for use in extreme conditions to stabilize the balance between generation and load. Under frequency protection schemes are drastic measures employed if system frequency falls below a specified value. See Automatic Underfrequency Load Shedding and Load Shedding Plans Reliability Standards, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,682, at PP 4– 10 (2011) (Order No. 763 NOPR) at PP 4–10. 4 In the Notice of Inquiry issued in Docket No. RM16–6–000 on Feb. 8, 2016, the Commission provided detailed discussion of how inertia, primary frequency response, and secondary frequency response interact to mitigate frequency deviations. Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response, 154 FERC ¶ 61,117, at PP 3–7 (2016) (NOI). See also Use of Frequency Response 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). VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 governors, while some response is provided by frequency responsive loads.5 Primary frequency response actions are intended to arrest abnormal frequency deviations and ensure that system frequency remains within acceptable bounds. An important goal for system planners and operators is for the frequency nadir,6 during large disturbances, to remain above the first stage of UFLS set points within an Interconnection. 7. Frequency response is a measure of an Interconnection’s ability to arrest and stabilize frequency deviations following the sudden loss of generation or load, and is affected by the collective responses of generation and load throughout the Interconnection. When considered in aggregate, the primary frequency response provided by generators within an Interconnection has a significant impact on the overall frequency response. NERC Reliability Standard BAL–003–1.1 defines the amount of frequency response needed from balancing authorities 7 to maintain Interconnection frequency within predefined bounds and includes requirements for the measurement and provision of frequency response.8 While NERC Reliability Standard BAL–003– 1.1 establishes requirements for balancing authorities, it does not include any requirements for individual generator owners or operators.9 5 NOI, 154 FERC ¶ 61,117 at P 6. The Commission also noted that regulation service is different than primary frequency response because generating facilities that provide regulation respond to automatic generation control signals and regulation service is centrally coordinated by the system operator, whereas primary frequency response service, in contrast, is autonomous and is not centrally coordinated. Schedule 3 of the pro forma Open Access Transmission Tariff (OATT) bundles these different services together, despite their differences. See Id. n.66. 6 The point at which the frequency decline is arrested (following the sudden loss of generation) is called the frequency nadir, and represents the point at which the net primary frequency response (real power) output from all generating units and the decrease in power consumed by the load within an Interconnection matches the net initial loss of generation (in megawatts (MW)). 7 NERC’s Glossary of Terms defines a balancing authority as ‘‘(t)he responsible entity that integrates resource plans ahead of time, maintains loadinterchange-generation balance within a balancing authority area, and supports Interconnection frequency in real time.’’ 8 Frequency Response and Frequency Bias Setting Reliability Standard, Order No. 794, 146 FERC ¶ 61,024 (2014). 9 The Commission has also accepted Regional Reliability Standard BAL–001–TRE–01 (Primary Frequency Response in the ERCOT Region) as mandatory and enforceable, which does establish requirements for generator owners and operators with respect to governor control settings and the provision of primary frequency response within the Electric Reliability Council of Texas (ERCOT) region. North American Electric Reliability Corporation, 146 FERC ¶ 61,025 (2014). PO 00000 Frm 00014 Fmt 4702 Sfmt 4702 85177 8. Unless otherwise required by tariffs or interconnection agreements, generator owners and operators can independently decide whether units are configured to provide primary frequency response.10 The magnitude and duration of a generator’s response to frequency deviations is generally determined by the settings of the unit’s governor 11 (or equivalent controls) and other plant level (e.g., ‘‘outer-loop’’) control systems. In particular, the governor’s droop and deadband settings have a significant impact on the unit’s provision of primary frequency response. In addition, plant-level or ‘‘outer-loop’’ controls, unless properly configured, can override or nullify a generator’s governor response and return the unit to operate at a scheduled pre-disturbance megawatt set-point.12 In 2010, NERC conducted a survey of generator owners and operators and found that only approximately 30 percent of generators in the Eastern Interconnection provided primary frequency response, and that only approximately 10 percent of generators provided sustained primary frequency response.13 This suggests that many generators within the Interconnection disable or otherwise set their governors or outer-loop controls such that they provide little to no primary frequency response.14 9. Declining frequency response performance has been an industry concern for many years. NERC, in conjunction with EPRI, initiated its first examination of declining frequency response and governor response in 1991.15 More recently, as noted in the 10 See NOI, 154 FERC ¶ 61,117 at PP 18–19. governor is an electronic or mechanical device that implements primary frequency response on a generator via a droop parameter. Droop refers to the variation in real power (MW) output due to variations in system frequency and is typically expressed as a percentage (e.g., 5 percent droop). Droop reflects the amount of frequency change from nominal (e.g., 5 percent of 60 Hz is 3 Hz) that is necessary to cause the main prime mover control mechanism of a generating facility to move from fully closed to fully open. A governor also has a deadband parameter which establishes a minimum frequency deviation (e.g., ±0.036 Hz) from nominal that must be exceeded in order for the governor to act. 12 For more discussion on ‘‘premature withdrawal’’ of primary frequency response, see NOI, 154 FERC ¶ 61,117 at PP 49–50. 13 See NERC Frequency Response Initiative Report: The Reliability Role of Frequency Response (Oct. 2012), http://www.nerc.com/docs/pc/FRI_ Report_10-30-12_Master_w-appendices.pdf (NERC Frequency Response Initiative Report) at 95. 14 However, as noted below, some commenters note that nuclear generating units are restricted by their U.S. Nuclear Regulatory Commission operating licenses regarding the provision of primary frequency response. 15 NERC Frequency Response Initiative Report at 22. 11 A E:\FR\FM\25NOP1.SGM 25NOP1 85178 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules NOI, while the three U.S. Interconnections currently exhibit adequate frequency response performance above their Interconnection Frequency Response Obligations,16 there has been a significant decline in the frequency response performance of the Western and Eastern Interconnections.17 B. Prior Commission Actions ehiers on DSK5VPTVN1PROD with PROPOSALS 10. In Order Nos. 2003 18 and 2006,19 the Commission adopted standard procedures for the interconnection of large and small generating facilities, including the development of standardized pro forma generator interconnection agreements and procedures. The Commission required public utility transmission providers 20 to file revised OATTs containing these standardized provisions, and use the LGIA and SGIA to provide nondiscriminatory interconnection service to Large Generators (i.e., generating facilities having a capacity of more than 20 MW) and Small Generators (i.e., generators having a capacity of no more than 20 MW). The pro forma LGIA and pro forma SGIA have since been revised through various subsequent proceedings.21 16 The Interconnection Frequency Response Obligations are established by NERC and are designed to require sufficient frequency response for each Interconnection (i.e., the Eastern, ERCOT, Quebec and Western Interconnections) to arrest frequency declines even for severe, but possible, contingencies. 17 NOI, 154 FERC ¶ 61,117 at P 20. 18 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order No. 2003–A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003–B, FERC Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003–C, FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008). 19 Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh’g, Order No. 2006–A, FERC Stats. & Regs. ¶ 31,196 (2005), order granting clarification, Order No. 2006–B, FERC Stats. & Regs. ¶ 31,221 (2006). 20 A public utility is a utility that owns, controls, or operates facilities used for transmitting electric energy in interstate commerce, as defined by the FPA. See 16 U.S.C. 824(e) (2012). A non-public utility that seeks voluntary compliance with the reciprocity condition of an OATT may satisfy that condition by filing an OATT, which includes a LGIA and SGIA. See Order No. 2003, FERC Stats. & Regs. ¶ 31,146, at PP 840–845. 21 E.g., Small Generator Interconnection Agreements and Procedures, Order No. 792, 145 FERC ¶ 61,159 (2013), clarifying, Order No. 792–A, 146 FERC ¶ 61,214 (2014); Reactive Power Requirements for Non-Synchronous Generation, Order No. 827, 81 FR 40,793 (Jun. 23, 2016), 155 FERC ¶ 61,277 (2016); Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities, Order No. 828, 81 FR 50,290 (Aug. 1, 2016), 156 FERC ¶ 61,062 (2016). VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 11. As relevant here, the pro forma LGIA and pro forma SGIA are largely silent on any requirements with respect to primary frequency response. In particular, the only requirement in the pro forma LGIA or pro forma SGIA related to primary frequency response is contained within current Article 9.6.2.1 of the pro forma LGIA (Governors and Regulators), which provides that if speed governors are installed, they should be operated in automatic mode.22 A speed governor implements the primary frequency response provided by a synchronous generating facility; however, Article 9.6.2.1 does not address governor settings or plantlevel controls, which also affect the ability of a generating facility to provide primary frequency response. In addition, Article 9.6.2.1 does not require the installation of the necessary equipment for frequency response capability (i.e., governors or equivalent controls). Finally, the pro forma SGIA does not contain any provisions related to primary frequency response. C. Efforts To Evaluate the Impacts of the Changing Resource Mix 12. The Commission’s pro forma generator interconnection agreements and procedures were developed at a time when traditional synchronous generating facilities with standard governor controls and large rotational inertia were the predominant sources of electricity generation. However, the nation’s resource mix has undergone significant change since the issuance of Order Nos. 2003 and 2006. This transformation has been characterized by the retirement of baseload, synchronous generating facilities and the integration of more distributed generation, demand response, and natural gas generating facilities, and the rapid expansion of non-synchronous variable energy resources (VERs) such as wind and solar.23 For example, the U.S. Energy Information Administration (EIA) has observed that the U.S. added approximately 13 gigawatts (GW) of wind, 6.2 GW of utility scale solar photovoltaic (PV), and 3.6 GW of distributed solar PV generating facilities in 2014 and 2015.24 Conversely, NERC 22 Article 9.6.2.1 of the pro forma LGIA. term VER is defined as a device for the production of electricity that is characterized by an energy source that: (1) Is renewable; (2) cannot be stored by the facility owner or operator; and (3) has variability that is beyond the control of the facility owner or operator. See, e.g., Integration of Variable Energy Resources, Order No. 764, FERC Stats. & Regs. ¶ 31,331, at P 210 (2012). 24 See, U.S. electric generation capacity additions, 2015 vs. 2014, EIA (March 2016), https:// www.eia.gov/todayinenergy/detail.php?id=25492. 23 The PO 00000 Frm 00015 Fmt 4702 Sfmt 4702 has reported 25 that almost 42 GW of synchronous generating facilities (e.g., coal, nuclear, and natural gas) have retired between 2011 and 2014, and the EIA recently reported that nearly 14 GW of coal and 3 GW of natural gas generating facilities retired in 2015.26 13. While technological advancements have enabled wind and solar generating facilities to now have the ability to provide primary frequency response, this functionality has not historically been a standard feature that was included and enabled on nonsynchronous generating facilities. Moreover, wind and solar generating facilities typically operate at their maximum operating output, leaving no capacity (or ‘‘headroom’’) 27 to provide primary frequency response during under-frequency conditions. 14. Given the changes in the resource mix and concerns about the significant decline in frequency response for the Eastern and Western Interconnections,28 NERC has undertaken several initiatives to evaluate the impacts of the changing resource mix, particularly with respect to primary frequency response. For example, in 2014, NERC initiated the Essential Reliability Services Task Force (Task Force) to analyze and better understand the impacts of the changing resource mix and develop technical assessments of essential reliability services.29 The Task Force focused on three essential reliability services: Frequency support, ramping capability, and voltage support.30 The Task Force considered the seven ancillary 25 See NERC 2015 LTRA (Dec. 2015), http:// www.nerc.com/pa/RAPA/ra/ Reliability%20Assessments%20DL/2015LTRA%20%20Final%20Report.pdf. 26 See Electricity generating capacity retired in 2015 by fuel and technology, EIA (May 2016), http://www.eia.gov/todayinenergy/ detail.php?id=25272. 27 Headroom refers to the difference between the current operating point of a generator and its maximum operating capability, and represents the potential amount of additional energy that can be provided by the generating facility in real-time. 28 See NERC Frequency Response Initiative Industry Advisory—Generator Governor Frequency Response, at slide 10 (Apr. 2015), http:// www.nerc.com/pa/rrm/Webinars%20DL/Generator_ Governor_Frequency_Response_Webinar_April_ 2015.pdf. (NERC 2015 Frequency Response Webinar). See also LBNL 2010 Report at pp xiv–xv. 29 Essential reliability services are referred to as elemental reliability building blocks from resources (generation and load) that are necessary to maintain the reliability of the Bulk-Power System. See Essential Reliability Services Task Force Scope Document, at 1 (Apr. 2014), http://www.nerc.com/ comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ ERSTF_Final.pdf. 30 Essential Reliability Services Task Force Measures Report, at 22 (Dec. 2015), http:// www.nerc.com/comm/Other/essntlrlblty srvcstskfrcDL/ERSTF%20Framework%20Report %20-%20Final.pdf. E:\FR\FM\25NOP1.SGM 25NOP1 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules ehiers on DSK5VPTVN1PROD with PROPOSALS services 31 adopted by the Commission in Order Nos. 888 32 and 890 33 as a subset of the essential reliability services that may need to be augmented by additional services as the Bulk-Power System 34 characteristics change. 15. The Task Force did not recommend new reliability standards or specific actions to alter the existing suite of ancillary services; however, it did make certain conclusions with regard to primary frequency response. Specifically, the Task Force concluded that it is prudent and necessary to ensure that primary frequency response capabilities are present in the future generation resource mix, and recommended that all new generators support the capability to manage frequency.35 16. In addition, as part of its ongoing analysis of primary frequency response concerns, NERC observed in a 2012 report that a number of generators implemented deadband settings that were so wide as to effectively defeat the ability to provide primary frequency response.36 The report also notes that many generators provide frequency response in the wrong direction during 31 The seven pro forma ancillary services set forth in Order Nos. 888 and 890 are: (1) Scheduling, System Control and Dispatch Service; (2) Reactive Supply and Voltage Control from Generation Sources Service; (3) Regulation and Frequency Response Service; (4) Energy Imbalance Service; (5) Operating Reserve—Spinning Reserve Service; (6) Operating Reserve—Supplemental Reserve Service; and (7) Generator Imbalance Service. 32 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order No. 888–A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). 33 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890–B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890–C, 126 FERC ¶ 61,228, order on clarification, Order No. 890–D, 129 FERC ¶ 61,126 (2009). 34 Section 215(a)(1) of the Federal Power Act (FPA), 16 U.S.C. 824o(a)(1) (2012) defines ‘‘BulkPower System’’ as those ‘‘facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) [and] electric energy from generating facilities needed to maintain transmission system reliability.’’ The term does not include facilities used in the local distribution of electric energy. See also Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 76, order on reh’g, Order No. 693–A, 120 FERC ¶ 61,053 (2007). 35 Essential Reliability Services Task Force Measures Report at vi. 36 NERC Frequency Response Initiative Report at 92. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 a disturbance.37 Additionally, in February 2015, NERC issued an Industry Advisory that determined that a significant portion of generators within the Eastern Interconnection use deadbands or governor control settings that either inhibit or prevent the provision of primary frequency response.38 Moreover, as noted in the NOI, NERC observed in 2015 that in many conventional steam plants, deadband settings exceed ±0.036 Hz, resulting in primary frequency response that is not sustained, and that the vast majority of the gas turbine fleet is not frequency responsive.39 In response to these issues and other concerns, NERC’s Operating Committee approved a voluntary Primary Frequency Control Guideline that contains recommended settings for generator governors and other plant control systems, and encourages generators within the three U.S. Interconnections to provide sustained and effective primary frequency response.40 NERC’s Guideline recommends maximum 5 percent droop and ±0.036 Hz deadband settings for most generating facilities.41 D. Initiatives by Individual Transmission Providers 17. While the pro forma LGIA and pro forma SGIA do not provide specific requirements related to frequency response, some public utility transmission providers have included provisions related to primary frequency response in their LGIA, SGIA, OATTs, and/or business practice manuals. 18. For example, ISO New England Inc. (ISO–NE) and New York Independent System Operator, Inc. (NYISO) have adopted provisions to their LGIAs that establish more specific requirements for governor operation.42 37 NERC Frequency Response Initiative Report at 96–97. 38 NERC Generator Governor Frequency Response Industry Advisory (Feb. 2015), http:// www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015 %20Alerts/NERC%20Alert%20A-2015-02-05-01 %20Generator%20Governor%20Frequency %20Response.pdf. 39 NOI, 154 FERC ¶ 61,117 at P 50 (citing to NERC 2015 Frequency Response Webinar at 1). 40 See NERC Primary Frequency Control Guideline Final Draft (Dec. 2015), http:// www.nerc.com/comm/OC/Reliability%20Guideline %20DL/Primary_Frequency_Control_final.pdf (NERC Primary Frequency Control Guideline). See also NERC Operating Committee Meeting Minutes (Jan. 2016), http://www.nerc.com/comm/OC/ AgendasHighlightsMinutes/Operating %20Committee%20Minutes%20-%20Dec%2015-16 %202015-Final.pdf. 41 See NERC Primary Frequency Control Guideline at 7–9. 42 See ISO–NE, Transmission, Markets and Services Tariff, Schedule 22 Large Generator Interconnection Procedures (9.0.0), Appendix 6, 9.6.2.2; NYISO, NYISO Tariffs, NYISO OATT, 30.14 OATT Att. X Appendices (8.0.0), Appendix 6, 9.5.4. PO 00000 Frm 00016 Fmt 4702 Sfmt 4702 85179 In particular, ISO–NE requires each generator within its region with a capability of 10 MW or more, including VERs, to operate with a functioning governor with specified droop and deadband settings, i.e., maximum 5 percent droop and ±0.036 Hz deadband, and to also ensure that the provision of primary frequency response is not inhibited by the effects of outer-loop controls.43 19. PJM Interconnection, L.L.C. (PJM) has implemented governor droop and deadband requirements, i.e., maximum 5 percent droop and ±0.036 Hz deadband, for all generating facilities excluding nuclear facilities with a gross plant/facility aggregate nameplate rating greater than 75 MVA.44 PJM also recently added new interconnection requirements requiring new nonsynchronous generators to interconnect with ‘‘enhanced inverters’’ that have various capabilities including, among other things, the ability to provide primary frequency response.45 20. Midcontinent Independent System Operator, Inc. (MISO) requires governor operation as a condition for providing regulating reserve but does not require specific settings.46 Also, the Commission recently accepted tariff provisions proposed by the California Independent System Operator Corporation (CAISO) to require governor operation, specified droop and deadband settings, i.e., maximum 5 percent droop and ±0.036 Hz deadband, and provisions for sustained primary frequency response for its participating generators that have traditional governor controls.47 E. Notice of Inquiry 1. Summary 21. On February 18, 2016, the Commission issued the NOI to explore issues regarding essential reliability 43 See ISO–NE’s Operating Procedure No. 14 I (Governor Control), http://www.iso-ne.com/rules_ proceds/operating/isone/op14/op14_rto_final.pdf. 44 PJM’s pro forma interconnection agreements obligate interconnection customers within its region to abide by all PJM rules and procedures, including rules set forth in PJM’s Manuals (See PJM Tariff, Attachment O 8.0). See also PJM Manual 14D 7.1.1 (Generator Real-Power Control), http:// www.pjm.com/∼/media/documents/manuals/ m14d.ashx. 45 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097, at n.58 (2015). 46 See MISO, FERC Electric Tariff, Module C, Energy and Operating Reserve Markets 39.2.1B (34.0.0) (‘‘All Regulation Qualified Resources in the Day-Ahead Energy and Operating Reserve Market must be capable of automatically responding to and alleviating frequency deviations through a speed governor or similar device in accordance with the Applicable Reliability Standards.’’). 47 CAISO, 156 FERC ¶ 61,182, at PP 10–12 and 17 (2016). E:\FR\FM\25NOP1.SGM 25NOP1 85180 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules services and the evolving Bulk-Power System.48 In particular, the Commission asked a broad range of questions on the need for reform of its rules and regulations regarding the provision of and compensation for primary frequency response. The Commission explained that there is a significant risk that, as conventional synchronous generating facilities retire or are displaced by increased numbers of VERs that do not typically contribute to system inertia or have primary frequency response capabilities, the net amount of frequency responsive generation online will be reduced.49 The Commission also explained that these developments and their potential impacts could challenge system operators in maintaining reliability.50 Further, the Commission explained that NERC Reliability Standard BAL–003– 1.1 and the pro forma LGIA and pro forma SGIA do not specifically address a generator’s ability to provide frequency response.51 The Commission noted, however, that while in previous years many non-synchronous generating facilities were not designed with primary frequency response capabilities, the technology now exists for new nonsynchronous generating facilities to install primary frequency response capability.52 22. Accordingly, the Commission requested comments on three main sets of issues. First, the Commission sought comment on whether amendments to the pro forma LGIA and pro forma SGIA are warranted to require all new generating facilities, both synchronous and non-synchronous, to have primary frequency response capabilities as a precondition of interconnection.53 Second, the Commission sought comment on the performance of existing generating facilities and whether primary frequency response requirements for these facilities are warranted.54 Finally, the Commission sought comment on compensation for primary frequency response.55 2. Comments on Modifying the Pro Forma LGIA and Pro Forma SGIA ehiers on DSK5VPTVN1PROD with PROPOSALS 23. The Commission received a robust response from industry, with 47 entities collectively submitting nearly 700 pages of comments that provided responses to some or all of the questions posed by 48 NOI, 154 FERC ¶ 61,117. P 12. 50 Id. P 14. 51 Id. P 41. 52 Id. P 43. 53 Id. PP 2 and 44–45. 54 Id. PP 2, 46, and 52. 55 Id. PP 2, 53–54. 49 Id. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 the NOI.56 Relevant to the proposed revisions considered in this NOPR, the Commission received numerous comments on whether the pro forma LGIA and pro forma SGIA should be revised to include requirements for all newly interconnecting generating facilities, whether synchronous or nonsynchronous, to install primary frequency response capability.57 a. Comments in Support of Modifying the pro forma LGIA and pro forma SGIA 24. Most commenters support, or are not opposed to, revising the pro forma LGIA and SGIA to impose primary frequency response capability requirements on all new generating facilities as suggested in the NOI.58 Several commenters indicate that the nation’s changing resource mix could create reliability concerns related to the provision of primary frequency response. For example, PJM Utilities Coalition states that while newer generating facilities are not installing frequency response capability, the existing generating facilities that do provide this essential reliability service have more limited capability, due to the cost of operation and planned retirements, placing the grid at further risk.59 Peak Reliability, the reliability coordinator for the Western Interconnection, states that as baseload generation retires, the number of generators providing primary frequency response is reduced and may present reliability challenges for system operators, as fewer options are available to reduce frequency deviations following an unexpected loss of generation or load.60 CAISO asserts that due to the increased proportion of renewable generating facilities operating in CAISO’s balancing authority area, there may not be sufficient frequency responsive capacity online when the system has high renewable output and low load levels.61 Bonneville states that 56 The Appendix lists the entities that submitted comments and the shortened names that are used throughout this NOPR. 57 NOI, 154 FERC ¶ 61,117 at P 45. 58 APPA, et al. Comments at 6; Bonneville Comments at 6; CAISO Comments at 2; California Cities Comments at 2; ELCON Comments at 5; EEI Comments at 12; EPSA, et al. Comments at 8; Howard F. Illian Comments at 43; Idaho Power Comments at 1; IEEE–PES Comments at 1; Indicated ISOs/RTOs Comments at 3; ITC, et al. Comments at 1; MISO Comments at 4; MISO TOs Comments at 6; NARUC Comments at 3; NERC Comments at 17; North American Generator Forum Comments at 2; Peak Reliability Comments at 4; PG&E Comments at 2; SoCal Edison Comments at 4; Southern Company Comments at 2; Tri-State Generation Comments at 3; WIRAB Comments at 3. 59 PJM Utilities Coalition Comments at 3. 60 Peak Reliability Comments at 4. 61 CAISO Comments at 2. PO 00000 Frm 00017 Fmt 4702 Sfmt 4702 the trend of declining frequency response capability will continue with a changing resource mix, unless provisions are put in place to assure that adequate inertial and primary frequency response capability are available in the future.62 NERC states that the rapidly changing resource mix may reduce the level of available frequency capability.63 25. Numerous commenters assert that they recognize the benefits of revising the pro forma LGIA and pro forma SGIA to require primary frequency response capabilities for new generators. NERC, for example, asserts that new primary frequency response requirements for generators will improve operator flexibility for system restoration and island capability and help balancing authorities meet their frequency response obligations.64 NERC also asserts that revisions to the pro forma LGIA and pro forma SGIA would result in measurable, clear requirements applicable to all new generating facilities in a fair and equitable manner.65 NERC points out, however, that primary frequency response capability, by itself, would not require a resource to respond if called upon to help a balancing authority meet its frequency response obligation, and that, as a result, it is important to have mechanisms to ensure that sufficient frequency response capability is not only available but ready to respond at all times.66 CASIO, Indicated ISOs/ RTOs, MISO, and a number of trade associations also support modifications to the pro forma LGIA and pro forma SGIA for new generating facilities to install primary frequency response capability.67 PJM Utilities Coalition states that, with all new generating facilities (both synchronous and nonsynchronous) being fully capable of providing primary frequency response, requiring this capability will ensure that system operators have the ability to reliably operate the grid of the future.68 Peak Reliability states that it supports modifications to the pro forma LGIA and pro forma SGIA and that requiring generating facilities to install or provide frequency response in the initial stages of the interconnection process will ensure that the grid is able to maintain 62 Bonneville 63 NERC Comments at 2. Comments at 17. 64 Id. 65 Id. 66 Id. at 18. et al. Comments at 2; CAISO Comments at 2; EEI Comments at 3; EPSA, et al. Comments at 8; Indicated ISOs/RTOs Comments at 3; MISO Comments at 4; North American Generator Forum Comments at 2. 68 PJM Utilities Coalition Comments at 4–5. 67 APPA, E:\FR\FM\25NOP1.SGM 25NOP1 ehiers on DSK5VPTVN1PROD with PROPOSALS Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules this essential service even as the resource mix changes.69 26. Other commenters also express support for revising the pro forma LGIA and pro forma SGIA. Bonneville points out that selling primary frequency response capability would not provide sufficient incentive for new generating facilities to invest in such capability, and argues that the only way to ensure that there is enough primary frequency response capability is to require new generators to install it.70 WIRAB advises that while current studies do not indicate that there is a shortage of primary frequency response in the Western Interconnection and that all generators do not need to provide primary frequency response all of the time, the Commission should, however, require that all new generator owners install primary frequency response capability because of the changing resource mix in the Western Interconnection and the associated uncertainty regarding the future provision of primary frequency response.71 27. Several commenters that generally support revising the pro forma LGIA and pro forma SGIA also express certain concerns. For example, Southern Company expresses support for revising the pro forma LGIA and pro forma SGIA, but caveats its support by arguing that new regulations for primary frequency response should include an ‘‘opt-out’’ provision that would allow balancing authorities that do not anticipate frequency response shortfalls to delay the implementation of the new pro forma LGIA and pro forma SGIA requirements until these needs are actually anticipated in their regions in order to avoid higher costs.72 EPSA, et al. state that while they do not fully oppose amending the pro forma LGIA and pro forma SGIA, they recommend that the Commission explore more effective and cost efficient ways to address the range of issues posed in the NOI and consider a measured approach before mandating governors for all prospective interconnecting generation.73 28. Some commenters that support modifying the pro forma LGIA and pro forma SGIA also assert that the costs of implementing primary frequency response capability for new generating facilities are low.74 For example, APPA, 69 Peak Reliability Comments at 4–5. Comments at 21. 71 WIRAB Comments at 5–6. 72 Southern Company Comments at 2–3. 73 EPSA, et al. Comments at 8–9. 74 APPA, et al. Comments at 6; Bonneville Comments at 8; California Cities Comments at 2; 70 Bonneville VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 et al. state that the capability for providing primary frequency response is almost always installed in synchronous generation, and that the inclusion of this additional control for new nonsynchronous generating facilities would likely add only nominal costs.75 EEI asserts that all new generating facilities coming online can be fully capable of providing primary frequency response and that the associated cost of installing such capability during initial manufacturing or construction of a new VER is small when considering the overall cost of the new generating facility.76 29. In contrast to new generating facilities, some entities, however, explain that the costs of retrofitting existing generating facilities with primary frequency response capability could be significant in some cases.77 For example, WIRAB states that the high cost of retrofitting existing generators to install the necessary control equipment supports limiting the requirement to new generators and taking early action now.78 30. In regards to nuclear generating facilities, some commenters indicate that nuclear plants have separate licensing requirements under the Nuclear Regulatory Commission and should not be required to provide primary frequency response. For example, the Nuclear Energy Institute asserts that while nearly all new generating facilities should be able to provide primary frequency response, nuclear plants are not well-suited to provide primary frequency response due to restrictions by their operating licenses issued by the Nuclear Regulatory Commission.79 The Nuclear Energy Institute also asserts that turbine controls on most nuclear units are designed to maintain the internal steam pressure and are not intended to react to changes in the grid.80 Similarly, the MISO TOs assert that requiring nuclear units to have primary frequency response capability would be contrary to Nuclear Regulatory Commission licensing requirements, and could have a detrimental effect on the safety of the nuclear fleet.81 EEI Comments at 13; Indicated ISOs/RTOs Comments at 5; MISO Comments at 4; SoCal Edison Comments at 2. 75 APPA, et al. Comments at 6. 76 EEI Comments at 13. 77 APPA, et al. Comments at 6; Bonneville Comments at 8; California Cities Comments at 8; EEI Comments at 14; Idaho Power Comments at 4; WIRAB Comments at 6. 78 WIRAB Comments at 6. 79 Nuclear Energy Institute Comments at 1 and 4. 80 Nuclear Energy Institute Comments at 4. 81 MISO TOs Comments at 7. PO 00000 Frm 00018 Fmt 4702 Sfmt 4702 85181 31. In the NOI, the Commission also sought comment on whether it would be appropriate to include recommended governor settings contained within NERC’s Primary Frequency Control Guideline in the pro forma LGIA and pro forma SGIA.82 Numerous commenters express support for including NERC’s recommended governor control settings in the pro forma LGIA and pro forma SGIA.83 Some commenters note that NERC’s Guideline is consistent with existing regulations or practices in certain regions.84 Indicated ISOs/RTOs point out that common primary frequency response settings for generators in an Interconnection will enhance reliability by reducing maneuvering by individual generators.85 MISO asserts that NERC’s Guideline provides a sound baseline.86 NERC notes that its Guideline was developed by technical committees with expertise and judgment of the electric industry, and accordingly, the Guideline is the ‘‘most advanced set of nationwide best practices and information currently available to support frequency response capability.’’ 87 32. However, not all entities that support modifying the pro forma LGIA and pro forma SGIA endorse the inclusion of NERC’s recommended governor settings. For example, EEI states that it does not support including prescriptive performance requirements for governor control settings or other performance indicators in the pro forma LGIA or pro forma SGIA due to the physical, technical, or operational limitations of new generating facilities to provide primary frequency response.88 Similarly, APPA, et al. state that they do not support revising the pro forma LGIA and pro forma SGIA to include the recommended settings contained within NERC’s Guideline at this time.89 MISO TOs state that some transmission owners in MISO believe that NERC’s recommended governor settings are appropriate for traditional synchronous generating facilities, but recommend additional consideration for other generation technologies.90 On the other hand, MISO TOs state that other transmission owners in MISO request 82 NOI, 154 FERC ¶ 61,117 at P 45. e.g., Bonneville Comments at 7; IEEE–PES Comments at 1; Indicated ISOs/RTOs Comments at 4; California Cities Comments at 2; WIRAB Comments at 7. 84 Indicated ISOs/RTOs Comments at 4; SoCal Edison Comments at 4; Peak Reliability Comments at 7; Manitoba Comments at 8. 85 Indicated ISOs/RTOs Comments at 5. 86 MISO Comments at 4. 87 NERC Comments at 12. 88 EEI Comments at 15–17. 89 APPA, et al. Comments at 8. 90 MISO TOs Comments at 8. 83 See E:\FR\FM\25NOP1.SGM 25NOP1 85182 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules flexibility and assert that specified governor settings should not be ‘‘hardwired’’ or dictated in the pro forma LGIA and pro forma SGIA.91 b. Comments Opposed To Modifying the pro forma LGIA and pro forma SGIA 33. Other commenters contend that the pro forma LGIA and pro forma SGIA should not be modified to require primary frequency response capability from new generating facilities.92 Some commenters argue that requiring all new generating facilities to have primary frequency response capability will result in extra costs above those necessary to ensure reliability.93 For example, APS argues that a global mandate to provide primary frequency response or to require generating facilities to be primary frequency response capable would result in significantly increased costs while providing a disproportionately minor impact on improving reliability.94 Powerex asserts that modifying the pro forma LGIA and pro forma SGIA to include minimum primary frequency response requirements will increase the cost of entry for new generators, particularly VERs, which typically are not designed with such capability.95 Several commenters note that there would be a significant opportunity cost for certain generating facilities to reserve headroom for the provision of primary frequency response.96 34. Some of the commenters that are opposed to modifying the pro forma LGIA and pro forma SGIA assert that they prefer a market-based approach instead of a requirement for new generating facilities to install primary frequency response capability.97 For example, AWEA asserts that, initially, the pro forma LGIA and pro forma SGIA should not be revised to require new 91 MISO TOs Comments at 8. Companies Comments at 6; Apex Comments at 6; APS Comments at 6; AWEA Comments at 12; Chelan County Comments at 2; ESA Comments at 2; Grid Storage Consulting Comments at 2; Microgrids Resources Coalition Comments at 3; NRECA Comments at 9; Powerex Comments at 5; SDG&E Comments at 3; SolarCity Comments at 1; TVA Comments at 2. 93 Apex Comments at 5–6; APS Comments at 6; AWEA Comments at 12; Chelan County Comments at 2; Powerex Comments at 5; Solar City Comments at 1. 94 APS Comments at 6. It is unclear whether the increased costs referenced by APS refer only to the costs for the necessary equipment to provide primary frequency response or the costs associated with maintaining the headroom necessary to provide primary frequency response. 95 Powerex Comments at 5. 96 Apex Comments at 7; Solar City Comments at 1; AWEA Comments at 6. 97 Apex Comments at 6; AWEA Comments at 12; Chelan County Comments at 2; ESA Comments at 2; SDG&E Comments at 3. ehiers on DSK5VPTVN1PROD with PROPOSALS 92 AES VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 generating facilities to have primary frequency response capability, and only if market-based steps do not satisfactorily address the need for primary frequency response, then the Commission could consider an additional requirement for new generating facilities to have such capability as a final step.98 35. Other commenters oppose mandatory requirements and prefer a voluntary approach to improving primary frequency response performance.99 For example, TVA asserts that if current voluntary actions fail to show improvement in primary frequency response, then the pro forma LGIA and pro forma SGIA could be revised to contain a general primary frequency response requirement, similar to reactive power, but that NERC should be directed to establish governor settings and performance requirements through the NERC Standards Development Process instead of the Commission including such requirements in the pro forma LGIA and pro forma SGIA.100 Some commenters assert that governor control details are better left to individual balancing authorities.101 For example, APS argues that the Commission should allow balancing authorities to determine the type and magnitude of generating facilities within its balancing authority area that are frequency-response enabled.102 APS also points out that any need to install frequency response capability or otherwise support frequency response performance can and should be evaluated and agreed upon between a generating facility and the transmission provider during the interconnection study process.103 II. Discussion A. Primary Frequency Response Requirements 1. The Need for Reform 36. Pursuant to FPA section 206, the Commission preliminarily finds that conditions have changed since the issuance of Order Nos. 2003 and 2006 and certain aspects of the pro forma LGIA and pro forma SGIA may now be unjust, unreasonable, unduly discriminatory, or preferential.104 98 AWEA Comments at 12. Comments at 8; NRECA Comments at 6; TVA Comments at 2. 100 TVA Comments at 2–3 and 5. 101 APS Comments at 8; AES Companies Comments at 8. 102 APS Comments at 8. 103 Id. at 15. 104 The Commission routinely evaluates the effectiveness of its regulations and policies in light of changing industry conditions to determine if 99 APS PO 00000 Frm 00019 Fmt 4702 Sfmt 4702 Specifically, as discussed above, the record indicates that while the frequency response performance of the Eastern and Western Interconnections is currently adequate, the frequency response performance of both Interconnections has significantly declined from historic values.105 Furthermore, the record shows that there is an ongoing evolution of the nation’s generation resource mix, including significant retirements of baseload generation and an increasing proportion of VERs interconnecting to the electric grid.106 Several commenters point out that there is significant risk that the rapidly changing resource mix may reduce the level of available frequency response capability online.107 This is in part because, as noted in the NOI, VERs have not been consistently designed with primary frequency response capabilities.108 The record suggests, however, that VER manufacturers have made significant technological advancements in recent years to develop primary frequency response capability for VERs.109 In addition, NERC, in conjunction with various industry stakeholders, has developed more robust technical guidance for the operation of governors or equivalent controls.110 As a result of the evolving resource mix and the potential for adverse impacts on primary frequency response, the Commission is concerned that there may be potential reliability impacts if it does not undertake the reforms proposed in this NOPR. Moreover, the Commission is concerned that certain aspects of the existing pro forma LGIA and pro forma SGIA may no longer be just and reasonable. 37. First, the current requirements for governor controls in the pro forma LGIA do not reflect advances in technology or the latest recommended operating practices. Specifically, current Article 9.6.2.1 states that ‘‘speed governors,’’ if installed, must be operated in automatic changes are necessary. See, e.g., Order No. 764, FERC Stats. & Regs. ¶ 31,331. 105 See NERC 2015 Frequency Response Webinar at 10, NERC Frequency Response Initiative Report at 22, and LBNL 2010 Report at pp xiv–xv. 106 See, e.g., P 12, supra (describing recent and ongoing changes in the nation’s generation mix). 107 See, e.g., Bonneville Comments at 2; CAISO Comments at 2; NERC Comments at 17; Peak Reliability Comments at 4; PJM Utilities Coalition Comments at 3. 108 NOI, 154 FERC ¶ 61,117 at PP 42–43. 109 See, e.g., PJM Utilities Comments at 4–5; EEI Comments at 13. See also PJM Interconnection, L.L.C., Docket No. ER15–1193–000 (March 6, 2015) Transmittal Letter at 11. See also NERC 2014 LTRA, at 27 (Nov. 2014), http://www.nerc.com/pa/RAPA/ ra/Reliability%20Assessments%20DL/2014LTRA_ ERATTA.pdf. 110 See P 16, supra. E:\FR\FM\25NOP1.SGM 25NOP1 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules ehiers on DSK5VPTVN1PROD with PROPOSALS mode. However, many of the new generating facilities interconnecting to the grid, such as wind and solar, do not utilize traditional speed governors; instead they utilize enhanced inverters and other plant supervisory control technology that can be designed to include primary frequency response capability.111 Therefore, due to advancements in technology, the Commission preliminarily finds that the existing references to ‘‘speed governors’’ in Article 9.6.2.1 that apply only to synchronous resources are outdated, and therefore may no longer be just and reasonable. 38. Second, since the issuance of Order No. 2003 and the establishment of the pro forma LGIA, NERC, in conjunction with industry stakeholders, has amassed a significant body of knowledge in regards to the operation of generator governors and plant control systems. For example, as noted above, NERC observed in 2012 that a number of generators implemented deadband settings that were so wide as to effectively defeat the ability to provide primary frequency response, and that many generators provide frequency response in the wrong direction during a disturbance.112 Additionally, as noted above, NERC observed in 2015 that in many conventional steam plants, deadband settings exceed a ±0.036 Hz dead band, resulting in primary frequency response that is not sustained, and that the vast majority of the gas turbine fleet is not frequency responsive.113 39. The record here suggests that the actual governor and plant control system settings that are being implemented by some generator owners and/or operators may be defeating the intent of Article 9.6.2.1 of the pro forma LGIA. In response to these issues, NERC, through the work of its various task forces, subcommittees, and initiatives, has developed a voluntary Guideline that includes recommended droop and deadband settings based on significant investigation.114 However, the pro forma LGIA does not currently reflect these updated recommended 111 See Electric Power Research Institute, Recommended Settings for Voltage and Frequency Ride Through of Distributed Energy Resources (May 2015) at 27, http://www.epri.com/abstracts/Pages/ ProductAbstract.aspx?ProductId= 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. 112 See P 16, supra. 113 Id. 114 See NERC Primary Frequency Control Guideline. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 practices for governor and plant control system settings of generating facilities. 40. Third, given the nation’s evolving resource mix and the potential adverse impacts on primary frequency response as noted in the NOI and pointed out by several commenters, the Commission believes that changes to the pro forma LGIA and pro forma SGIA may be necessary to provide for the continued reliable operation of the power system. As noted above, the Task Force concluded that all new generating facilities should be required to be capable of providing primary frequency response.115 However, the pro forma LGIA does not currently require large generating facilities to install such capability; rather, it only requires governor operation in ‘‘automatic mode’’ if a ‘‘speed governor’’ is installed.116 41. In addition, the Commission is concerned that the current pro forma SGIA may be unduly discriminatory or preferential because it does not establish any specific requirements with respect to the installation or operation of governors or equivalent frequency control equipment. In particular, the pro forma SGIA does not have a similar provision to Article 9.6.2.1 of the pro forma LGIA. The Commission has previously acted under FPA section 206 to remove inconsistencies between the pro forma LGIA and pro forma SGIA when there is no economic or technical basis for treating large and small generating facilities differently.117 Similarly, in this instance, the record developed from the NOI appears to suggest that small generating facilities are capable of installing and enabling governors at low cost in a manner comparable to large generating facilities.118 As discussed above, the record indicates that there have been significant advances in technology, as well as the development of more robust technical guidance for the operation of governors or equivalent controls for both large and small generating 115 See P 15, supra. 9.6.2.1 of the pro forma LGIA. 117 See Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities, Order No. 828, 81 FR 50,290 (Aug. 1, 2016), 156 FERC ¶ 61,062 (2016), (The Final Rule revised the pro forma SGIA such that small generating facilities have frequency and voltage ride through requirements comparable to large generating facilities). 118 IEEE–P1547 Working Group Comments at 1, 5, and 7. Moreover, the Commission notes that other commenters stated costs of installing primary frequency response capability are generally low, but did not differentiate between small and large generating facilities. See, e.g., APPA, et al. Comments at 6; California Cities Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at 3–5; SoCal Edison Comments at 2. 116 Article PO 00000 Frm 00020 Fmt 4702 Sfmt 4702 85183 facilities.119 In particular, the IEEE– P1547 Working Group noted that its new IEEE–1547 standard for interconnecting distributed generation will likely include certain requirements for providing primary frequency response.120 Given these low-cost technological advances, the Commission does not anticipate that these additional requirements added in the pro forma SGIA will present a barrier to entry for small generating facilities. And, given the need for additional primary frequency response capability and an increasingly large market penetration of small generating facilities, the Commission believes that there is a need to add these requirements to the pro forma SGIA to help ensure adequate primary frequency response capability. 42. Moreover, as noted above, a number of commenters assert that costs for new generating facilities to install the capability of providing primary frequency response are low, suggesting that there is not a financial barrier to small generating facilities installing the capability to provide frequency response.121 PJM’s recent changes to require both small and large nonsynchronous generating facilities to use enhanced inverters, which include primary frequency response capability, among other functions, further support this notion.122 2. Commission Proposal 43. To remedy the potentially unjust, unreasonable, and unduly discriminatory or preferential practices described above, the Commission preliminarily finds that revisions to the pro forma LGIA and pro forma SGIA are appropriate. The Commission believes that revising the pro forma LGIA and pro forma SGIA to require all new generating facilities to install, maintain, and operate a functioning governor or equivalent controls, consistent with the proposed requirements described below, will help to ensure adequate primary frequency response capability as the resource mix continues to evolve, ensure fair and consistent treatment for all types of generating facilities, help balancing authorities meet their frequency response obligations pursuant to NERC Reliability Standard BAL–003– 1.1, and help improve reliability during 119 See PP 13, 36, supra. Working Group Comments at 1, 5, 120 IEEE–P1547 and 7. 121 See, e.g., APPA, et al. Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at 5; SoCal Edison Comments at 2. 122 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097 at P 28 (the Commission stated that it ‘‘find[s] that PJM’s proposal will not present a barrier to non-synchronous resources.’’). E:\FR\FM\25NOP1.SGM 25NOP1 ehiers on DSK5VPTVN1PROD with PROPOSALS 85184 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules system restoration and islanding situations.123 44. In particular, the Commission proposes to revise the pro forma LGIA and pro forma SGIA to include the following: (1) Requirements for new large and small generating facilities, both synchronous and nonsynchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection; (2) requirements for governor or equivalent controls to be operated, at a minimum, with maximum 5 percent droop and ±0.036 Hz deadband settings; (3) requirements to ensure the timely and sustained response to frequency deviations, including provisions to prevent plant-level (i.e., outer-loop) control equipment from inhibiting primary frequency response and resulting in premature withdrawal; and (4) a requirement for droop parameters to be based on nameplate capability with a linear operating range of 59 to 61 Hz. Additionally, as informed by NOI commenters, the Commission believes that it is not necessary to impose a generic headroom requirement or subject newly interconnecting nuclear generating facilities to the new requirements. The Commission does not propose to mandate any separate compensation related to the proposed requirements. The Commission seeks comment on the proposed reforms, as discussed more fully below. 45. Specifically, the Commission proposes to revise existing sections 9.6 and 9.6.2.1 of the pro forma LGIA and to include proposed new sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.3. Similarly, the Commission proposes to revise existing section 1.8 of the pro forma SGIA and add proposed new sections 1.8.4, 1.8.4.1, 1.8.4.1.1, 1.8.4.1.2, and 1.8.4.1.3.124 46. The Commission’s proposed revisions to the pro forma LGIA and pro forma SGIA would apply to new generating facilities that execute or request the unexecuted filing of interconnection agreements on or after the effective date of any Final Rule issued in Docket No. RM16–6–000. The Commission also proposes to apply the requirements to any large or small generating facility that has an executed or has requested the filing of an unexecuted LGIA or SGIA as of the effective date of any Final Rule in Docket No. RM16–6–000, but that takes 123 See NERC Comments at 17. See also NERC Essential Reliability Services Task Force Measures Framework Report at iv. 124 The specific proposed modifications and additions to the pro forma LGIA and pro forma SGIA are set forth at PP 52–53, below. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date of any Final Rule in Docket No. RM16–6–000. 47. In particular, the proposed revisions to the pro forma LGIA and pro forma SGIA would require new large and small generating facilities to install, maintain, and operate a functioning governor or equivalent controls, which the Commission proposes to define as the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the generating facility’s real power output in accordance with the proposed maximum droop and deadband parameters and in the direction needed to correct frequency deviations. The Commission seeks comment on this proposal. 48. The Commission also proposes to require new large and small generating facilities to install, maintain and operate governor or equivalent controls with the ability to operate with a maximum 5 percent droop and ±0.036 Hz deadband parameter, consistent with NERC’s recommended guidance. As noted above, the Commission sought comment in the NOI on whether NERC’s recommended guidance for governor settings related to droop and deadband should be included in the pro forma LGIA and pro forma SGIA, and numerous commenters agreed stating that NERC’s Guideline provides a sound baseline.125 Therefore, the Commission preliminarily finds that a maximum droop setting of 5 percent and deadband setting of ±0.036 Hz are appropriate to include in the pro forma LGIA and pro forma SGIA as interconnection requirements for new generating facilities. The Commission notes that these proposed requirements are minimum requirements; therefore, if a new generating facility elects, in coordination with its transmission provider, to operate in a more responsive mode by using lower droop or tighter deadband settings, nothing in these requirements would prohibit it from doing so.126 The Commission seeks comment on these proposed 125 See e.g., Bonneville Comments at 7; California Cities Comments at 2; IEEE–PES Comments at 2; Indicated ISOs/RTOs Comments at 4; MISO Comments at 4; WIRAB Comments at 7. 126 Moreover, the Commission proposes that nothing in these requirements would prohibit the implementation of asymmetrical droop settings (i.e., different droop settings for under-frequency and over-frequency conditions), provided that each segment has a droop value of no more than 5 percent. PO 00000 Frm 00021 Fmt 4702 Sfmt 4702 requirements for droop and deadband settings. 49. The Commission also proposes to prohibit all new large and small generating facilities from taking any action that would inhibit the provision of primary frequency response, except under certain conditions as discussed below. The lack of coordination between governor and plant-level control systems can result in premature withdrawal of primary frequency response by allowing additional plant control systems to reverse the action of the governor to return the unit to operating at a pre-selected target setpoint.127 NERC’s Guideline explains that ‘‘in order to provide sustained primary frequency response, it is essential that the prime mover governor, plant controls and remote plant controls are coordinated.’’ 128 Accordingly, the Commission proposes to require new generating facilities that respond to frequency deviations to not inhibit primary frequency response, such as by coordinating plant-level, outer-loop control equipment with the governor or equivalent controls, except under certain operational constraints including, but not limited to, ambient temperature limitations, outages of mechanical equipment, or regulatory requirements. The Commission also proposes to require new generating facilities to respond to frequency deviations without undue delay and to sustain the response until at least system frequency returns to a stable value within the governor’s deadband setting. The Commission believes this proposed requirement for sustained response is consistent with the current requirements of PJM and ISO–NE as well as similar OATT revisions recently implemented by CAISO.129 The Commission seeks comment on the proposed requirements for sustained response. In particular, the Commission seeks comment on whether these provisions will be sufficient to prevent plant-level (i.e., outer-loop) controls from inhibiting primary frequency response. 50. Regarding droop settings, in its comments to the NOI, MISO proposed that a linear droop should be available between 59 to 61 Hz.130 The 127 NERC Frequency Response Initiative Report at 31. See also NOI, 154 FERC ¶ 61,117 at P 49 (stating that primary frequency response withdrawal ‘‘has the potential to degrade the overall response of the Interconnection and result in a frequency that declines below the original nadir’’). 128 NERC Primary Frequency Control Guideline at 4. 129 See, e.g., ISO–NE Operating Procedure OP–14 and PJM Manual 14D. See also CAISO, 156 FERC ¶ 61,182 at PP 10–12 and 17. 130 MISO Comments at 4. E:\FR\FM\25NOP1.SGM 25NOP1 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules ehiers on DSK5VPTVN1PROD with PROPOSALS Commission believes that this is reasonable because it would allow for new generating facilities that remain connected during frequency deviations to provide a proportional response within this range of frequencies. Accordingly, the Commission proposes to require the droop parameter to be based on the nameplate capability of the unit and linear in operating range between 59 to 61 Hz. The Commission seeks comment on these proposed requirements for droop settings. 51. Several NOI commenters expressed concern about possible generic headroom requirements 131 that could result in significant opportunity costs.132 The Commission clarifies that nothing in these proposed reforms will impose a generic headroom requirement for new generating facilities or affect the unit commitment and dispatch decisions of balancing authorities. Therefore, if a generating facility that is subject to these proposed requirements has been dispatched by its balancing authority to a set-point at which there is no available operating range to increase or decrease its output in response to frequency deviations, it would not be in violation of the proposed requirements in regards to providing sustained response. The Commission believes that the reliability benefits from the proposed modifications to the pro forma LGIA and pro forma SGIA do not require imposing additional costs that would result from a generic headroom requirement. The Commission also agrees with NOI commenters regarding the unique operating characteristics and regulatory requirements of nuclear generating facilities regulated by the Nuclear Regulatory Commission, and therefore proposes to exempt such generating facilities from the proposed reforms.133 The Commission seeks comment on the proposal to not impose a generic headroom requirement and to not apply the new requirements to nuclear generating facilities. 52. In light of the above discussion, the Commission proposes to modify sections 9.6 and 9.6.2.1 of the pro forma LGIA and add new sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.3 as follows: 131 A generic headroom requirement would require generating facilities to operate below maximum output at all times to ensure sufficient ability to increase their real power output in response to under-frequency conditions. 132 See, e.g., Apex Comments at 7; Solar City Comments at 1; AWEA Comments at 6. 133 See, e.g., Nuclear Energy Institute Comments at 1, 4; MISO TOs Comments at 7. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 9.6 Reactive Power and Primary Frequency Response 9.6.2.1 Voltage Regulators. Whenever the Large Generating Facility is operated in parallel with the Transmission System and voltage regulators are capable of operation, Interconnection Customer shall operate the Large Generating Facility with its voltage regulators in automatic operation. If the Large Generating Facility’s voltage regulators are not capable of such automatic operation, Interconnection Customer shall immediately notify Transmission Provider’s system operator, or its designated representative, and ensure that such Large Generating Facility’s reactive power production or absorption (measured in MVARs) are within the design capability of the Large Generating Facility’s generating unit(s) and steady state stability limits. Interconnection Customer shall not cause its Large Generating Facility to disconnect automatically or instantaneously from the Transmission System or trip any generating unit comprising the Large Generating Facility for an under or over frequency condition unless the abnormal frequency condition persists for a time period beyond the limits set forth in ANSI/IEEE Standard C37.106, or such other standard as applied to other generators in the Control Area on a comparable basis. 9.6.4 Primary Frequency Response. Interconnection Customer shall ensure the primary frequency response capability of its Large Generating Facility by installing, maintaining, and operating a functioning governor or equivalent controls. The term ‘‘functioning governor or equivalent controls’’ as used herein shall mean the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the Large Generating Facility’s real power output in accordance with the droop and deadband parameters and in the direction needed to correct frequency deviations. Interconnection Customer is required to install a governor or equivalent controls with the capability of operating with a maximum 5 percent droop and ±0.036 Hz deadband. The droop characteristic shall be based on the nameplate capacity of the Large Generating Facility, and shall be linear in the range of 59 to 61 Hz. The deadband parameter shall be the range of frequencies above and below nominal (60 Hz) in which the governor or equivalent controls is not expected to adjust the Large Generating Facility’s real power output in response to frequency deviations. Interconnection Customer shall notify Transmission Provider that the primary frequency response capability of the Large Generating Facility has been tested and confirmed during commissioning. Once Interconnection Customer has synchronized the Large Generating Facility with the Transmission System, Interconnection Customer shall operate the Large Generating Facility consistent with provisions specified in Sections 9.6.4.1 and 9.6.4.2 of this Agreement. The primary frequency response requirements contained herein shall apply to both synchronous and non-synchronous Large Generating Facilities. Nothing in Sections 9.6.4, 9.6.4.1 and 9.6.4.2 shall PO 00000 Frm 00022 Fmt 4702 Sfmt 4702 85185 require the Large Generating Facility to operate above its minimum operating limit or below its maximum operating limit, or otherwise alter its dispatch to have headroom to provide primary frequency response. 9.6.4.1 Governor or Equivalent Controls. Whenever the Large Generating Facility is operated in parallel with the Transmission System, Interconnection Customer shall operate the Large Generating Facility with its governor or equivalent controls in service and responsive to frequency. Interconnection Customer shall, in coordination with Transmission Provider, set the deadband parameter to a maximum of ±0.036 Hz and set the droop parameter to a maximum of 5 percent. Interconnection Customer shall be required to provide the status and settings of the governor or equivalent controls to Transmission Provider upon request. If Interconnection Customer needs to operate the Large Generating Facility with its governor or equivalent controls not in service, Interconnection Customer shall immediately notify Transmission Provider’s system operator, or its designated representative. Interconnection Customer shall make Reasonable Efforts to return its governor or equivalent controls into service as soon as practicable. 9.6.4.2 Sustained Response. Interconnection Customer shall ensure that the Large Generating Facility’s real power response to sustained frequency deviations outside of the deadband setting is provided without undue delay, and ensure that the response is not inhibited, except under certain operational constraints including, but not limited to, ambient temperature limitations, outages of mechanical equipment, or regulatory requirements. The Large Generating Facility shall sustain the real power response at least until system frequency returns to a stable value within the deadband setting of the governor or equivalent controls. 9.6.4.3 Exemptions. Large Generating Facilities that are regulated by the United States Nuclear Regulatory Commission shall be exempt from Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this Agreement. 53. Similarly, the Commission proposes to modify section 1.8 of the pro forma SGIA and add new sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 as follows: 1.8 Reactive Power and Primary Frequency Response 1.8.4 Primary Frequency Response. Interconnection Customer shall ensure the primary frequency response capability of its Small Generating Facility by installing, maintaining, and operating a functioning governor or equivalent controls. The term ‘‘functioning governor or equivalent controls’’ as used herein shall mean the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the Small Generating Facility’s real power output in accordance with the droop and deadband parameters and in the direction needed to correct frequency deviations. Interconnection Customer is required to install a governor or E:\FR\FM\25NOP1.SGM 25NOP1 ehiers on DSK5VPTVN1PROD with PROPOSALS 85186 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules equivalent controls with the capability of operating with a maximum 5 percent droop and ±0.036 Hz deadband. The droop characteristic shall be based on the nameplate capacity of the Small Generating Facility, and shall be linear in the range of 59 to 61 Hz. The deadband parameter shall be the range of frequencies above and below nominal (60 Hz) in which the governor or equivalent controls is not expected to adjust the Small Generating Facility’s real power output in response to frequency deviations. Interconnection Customer shall notify Transmission Provider that the primary frequency response capability of the Small Generating Facility has been tested and confirmed during commissioning. Once Interconnection Customer has synchronized the Small Generating Facility with the Transmission System, Interconnection Customer shall operate the Small Generating Facility consistent with the provisions specified in Sections 1.8.4.1 and 1.8.4.2 of this Agreement. The primary frequency response requirements contained herein shall apply to both synchronous and nonsynchronous Small Generating Facilities. Nothing in Sections 1.8.4, 1.8.4.1 and 1.8.4.2 shall require the Small Generating Facility to operate above its minimum operating limit, below its maximum operating limit, or otherwise alter its dispatch to have headroom to provide primary frequency response. 1.8.4.1 Governor or Equivalent Controls. Whenever the Small Generating Facility is operated in parallel with the Transmission System, Interconnection Customer shall operate the Small Generating Facility with its governor or equivalent controls in service and responsive to frequency. Interconnection Customer shall, in coordination with Transmission Provider, set the deadband parameter to a maximum of ±0.036 Hz and set the droop parameter to a maximum of 5 percent. Interconnection Customer shall be required to provide the status and settings of the governor or equivalent controls to Transmission Provider upon request. If Interconnection Customer needs to operate the Small Generating facility with its governor or equivalent controls not in service, Interconnection Customer shall immediately notify Transmission Provider’s system operator, or its designated representative. Interconnection Customer shall make Reasonable Efforts to return its governor or equivalent controls into service as soon as practicable. 1.8.4.2 Sustained Response. Interconnection Customer shall ensure that the Small Generating Facility’s real power response to sustained frequency deviations outside of the deadband setting is provided without undue delay, and ensure that the response is not inhibited, except under certain operational constraints including, but not limited to, ambient temperature limitations, outages of mechanical equipment, or regulatory requirements. The Small Generating Facility shall sustain the real power response at least until system frequency returns to a stable value within the deadband setting of the governor or equivalent controls. 1.8.4.3 Exemptions. Small Generating Facilities that are regulated by the United VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 States Nuclear Regulatory Commission shall be exempt from Sections 1.8.4, 1.8.4.1, 1.8.4.2 of this Agreement. 54. The Commission proposes to apply the primary frequency response requirements to any new large or small generating facility that executes or requests the unexecuted filing of a LGIA or SGIA on or after the effective date of any Final Rule issued in this proceeding. In addition, the Commission proposes to apply the requirements to any large or small generating facility that has an executed or has requested the filing of an unexecuted LGIA or SGIA as of the effective date of any Final Rule in Docket No. RM16–6–000, but that takes any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date of any Final Rule in Docket No. RM16–6–000. The Commission seeks comment on the proposed effective date including whether applying these requirements to existing generating facilities that take any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date of any Final Rule in Docket No. RM16–6–000 would be unduly burdensome. 55. The Commission does not propose in this NOPR to require that the interconnection customer receive any compensation for these proposed requirements. The Commission has previously accepted changes to transmission provider tariffs that similarly required interconnection customers to install primary frequency response capability or that established specified governor settings, without requiring any accompanying compensation.134 While the Commission has not required compensation for similar requirements in the past, it clarifies that nothing in this NOPR is meant to prohibit a public utility from filing a proposal for primary frequency response compensation under FPA section 205, if it so chooses.135 B. Request for Comment 56. The Commission seeks comment on the proposed: (1) Requirements for new large and small generating facilities to install, maintain, and operate a governor or equivalent controls; (2) requirements for droop and deadband 134 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097, at n.58 (2015); CAISO, 156 FERC ¶ 61,182, at PP 10–12 and 17 (2016); New England Power Pool, 109 FERC ¶ 61,155 (2004), order on reh’g, 110 FERC ¶ 61,335 (2005). 135 16 U.S.C. 824d (2012). PO 00000 Frm 00023 Fmt 4702 Sfmt 4702 settings of 5 percent and ±0.036 Hz, respectively; (3) requirements for timely and sustained response; (4) requirement for droop parameters to be based on nameplate capability with a linear operating range of 59 to 61 Hz; (5) exemptions for new nuclear units; and (6) effective dates as discussed above. The Commission also seeks comment on its proposal to not impose a generic headroom requirement or mandate compensation related to the proposed reforms. 57. In the NOI, the Commission also sought comment on the performance of existing resources and whether primary frequency response requirements for these resources are warranted.136 At this time, the Commission proposes only to adopt the reforms included in this NOPR regarding newly interconnecting large and small generating facilities. However, the Commission seeks comment regarding whether the reforms proposed in this NOPR are sufficient to ensure adequate levels of primary frequency response, or whether additional reforms are needed. In particular, the Commission seeks comment on whether additional primary frequency response performance or capability requirements for existing resources are needed, and if so, whether the Commission should impose those requirements by: (1) Directing the development or modification of a reliability standard pursuant to section 215(d)(5) of the FPA; or (2) acting pursuant to section 206 of the FPA to require changes to the pro forma OATT. C. Proposed Compliance Procedures 58. The Commission proposes to require all public utility transmission providers to adopt the requirements of any Final Rule in Docket No. RM16–6– 000 as revisions to the LGIA and SGIA in their OATTs within 60 days after the publication of the Final Rule in the Federal Register. 59. Some public utility transmission providers may have provisions in their existing LGIAs and SGIAs that the Commission has found to be consistent with or superior to the pro forma LGIA and pro forma SGIA. Where these provisions would be modified by the Final Rule, public utility transmission providers must either comply with the Final Rule or demonstrate that these previously-approved variations continue to be consistent with or superior to the pro forma LGIA and pro forma SGIA as modified by the Final Rule. The Commission also proposes to permit appropriate entities to seek 136 NOI, E:\FR\FM\25NOP1.SGM 154 FERC ¶ 61,117 at PP 2, 46–52. 25NOP1 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules ‘‘independent entity variations’’ from the proposed revisions to the pro forma LGIA and pro forma SGIA.137 60. The Commission would assess whether each compliance filing satisfies the proposed requirements stated above and issue additional orders as necessary to ensure that each public utility transmission provider meets the requirements of the subsequent Final Rule. 61. The Commission also proposes that transmission providers that are not public utilities would have to adopt the requirements of this proposal and subsequent Final Rule as a condition of maintaining the status of their safe harbor tariff or otherwise satisfying the reciprocity requirement of Order No. 888.138 III. Information Collection Statement 62. The Paperwork Reduction Act (PRA) 139 requires each federal agency to seek and obtain Office of Management and Budget (OMB) approval before undertaking a collection of information directed to ten or more persons, or contained in a rule of general applicability. OMB’s regulations require the approval of certain information collection requirements imposed by agency rules.140 Upon approval of a collection of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of this proposal will not be penalized for failing to respond to this collection of information unless the collection of information displays a valid OMB control number. Transmission providers are subject to the proposed revisions to the pro forma LGIA and SGIA. 63. In this NOPR, the Commission proposes to amend its pro forma LGIA and pro forma SGIA in accordance with section 35.28(f)(1) of its regulations.141 The proposed revisions to the pro forma LGIA and pro forma SGIA would require new large and small generating facilities to install, maintain, and operate a functioning governor or equivalent controls which the Commission proposes to define as the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the generating facility’s real power output in accordance with the proposed maximum droop and dead band parameters and in the direction needed to correct frequency deviations. The NOPR proposes to require each public utility transmission provider to amend its pro forma LGIA and pro forma SGIA to require that all newly interconnecting large and small generating facilities, as well as all existing large and small generating facilities that take any action 85187 that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement, to adhere to the proposed requirements, on or after the effective date of any Final Rule issued in this proceeding. 64. The reforms in this NOPR would require filings of pro forma LGIAs and pro forma SGIAs with the Commission. The Commission anticipates the proposed reforms, once implemented, would not significantly change currently existing burdens on an ongoing basis. With regard to those public utility transmission providers that believe that they already comply with the proposed reforms in this NOPR, they could demonstrate their compliance in the filing required 60 days after publication of the Final Rule in the Federal Register. The Commission will submit the proposed reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.142 The Commission will use FERC– 516B as a temporary ‘‘placeholder’’ information collection number.143 Burden Estimate: 144 The Commission believes that the burden estimates below are representative of the average burden on respondents. The estimated burden and cost for the requirements contained in this NOPR follow.145 FERC 516B, IN NOPR IN RM16–6 Number of respondents 146 Annual number of responses per respondent Total number of responses Average burden (hours) & cost ($) per response Total annual burden hours & total annual cost ($) (1) (2) (1) * (2) = (3) (4) (3) * (4) = (5) LGIA & SGIA changes/revisions .................. 74 1 74 10 hours; $745.00 740 hours; $55,130.00. Total ...................................................... ........................ ........................ 74 ............................... 740 hours; $55,130.00. ehiers on DSK5VPTVN1PROD with PROPOSALS There are no maintenance cost, installation cost or any additional cost or requirements after year 1. Title: FERC–516B, Electric Rate Schedules and Tariff Filings. Action: Revision of currently approved collection of information. OMB Control No.: 1902–0286. Respondents for this Rulemaking: Businesses or other for profit and/or not-for-profit institutions. Frequency of Information: One-time during year 1. Necessity of Information: The Commission proposes to revise its regulations to require all newly interconnecting large and small 137 See, e.g., Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 827. 138 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,760–63. 139 44 U.S.C. 3501–3520 (2012). 140 5 CFR 1320.11 (2016). 141 18 CFR 35.28(f)(1) (2016). 142 44 U.S.C. 3507(d) (2012). 143 The reporting requirements in this NOPR would normally be included under FERC–516 (OMB Control No. 1902–0096). However, FERC–516 is pending review at OMB in an unrelated action. Because only one item per OMB Control No. can be pending OMB review at a time, the Commission is temporarily using the information collection number FERC–516B (OMB Control No. 1902–0286) to ensure timely submittal of this NOPR to OMB. 144 Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, disclose or provide information to or for a Federal agency, including: The time, effort, and financial resources necessary to comply with a collection of information that would be incurred by persons in the normal course of their activities (e.g., in compiling and maintaining business records) will be excluded from the ‘‘burden’’ if the agency demonstrates that the reporting, recordkeeping, or disclosure activities needed to comply are usual and customary. 145 For this information collection, the Commission staff estimates that industry is similarly situated in terms of hourly cost (wages plus benefits). Based on the Commission’s average cost (wages plus benefits) for 2016, the Commission is using $74.50/hour. 146 The NERC Compliance Registry lists 80 entities that administer a transmission tariff and provide transmission service. The Commission identifies only 74 as being subject to the proposed requirements because 6 are Canadian entities and are not under the Commission’s jurisdiction. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 PO 00000 Frm 00024 Fmt 4702 Sfmt 4702 E:\FR\FM\25NOP1.SGM 25NOP1 85188 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. To implement these requirements, the Commission proposes to revise the pro forma LGIA and the pro forma SGIA. Internal Review: The Commission has reviewed the proposed changes and has determined that the changes are necessary. These requirements conform to the Commission’s need for efficient information collection, communication, and management within the energy industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information collection requirements. 65. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: DataClearance@ferc.gov, Phone: (202) 502–8663, fax: (202) 273–0873. 66. Comments on the collection of information and the associated burden estimate in the proposed rule should be sent to the Commission in this docket and may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission], at the following email address: oira_ submission@omb.eop.gov. Please refer to OMB Control No. 1902–0286 in your submission. ehiers on DSK5VPTVN1PROD with PROPOSALS IV. Environmental Analysis 67. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.147 The Commission concludes that neither an Environmental Assessment or an Environmental Impact Statement is required for proposed revisions under section 380.4(a)(15) of the Commission’s regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the FPA relating to the filing of schedules containing all rates and charges for the transmission or sale of electric energy subject to the 147 Order No. 486, Regulations Implementing the National Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986–1990 ¶ 30,783 (1987). VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 Commission’s jurisdiction, plus the classification, practices, contracts and regulations that affect rates, charges, classifications, and services.148 The revisions proposed in this NOPR update and clarify the application of the Commission’s standard interconnection requirements to synchronous and nonsynchronous generators. Therefore, this NOPR falls within the categorical exemptions provided in the Commission’s regulations, and therefore neither an Environmental Assessment nor an Environmental Impact Statement is required. V. Regulatory Flexibility Act 68. The Regulatory Flexibility Act of 1980 (RFA) 149 generally requires a description and analysis of proposed rules that will have significant economic impact on a substantial number of small entities. The RFA does not mandate any particular outcome in a rulemaking. It only requires consideration of alternatives that are less burdensome to small entities and an agency explanation of why alternatives were rejected. 69. The Small Business Administration (SBA) revised its size standards (effective January 22, 2014) for electric utilities from a standard based on megawatt hours to a standard based on the number of employees, including affiliates. Under SBA’s standards, some transmission owners will fall under the following category and associated size threshold: Electric bulk power transmission and control, at 500 employees.150 70. The Commission estimates that the total number of transmission providers, both public and non-public, affected by this NOPR is 74.151 Of these, the Commission estimates that approximately 27.5 percent are small entities. The Commission estimates the average total cost to each of these entities will be minimal, requiring on average 10 hours, or $745.00. According to SBA guidance, the determination of significance of impact ‘‘should be seen as relative to the size of the business, the size of the competitor’s business, and the impact the regulation has on larger competitors.’’ 152 The Commission CFR 380.4(a)(15) (2015). U.S.C. 601–612 (2012). 150 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121 (Electric Bulk Power Transmission and Control). 151 The NERC Compliance Registry lists 80 entities that administer a transmission tariff and provide transmission service. The Commission identifies only 74 as being subject to the proposed requirements because 6 are Canadian entities and are not under the Commission’s jurisdiction. 152 U.S. Small Business Administration, A Guide for Government Agencies: How to Comply with the does not consider the estimated burden to be a significant economic impact. As a result, the Commission believes this NOPR would not have a significant economic impact on a substantial number of small entities. 71. The Commission estimates that the total annual number of new nonsynchronous interconnections per year for the first few years of potential implementation under this NOPR would be approximately 200, representing approximately 5,000 MW of installed capacity. Of these, the Commission estimates that the majority are small entities. The Commission estimates the average total cost to each of these entities will be minimal, requiring on average approximately $3,300 per MW of installed capacity. According to SBA guidance, the determination of significance of impact ‘‘should be seen as relative to the size of the business, the size of the competitor’s business, and the impact the regulation has on larger competitors.’’ The Commission does not consider the estimated burden to be a significant economic impact on these entities because the cost is relatively minimal compared to the average capital cost per MW for wind and solar PV generation.153 Additionally, the Commission does not believe that there will be substantial additional costs for new synchronous generators because synchronous generators already come equipped with governors that provide the capability to provide primary frequency response. Accordingly, the Commission believes that this NOPR would not have a significant economic impact on a substantial number of small entities. VI. Comment Procedures 72. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due January 24, 2017. Comments must refer to Docket No. RM16–6–000, and must include the commenter’s name, the organization they represent, if applicable, and their address in their comments. 148 18 149 5 PO 00000 Frm 00025 Fmt 4702 Sfmt 4702 Regulatory Flexibility Act, at 18 (May 2012), https:// www.sba.gov/sites/default/files/advocacy/rfaguide_ 0512_0.pdf. 153 LBNL estimates that capital cost per MW of installed wind capacity is $1,690,000. See LBNL 2015 Wind Market Report (Aug. 2016), https:// emp.lbl.gov/sites/all/files/2015windtechreport.final_.pdf). NREL estimates that the capital cost per MW of installed solar PV capacity is $1,770,000. See NREL U.S. Photovoltaic Prices and Cost Breakdowns (Sep. 2015), http:// www.nrel.gov/docs/fy15osti/64746.pdf. E:\FR\FM\25NOP1.SGM 25NOP1 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules 73. The Commission encourages comments to be filed electronically via the eFiling link on the Commission’s Web site at http://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing. 74. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426. 75. All comments will be placed in the Commission’s public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters. VII. Document Availability 76. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission’s Home Page (http:// www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 77. From the Commission’s Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for 85189 viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 78. User assistance is available for eLibrary and the Commission’s Web site during normal business hours from the Commission’s Online Support at (202) 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202)502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. By direction of the Commission. Issued: November 17, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. Appendix LIST OF COMMENTERS (DOCKET NO. RM16–6–000) AES Companies ................................................. APPA, et al ......................................................... AWEA ................................................................. Apex .................................................................... APS ..................................................................... Bonneville ........................................................... CAISO ................................................................. Chelan County .................................................... California Cities ................................................... EEI ...................................................................... EDP ..................................................................... EPRI .................................................................... EPSA, et al ......................................................... ELCON ................................................................ ESA ..................................................................... Grid Storage Consulting ..................................... Howard F. Illian ................................................... Idaho Power ........................................................ Indicated ISOs/RTOs .......................................... ehiers on DSK5VPTVN1PROD with PROPOSALS IEEE–P1547 Working Group .............................. IEEE–PES ........................................................... ITC, et al ............................................................. Manitoba ............................................................. Microgrids Resources Coalition .......................... MISO ................................................................... MISO TOs ........................................................... NARUC ............................................................... NRECA ............................................................... NERC .................................................................. North American Generator Forum ...................... Nuclear Energy Institute ..................................... PG&E .................................................................. Peak Reliability ................................................... PJM Utilities Coalition ......................................... Powerex .............................................................. Public Interest Organizations .............................. Ralph D. Masiello ............................................... SDG&E ............................................................... Solar City ............................................................ SoCal Edison ...................................................... Southern Company ............................................. Steel Producers .................................................. VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 AES Corporation/AES Energy Storage/Dayton Power and Light Company/Indianapolis Power and Light Company. American Public Power Association/Large Public Power Council/Transmission Access Policy Study Group. American Wind Energy Association. Apex Compressed Air Energy Storage. Arizona Public Service Company. Bonneville Power Administration. California Independent System Operator. Chelan County Public Utility District. City of Anaheim/City of Azusa/City of Banning/City of Colton/City of Pasadena/City of Riverside. Edison Electric Institute. EDP Renewables North America. Electric Power Research Institute. Electric Power Supply Association/Independent Power Producers of New York/New England Power Generators Association/Western Power Trading Forum. Electricity Consumers Resource Council. Energy Storage Association. Grid Storage Consulting. Howard F. Illian Idaho Power Company. Independent Electricity System Operator/ISO New England/New York Independent System Operator/PJM Interconnection/Southwest Power Pool. Institute of Electrical and Electronics Engineers (IEEE) P1547 Standards Working Group. IEEE Power and Energy Society Technical Council. International Transmission Company/Michigan Electric Transmission Company/ITC Great Plains/ITC Midwest. Manitoba Hydro. Microgrids Resources Coalition. Midcontinent Independent System Operator. Midcontinent Independent System Operator Transmission Owners. National Association of Regulatory Utility Commissioners. National Rural Electric Cooperative Association. North American Electric Reliability Corporation. North American Generator Forum. Nuclear Energy Institute. Pacific Gas and Electric Company. Peak Reliability. PJM Utilities Coalition. Powerex Corp. Public Interest Organizations. Ralph D. Masiello. San Diego Gas & Electric Company. Solar City Corporation. Southern California Edison Company. Southern Company. Steel Producers. PO 00000 Frm 00026 Fmt 4702 Sfmt 4702 E:\FR\FM\25NOP1.SGM 25NOP1 85190 Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules LIST OF COMMENTERS (DOCKET NO. RM16–6–000)—Continued Tacoma Power .................................................... TVA ..................................................................... Tri-State Generation ........................................... Union of Concerned Scientists ........................... WIRAB ................................................................ FOR FURTHER INFORMATION CONTACT: [FR Doc. 2016–28321 Filed 11–23–16; 8:45 am] Concerning the regulations, Neil S. Sandhu or Linda S.F. Marshall at (202) 317–6700; concerning submissions of comments, the hearing, and/or being placed on the building access list to attend the hearing, Oluwafunmilayo (Funmi) Taylor at (202) 317–6901 (not toll-free numbers). SUPPLEMENTARY INFORMATION: BILLING CODE 6717–01–P DEPARTMENT OF THE TREASURY Internal Revenue Service 26 CFR Part 1 [REG–107424–12] RIN 1545–BK95 Update to Minimum Present Value Requirements for Defined Benefit Plan Distributions Internal Revenue Service (IRS), Treasury. ACTION: Notice of proposed rulemaking and notice of public hearing. AGENCY: This document contains proposed regulations providing guidance relating to the minimum present value requirements applicable to certain defined benefit pension plans. These proposed regulations would provide guidance on changes made by the Pension Protection Act of 2006 and would provide other modifications to these rules as well. These regulations would affect participants, beneficiaries, sponsors, and administrators of defined benefit pension plans. This document also provides a notice of a public hearing on these proposed regulations. DATES: Written or electronic comments must be received by February 23, 2017. Outlines of topics to be discussed at the public hearing scheduled for March 7, 2017, must be received by February 23, 2017. ADDRESSES: Send submissions to: CC:PA:LPD:PR (REG–107424–12), Room 5203, Internal Revenue Service, P.O. Box 7604, Ben Franklin Station, Washington, DC 20044. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to: CC:PA:LPD:PR (REG–107424– 12), Courier’s Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC, or sent electronically, via the Federal eRulemaking Portal at http://www.regulations.gov (IRS REG– 107424–12). The public hearing will be held in the IRS Auditorium, Internal Revenue Building, 1111 Constitution Avenue NW., Washington, DC. ehiers on DSK5VPTVN1PROD with PROPOSALS SUMMARY: VerDate Sep<11>2014 14:01 Nov 23, 2016 Jkt 241001 Tacoma Power. Tennessee Valley Authority. Tri-State Generation and Transmission Association. Union of Concerned Scientists. Western Interconnection Regional Advisory Body. Background Section 401(a)(11) of the Internal Revenue Code (Code) provides that, in order for a defined benefit plan to qualify under section 401(a), except as provided under section 417, in the case of a vested participant who does not die before the annuity starting date, the accrued benefit payable to such participant must be provided in the form of a qualified joint and survivor annuity. In the case of a vested participant who dies before the annuity starting date and who has a surviving spouse, a defined benefit plan must provide a qualified preretirement survivor annuity to the surviving spouse of such participant, except as provided under section 417. Section 411(d)(6)(B) provides that a plan amendment that has the effect of eliminating or reducing an early retirement benefit or a retirement-type subsidy, or eliminating an optional form of benefit, with respect to benefits attributable to service before the amendment is treated as impermissibly reducing accrued benefits. However, the last sentence of section 411(d)(6)(B) provides that the Secretary may by regulations provide that section 411(d)(6)(B) does not apply to a plan amendment that eliminates an optional form of benefit (other than a plan amendment that has the effect of eliminating or reducing an early retirement benefit or a retirement-type subsidy). Section 417(e)(1) provides that a plan may provide that the present value of a qualified joint and survivor annuity or a qualified preretirement survivor annuity will be immediately distributed if that present value does not exceed the amount that can be distributed without the participant’s consent under section 411(a)(11). Section 417(e)(2) provides that, if the present value of the qualified joint and survivor annuity or the PO 00000 Frm 00027 Fmt 4702 Sfmt 4702 qualified preretirement survivor annuity exceeds the amount that can be distributed without the participant’s consent under section 411(a)(11), then a plan may immediately distribute the present value of a qualified joint and survivor annuity or the qualified preretirement survivor annuity only if the participant and the spouse of the participant (or where the participant has died, the surviving spouse) consent in writing to the distribution. Section 417(e)(3)(A) provides that the present value shall not be less than the present value calculated by using the applicable mortality table and the applicable interest rate.1 Section 417(e)(3)(B) of the Code, as amended by section 302 of the Pension Protection Act of 2006 (PPA ’06), Public Law 109–280, 120 Stat. 780 (2006), provides that the term ‘‘applicable mortality table’’ means a mortality table, modified as appropriate by the Secretary, based on the mortality table specified for the plan year under section 430(h)(3)(A) (without regard to section 430(h)(3)(C) or (3)(D)). Section 417(e)(3)(C) of the Code, as amended by section 302 of PPA ‘06, provides that the term ‘‘applicable interest rate’’ means the adjusted first, second, and third segment rates applied under rules similar to the rules of section 430(h)(2)(C) of the Code for the month before the date of the distribution or such other time as the Secretary may prescribe by regulations. However, for purposes of section 417(e)(3), these rates are to be determined without regard to the segment rate stabilization rules of section 430(h)(2)(C)(iv). In addition, under section 417(e)(3)(D), these rates are to be determined using the average yields for a month, rather than the 24month average used under section 430(h)(2)(D). Section 411(a)(13) of the Code, as added by section 701(b) of PPA ‘06, provides that an ‘‘applicable defined benefit plan,’’ as defined by section 411(a)(13)(C), is not treated as failing to meet the requirements of section 417(e) 1 Under section 411(a)(11)(B), the same applicable mortality table and applicable interest rate are used for purposes of determining whether the present value of a participant’s nonforfeitable accrued benefit exceeds the maximum amount that can be immediately distributed without the participant’s consent. E:\FR\FM\25NOP1.SGM 25NOP1

Agencies

[Federal Register Volume 81, Number 227 (Friday, November 25, 2016)]
[Proposed Rules]
[Pages 85176-85190]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-28321]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM16-6-000]


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

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes 
to revise its regulations to require all newly interconnecting large 
and small generating facilities, both synchronous and non-synchronous, 
to install and enable primary frequency response capability as a 
condition of interconnection. To implement these requirements, the 
Commission proposes to revise the pro forma Large Generator 
Interconnection Agreement (LGIA) and the pro forma Small Generator 
Interconnection Agreement (SGIA). The proposed changes are designed to 
address the increasing impact of the evolving generation resource mix 
and to ensure that the relevant provisions of the pro forma LGIA and 
pro forma SGIA are just, reasonable, and not unduly discriminatory or 
preferential. The Commission also seeks comment on whether its 
proposals in this Notice of Proposed Rulemaking are sufficient at this 
time to ensure adequate levels of primary frequency response, or 
whether additional reforms are needed.

DATES: Comments are due January 24, 2017.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways:
     Electronic Filing through http://www.ferc.gov. Documents 
created electronically using word processing software should be filed 
in native applications or print-to-PDF format and not in a scanned 
format.
     Mail/Hand Delivery: Those unable to file electronically 
may mail or hand-deliver comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT: 

Jomo Richardson (Technical Information), Office of Electric 
Reliability, Federal Energy Regulatory Commission, 888 First Street 
NE., Washington, DC 20426, (202) 502-6281, Jomo.Richardson@ferc.gov.
Mark Bennett (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, (202) 502-8524, Mark.Bennett@ferc.gov.

SUPPLEMENTARY INFORMATION: 
    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy 
Regulatory Commission (Commission) proposes to modify the pro forma 
Large Generator Interconnection Agreement (LGIA) and the pro forma 
Small Generator Interconnection Agreement (SGIA), pursuant to its 
authority under section 206 of the Federal Power Act (FPA) to ensure 
that rates, terms and conditions of jurisdictional service remain just 
and reasonable and not unduly discriminatory or preferential.\1\ The 
proposed modifications would require all new large and small generating 
facilities, including both synchronous and non-synchronous, 
interconnecting with a LGIA or SGIA to install, maintain and operate 
equipment capable of providing primary frequency response as a 
condition of interconnection. The Commission also proposes to establish 
certain operating requirements, including maximum droop and deadband 
parameters in the pro forma LGIA and pro forma SGIA. The Commission 
does not propose to apply these requirements to generating facilities 
regulated by the Nuclear Regulatory Commission. In addition, the 
Commission does not propose in these reforms to impose a headroom 
requirement for new generating facilities. The Commission also does not 
propose to mandate that new generating facilities receive any 
compensation for complying with the proposed requirements in this NOPR.
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824e (2012).
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    2. The proposed revisions address the Commission's concerns that 
the existing pro forma LGIA contains limited primary frequency response 
requirements that apply only to synchronous generating facilities and 
do not account for recent technological advancements that have enabled 
new non-synchronous generating facilities to now have primary frequency 
response capabilities. Further, the Commission believes that it may be 
unduly discriminatory or preferential to impose primary frequency 
response requirements only on new large generating facilities but not 
on new small generating facilities, and the reforms proposed here would 
impose

[[Page 85177]]

comparable primary frequency response requirements on both new large 
and small generating facilities.
    3. In addition, and as discussed below in paragraph 57, the 
Commission also seeks comment on whether its proposals in this NOPR are 
sufficient at this time to ensure adequate levels of primary frequency 
response, or whether additional reforms are needed.
    4. The Commission seeks comment on the proposed reforms and 
requests for comment sixty (60) days after publication of this NOPR in 
the Federal Register.

I. Background

A. Frequency Response

    5. Reliable operation of an Interconnection \2\ depends on 
maintaining frequency within predetermined boundaries above and below a 
scheduled value, which is 60 Hertz (Hz) in North America. Changes in 
frequency are caused by changes in the balance between load and 
generation, such as the sudden loss of a large generator or a large 
amount of load. If frequency deviates too far above or below its 
scheduled value, it could potentially result in under frequency load 
shedding (UFLS), generation tripping, or cascading outages.\3\
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    \2\ An Interconnection is a geographic area in which the 
operation of the electric system is synchronized. In the continental 
United States, there are three Interconnections, namely the Eastern, 
Texas, and Western Interconnections.
    \3\ UFLS is designed for use in extreme conditions to stabilize 
the balance between generation and load. Under frequency protection 
schemes are drastic measures employed if system frequency falls 
below a specified value. See Automatic Underfrequency Load Shedding 
and Load Shedding Plans Reliability Standards, Notice of Proposed 
Rulemaking, FERC Stats. & Regs. ] 32,682, at PP 4-10 (2011) (Order 
No. 763 NOPR) at PP 4-10.
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    6. Mitigation of frequency deviations after the sudden loss of 
generation or load is driven by three primary factors: inertial 
response, primary frequency response, and secondary frequency 
response.\4\ Primary frequency response actions begin within seconds 
after system frequency changes and are mostly provided by the automatic 
and autonomous actions (i.e., outside of system operator control) of 
turbine-governors, while some response is provided by frequency 
responsive loads.\5\ Primary frequency response actions are intended to 
arrest abnormal frequency deviations and ensure that system frequency 
remains within acceptable bounds. An important goal for system planners 
and operators is for the frequency nadir,\6\ during large disturbances, 
to remain above the first stage of UFLS set points within an 
Interconnection.
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    \4\ In the Notice of Inquiry issued in Docket No. RM16-6-000 on 
Feb. 8, 2016, the Commission provided detailed discussion of how 
inertia, primary frequency response, and secondary frequency 
response interact to mitigate frequency deviations. Essential 
Reliability Services and the Evolving Bulk-Power System--Primary 
Frequency Response, 154 FERC ] 61,117, at PP 3-7 (2016) (NOI). See 
also Use of Frequency Response Metrics to Assess the Planning and 
Operating Requirements for Reliable Integration of Variable 
Renewable Generation, Lawrence Berkeley National Laboratory, at 13-
14 (Dec. 2010), http://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf 
(LBNL 2010 Report).
    \5\ NOI, 154 FERC ] 61,117 at P 6. The Commission also noted 
that regulation service is different than primary frequency response 
because generating facilities that provide regulation respond to 
automatic generation control signals and regulation service is 
centrally coordinated by the system operator, whereas primary 
frequency response service, in contrast, is autonomous and is not 
centrally coordinated. Schedule 3 of the pro forma Open Access 
Transmission Tariff (OATT) bundles these different services 
together, despite their differences. See Id. n.66.
    \6\ The point at which the frequency decline is arrested 
(following the sudden loss of generation) is called the frequency 
nadir, and represents the point at which the net primary frequency 
response (real power) output from all generating units and the 
decrease in power consumed by the load within an Interconnection 
matches the net initial loss of generation (in megawatts (MW)).
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    7. Frequency response is a measure of an Interconnection's ability 
to arrest and stabilize frequency deviations following the sudden loss 
of generation or load, and is affected by the collective responses of 
generation and load throughout the Interconnection. When considered in 
aggregate, the primary frequency response provided by generators within 
an Interconnection has a significant impact on the overall frequency 
response. NERC Reliability Standard BAL-003-1.1 defines the amount of 
frequency response needed from balancing authorities \7\ to maintain 
Interconnection frequency within predefined bounds and includes 
requirements for the measurement and provision of frequency 
response.\8\ While NERC Reliability Standard BAL-003-1.1 establishes 
requirements for balancing authorities, it does not include any 
requirements for individual generator owners or operators.\9\
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    \7\ NERC's Glossary of Terms defines a balancing authority as 
``(t)he responsible entity that integrates resource plans ahead of 
time, maintains load-interchange-generation balance within a 
balancing authority area, and supports Interconnection frequency in 
real time.''
    \8\ Frequency Response and Frequency Bias Setting Reliability 
Standard, Order No. 794, 146 FERC ] 61,024 (2014).
    \9\ The Commission has also accepted Regional Reliability 
Standard BAL-001-TRE-01 (Primary Frequency Response in the ERCOT 
Region) as mandatory and enforceable, which does establish 
requirements for generator owners and operators with respect to 
governor control settings and the provision of primary frequency 
response within the Electric Reliability Council of Texas (ERCOT) 
region. North American Electric Reliability Corporation, 146 FERC ] 
61,025 (2014).
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    8. Unless otherwise required by tariffs or interconnection 
agreements, generator owners and operators can independently decide 
whether units are configured to provide primary frequency response.\10\ 
The magnitude and duration of a generator's response to frequency 
deviations is generally determined by the settings of the unit's 
governor \11\ (or equivalent controls) and other plant level (e.g., 
``outer-loop'') control systems. In particular, the governor's droop 
and deadband settings have a significant impact on the unit's provision 
of primary frequency response. In addition, plant-level or ``outer-
loop'' controls, unless properly configured, can override or nullify a 
generator's governor response and return the unit to operate at a 
scheduled pre-disturbance megawatt set-point.\12\ In 2010, NERC 
conducted a survey of generator owners and operators and found that 
only approximately 30 percent of generators in the Eastern 
Interconnection provided primary frequency response, and that only 
approximately 10 percent of generators provided sustained primary 
frequency response.\13\ This suggests that many generators within the 
Interconnection disable or otherwise set their governors or outer-loop 
controls such that they provide little to no primary frequency 
response.\14\
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    \10\ See NOI, 154 FERC ] 61,117 at PP 18-19.
    \11\ A governor is an electronic or mechanical device that 
implements primary frequency response on a generator via a droop 
parameter. Droop refers to the variation in real power (MW) output 
due to variations in system frequency and is typically expressed as 
a percentage (e.g., 5 percent droop). Droop reflects the amount of 
frequency change from nominal (e.g., 5 percent of 60 Hz is 3 Hz) 
that is necessary to cause the main prime mover control mechanism of 
a generating facility to move from fully closed to fully open. A 
governor also has a deadband parameter which establishes a minimum 
frequency deviation (e.g., 0.036 Hz) from nominal that 
must be exceeded in order for the governor to act.
    \12\ For more discussion on ``premature withdrawal'' of primary 
frequency response, see NOI, 154 FERC ] 61,117 at PP 49-50.
    \13\ See NERC Frequency Response Initiative Report: The 
Reliability Role of Frequency Response (Oct. 2012), http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf 
(NERC Frequency Response Initiative Report) at 95.
    \14\ However, as noted below, some commenters note that nuclear 
generating units are restricted by their U.S. Nuclear Regulatory 
Commission operating licenses regarding the provision of primary 
frequency response.
---------------------------------------------------------------------------

    9. Declining frequency response performance has been an industry 
concern for many years. NERC, in conjunction with EPRI, initiated its 
first examination of declining frequency response and governor response 
in 1991.\15\ More recently, as noted in the

[[Page 85178]]

NOI, while the three U.S. Interconnections currently exhibit adequate 
frequency response performance above their Interconnection Frequency 
Response Obligations,\16\ there has been a significant decline in the 
frequency response performance of the Western and Eastern 
Interconnections.\17\
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    \15\ NERC Frequency Response Initiative Report at 22.
    \16\ The Interconnection Frequency Response Obligations are 
established by NERC and are designed to require sufficient frequency 
response for each Interconnection (i.e., the Eastern, ERCOT, Quebec 
and Western Interconnections) to arrest frequency declines even for 
severe, but possible, contingencies.
    \17\ NOI, 154 FERC ] 61,117 at P 20.
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B. Prior Commission Actions

    10. In Order Nos. 2003 \18\ and 2006,\19\ the Commission adopted 
standard procedures for the interconnection of large and small 
generating facilities, including the development of standardized pro 
forma generator interconnection agreements and procedures. The 
Commission required public utility transmission providers \20\ 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.\21\
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    \18\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003), 
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160, 
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171 
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ] 
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 
U.S. 1230 (2008).
    \19\ Standardization of Small Generator Interconnection 
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ] 
31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs. ] 
31,196 (2005), order granting clarification, Order No. 2006-B, FERC 
Stats. & Regs. ] 31,221 (2006).
    \20\ A public utility is a utility that owns, controls, or 
operates facilities used for transmitting electric energy in 
interstate commerce, as defined by the FPA. See 16 U.S.C. 824(e) 
(2012). A non-public utility that seeks voluntary compliance with 
the reciprocity condition of an OATT may satisfy that condition by 
filing an OATT, which includes a LGIA and SGIA. See Order No. 2003, 
FERC Stats. & Regs. ] 31,146, at PP 840-845.
    \21\ E.g., Small Generator Interconnection Agreements and 
Procedures, Order No. 792, 145 FERC ] 61,159 (2013), clarifying, 
Order No. 792-A, 146 FERC ] 61,214 (2014); Reactive Power 
Requirements for Non-Synchronous Generation, Order No. 827, 81 FR 
40,793 (Jun. 23, 2016), 155 FERC ] 61,277 (2016); Requirements for 
Frequency and Voltage Ride Through Capability of Small Generating 
Facilities, Order No. 828, 81 FR 50,290 (Aug. 1, 2016), 156 FERC ] 
61,062 (2016).
---------------------------------------------------------------------------

    11. As relevant here, the pro forma LGIA and pro forma SGIA are 
largely silent on any requirements with respect to primary frequency 
response. In particular, the only requirement in the pro forma LGIA or 
pro forma SGIA related to primary frequency response is contained 
within current Article 9.6.2.1 of the pro forma LGIA (Governors and 
Regulators), which provides that if speed governors are installed, they 
should be operated in automatic mode.\22\ A speed governor implements 
the primary frequency response provided by a synchronous generating 
facility; however, Article 9.6.2.1 does not address governor settings 
or plant-level controls, which also affect the ability of a generating 
facility to provide primary frequency response. In addition, Article 
9.6.2.1 does not require the installation of the necessary equipment 
for frequency response capability (i.e., governors or equivalent 
controls). Finally, the pro forma SGIA does not contain any provisions 
related to primary frequency response.
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    \22\ Article 9.6.2.1 of the pro forma LGIA.
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C. Efforts To Evaluate the Impacts of the Changing Resource Mix

    12. The Commission's pro forma generator interconnection agreements 
and procedures were developed at a time when traditional synchronous 
generating facilities with standard governor controls and large 
rotational inertia were the predominant sources of electricity 
generation. However, the nation's resource mix has undergone 
significant change since the issuance of Order Nos. 2003 and 2006. This 
transformation has been characterized by the retirement of baseload, 
synchronous generating facilities and the integration of more 
distributed generation, demand response, and natural gas generating 
facilities, and the rapid expansion of non-synchronous variable energy 
resources (VERs) such as wind and solar.\23\ For example, the U.S. 
Energy Information Administration (EIA) has observed that the U.S. 
added approximately 13 gigawatts (GW) of wind, 6.2 GW of utility scale 
solar photovoltaic (PV), and 3.6 GW of distributed solar PV generating 
facilities in 2014 and 2015.\24\ Conversely, NERC has reported \25\ 
that almost 42 GW of synchronous generating facilities (e.g., coal, 
nuclear, and natural gas) have retired between 2011 and 2014, and the 
EIA recently reported that nearly 14 GW of coal and 3 GW of natural gas 
generating facilities retired in 2015.\26\
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    \23\ The term VER is defined as a device for the production of 
electricity that is characterized by an energy source that: (1) Is 
renewable; (2) cannot be stored by the facility owner or operator; 
and (3) has variability that is beyond the control of the facility 
owner or operator. See, e.g., Integration of Variable Energy 
Resources, Order No. 764, FERC Stats. & Regs. ] 31,331, at P 210 
(2012).
    \24\ See, U.S. electric generation capacity additions, 2015 vs. 
2014, EIA (March 2016), https://www.eia.gov/todayinenergy/detail.php?id=25492.
    \25\ See NERC 2015 LTRA (Dec. 2015), http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015LTRA%20-%20Final%20Report.pdf.
    \26\ See Electricity generating capacity retired in 2015 by fuel 
and technology, EIA (May 2016), http://www.eia.gov/todayinenergy/detail.php?id=25272.
---------------------------------------------------------------------------

    13. While technological advancements have enabled wind and solar 
generating facilities to now have the ability to provide primary 
frequency response, this functionality has not historically been a 
standard feature that was included and enabled on non-synchronous 
generating facilities. Moreover, wind and solar generating facilities 
typically operate at their maximum operating output, leaving no 
capacity (or ``headroom'') \27\ to provide primary frequency response 
during under-frequency conditions.
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    \27\ Headroom refers to the difference between the current 
operating point of a generator and its maximum operating capability, 
and represents the potential amount of additional energy that can be 
provided by the generating facility in real-time.
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    14. Given the changes in the resource mix and concerns about the 
significant decline in frequency response for the Eastern and Western 
Interconnections,\28\ NERC has undertaken several initiatives to 
evaluate the impacts of the changing resource mix, particularly with 
respect to primary frequency response. For example, in 2014, NERC 
initiated the Essential Reliability Services Task Force (Task Force) to 
analyze and better understand the impacts of the changing resource mix 
and develop technical assessments of essential reliability 
services.\29\ The Task Force focused on three essential reliability 
services: Frequency support, ramping capability, and voltage 
support.\30\ The Task Force considered the seven ancillary

[[Page 85179]]

services \31\ adopted by the Commission in Order Nos. 888 \32\ and 890 
\33\ as a subset of the essential reliability services that may need to 
be augmented by additional services as the Bulk-Power System \34\ 
characteristics change.
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    \28\ See NERC Frequency Response Initiative Industry Advisory--
Generator Governor Frequency Response, at slide 10 (Apr. 2015), 
http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. (NERC 
2015 Frequency Response Webinar). See also LBNL 2010 Report at pp 
xiv-xv.
    \29\ Essential reliability services are referred to as elemental 
reliability building blocks from resources (generation and load) 
that are necessary to maintain the reliability of the Bulk-Power 
System. See Essential Reliability Services Task Force Scope 
Document, at 1 (Apr. 2014), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
    \30\ Essential Reliability Services Task Force Measures Report, 
at 22 (Dec. 2015), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report%20-%20Final.pdf.
    \31\ The seven pro forma ancillary services set forth in Order 
Nos. 888 and 890 are: (1) Scheduling, System Control and Dispatch 
Service; (2) Reactive Supply and Voltage Control from Generation 
Sources Service; (3) Regulation and Frequency Response Service; (4) 
Energy Imbalance Service; (5) Operating Reserve--Spinning Reserve 
Service; (6) Operating Reserve--Supplemental Reserve Service; and 
(7) Generator Imbalance Service.
    \32\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g, 
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order 
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom. 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. 
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \33\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241, 
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261 
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), 
order on reh'g, Order No. 890-C, 126 FERC ] 61,228, order on 
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
    \34\ Section 215(a)(1) of the Federal Power Act (FPA), 16 U.S.C. 
824o(a)(1) (2012) defines ``Bulk-Power System'' as those 
``facilities and control systems necessary for operating an 
interconnected electric energy transmission network (or any portion 
thereof) [and] electric energy from generating facilities needed to 
maintain transmission system reliability.'' The term does not 
include facilities used in the local distribution of electric 
energy. See also Mandatory Reliability Standards for the Bulk-Power 
System, Order No. 693, FERC Stats. & Regs. ] 31,242 at P 76, order 
on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007).
---------------------------------------------------------------------------

    15. The Task Force did not recommend new reliability standards or 
specific actions to alter the existing suite of ancillary services; 
however, it did make certain conclusions with regard to primary 
frequency response. Specifically, the Task Force concluded that it is 
prudent and necessary to ensure that primary frequency response 
capabilities are present in the future generation resource mix, and 
recommended that all new generators support the capability to manage 
frequency.\35\
---------------------------------------------------------------------------

    \35\ Essential Reliability Services Task Force Measures Report 
at vi.
---------------------------------------------------------------------------

    16. In addition, as part of its ongoing analysis of primary 
frequency response concerns, NERC observed in a 2012 report that a 
number of generators implemented deadband settings that were so wide as 
to effectively defeat the ability to provide primary frequency 
response.\36\ The report also notes that many generators provide 
frequency response in the wrong direction during a disturbance.\37\ 
Additionally, in February 2015, NERC issued an Industry Advisory that 
determined that a significant portion of generators within the Eastern 
Interconnection use deadbands or governor control settings that either 
inhibit or prevent the provision of primary frequency response.\38\ 
Moreover, as noted in the NOI, NERC observed in 2015 that in many 
conventional steam plants, deadband settings exceed 0.036 
Hz, resulting in primary frequency response that is not sustained, and 
that the vast majority of the gas turbine fleet is not frequency 
responsive.\39\ In response to these issues and other concerns, NERC's 
Operating Committee approved a voluntary Primary Frequency Control 
Guideline that contains recommended settings for generator governors 
and other plant control systems, and encourages generators within the 
three U.S. Interconnections to provide sustained and effective primary 
frequency response.\40\ NERC's Guideline recommends maximum 5 percent 
droop and 0.036 Hz deadband settings for most generating 
facilities.\41\
---------------------------------------------------------------------------

    \36\ NERC Frequency Response Initiative Report at 92.
    \37\ NERC Frequency Response Initiative Report at 96-97.
    \38\ NERC Generator Governor Frequency Response Industry 
Advisory (Feb. 2015), http://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A-2015-02-05-01%20Generator%20Governor%20Frequency%20Response.pdf.
    \39\ NOI, 154 FERC ] 61,117 at P 50 (citing to NERC 2015 
Frequency Response Webinar at 1).
    \40\ See NERC Primary Frequency Control Guideline Final Draft 
(Dec. 2015), http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_final.pdf 
(NERC Primary Frequency Control Guideline). See also NERC Operating 
Committee Meeting Minutes (Jan. 2016), http://www.nerc.com/comm/OC/AgendasHighlightsMinutes/Operating%20Committee%20Minutes%20-%20Dec%2015-16%202015-Final.pdf.
    \41\ See NERC Primary Frequency Control Guideline at 7-9.
---------------------------------------------------------------------------

D. Initiatives by Individual Transmission Providers

    17. While the pro forma LGIA and pro forma SGIA do not provide 
specific requirements related to frequency response, some public 
utility transmission providers have included provisions related to 
primary frequency response in their LGIA, SGIA, OATTs, and/or business 
practice manuals.
    18. For example, ISO New England Inc. (ISO-NE) and New York 
Independent System Operator, Inc. (NYISO) have adopted provisions to 
their LGIAs that establish more specific requirements for governor 
operation.\42\ In particular, ISO-NE requires each generator within its 
region with a capability of 10 MW or more, including VERs, to operate 
with a functioning governor with specified droop and deadband settings, 
i.e., maximum 5 percent droop and 0.036 Hz deadband, and to 
also ensure that the provision of primary frequency response is not 
inhibited by the effects of outer-loop controls.\43\
---------------------------------------------------------------------------

    \42\ See ISO-NE, Transmission, Markets and Services Tariff, 
Schedule 22 Large Generator Interconnection Procedures (9.0.0), 
Appendix 6, 9.6.2.2; NYISO, NYISO Tariffs, NYISO OATT, 30.14 OATT 
Att. X Appendices (8.0.0), Appendix 6, 9.5.4.
    \43\ See ISO-NE's Operating Procedure No. 14 I (Governor 
Control), http://www.iso-ne.com/rules_proceds/operating/isone/op14/op14_rto_final.pdf.
---------------------------------------------------------------------------

    19. PJM Interconnection, L.L.C. (PJM) has implemented governor 
droop and deadband requirements, i.e., maximum 5 percent droop and 
0.036 Hz deadband, for all generating facilities excluding 
nuclear facilities with a gross plant/facility aggregate nameplate 
rating greater than 75 MVA.\44\ PJM also recently added new 
interconnection requirements requiring new non-synchronous generators 
to interconnect with ``enhanced inverters'' that have various 
capabilities including, among other things, the ability to provide 
primary frequency response.\45\
---------------------------------------------------------------------------

    \44\ PJM's pro forma interconnection agreements obligate 
interconnection customers within its region to abide by all PJM 
rules and procedures, including rules set forth in PJM's Manuals 
(See PJM Tariff, Attachment O 8.0). See also PJM Manual 14D 7.1.1 
(Generator Real-Power Control), http://www.pjm.com/~/media/
documents/manuals/m14d.ashx.
    \45\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58 
(2015).
---------------------------------------------------------------------------

    20. Midcontinent Independent System Operator, Inc. (MISO) requires 
governor operation as a condition for providing regulating reserve but 
does not require specific settings.\46\ Also, the Commission recently 
accepted tariff provisions proposed by the California Independent 
System Operator Corporation (CAISO) to require governor operation, 
specified droop and deadband settings, i.e., maximum 5 percent droop 
and 0.036 Hz deadband, and provisions for sustained primary 
frequency response for its participating generators that have 
traditional governor controls.\47\
---------------------------------------------------------------------------

    \46\ See MISO, FERC Electric Tariff, Module C, Energy and 
Operating Reserve Markets 39.2.1B (34.0.0) (``All Regulation 
Qualified Resources in the Day-Ahead Energy and Operating Reserve 
Market must be capable of automatically responding to and 
alleviating frequency deviations through a speed governor or similar 
device in accordance with the Applicable Reliability Standards.'').
    \47\ CAISO, 156 FERC ] 61,182, at PP 10-12 and 17 (2016).
---------------------------------------------------------------------------

E. Notice of Inquiry

1. Summary
    21. On February 18, 2016, the Commission issued the NOI to explore 
issues regarding essential reliability

[[Page 85180]]

services and the evolving Bulk-Power System.\48\ In particular, the 
Commission asked a broad range of questions on the need for reform of 
its rules and regulations regarding the provision of and compensation 
for primary frequency response. The Commission explained that there is 
a significant risk that, as conventional synchronous generating 
facilities retire or are displaced by increased numbers of VERs that do 
not typically contribute to system inertia or have primary frequency 
response capabilities, the net amount of frequency responsive 
generation online will be reduced.\49\ The Commission also explained 
that these developments and their potential impacts could challenge 
system operators in maintaining reliability.\50\ Further, the 
Commission explained that NERC Reliability Standard BAL-003-1.1 and the 
pro forma LGIA and pro forma SGIA do not specifically address a 
generator's ability to provide frequency response.\51\ The Commission 
noted, however, that while in previous years many 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.\52\
---------------------------------------------------------------------------

    \48\ NOI, 154 FERC ] 61,117.
    \49\ Id. P 12.
    \50\ Id. P 14.
    \51\ Id. P 41.
    \52\ Id. P 43.
---------------------------------------------------------------------------

    22. Accordingly, the Commission requested comments on three main 
sets of issues. First, the Commission sought comment on whether 
amendments to the pro forma LGIA and pro forma SGIA are warranted to 
require all new generating facilities, both synchronous and non-
synchronous, to have primary frequency response capabilities as a 
precondition of interconnection.\53\ Second, the Commission sought 
comment on the performance of existing generating facilities and 
whether primary frequency response requirements for these facilities 
are warranted.\54\ Finally, the Commission sought comment on 
compensation for primary frequency response.\55\
---------------------------------------------------------------------------

    \53\ Id. PP 2 and 44-45.
    \54\ Id. PP 2, 46, and 52.
    \55\ Id. PP 2, 53-54.
---------------------------------------------------------------------------

2. Comments on Modifying the Pro Forma LGIA and Pro Forma SGIA
    23. The Commission received a robust response from industry, with 
47 entities collectively submitting nearly 700 pages of comments that 
provided responses to some or all of the questions posed by the 
NOI.\56\ Relevant to the proposed revisions considered in this NOPR, 
the Commission received numerous comments on whether the pro forma LGIA 
and pro forma SGIA should be revised to include requirements for all 
newly interconnecting generating facilities, whether synchronous or 
non-synchronous, to install primary frequency response capability.\57\
---------------------------------------------------------------------------

    \56\ The Appendix lists the entities that submitted comments and 
the shortened names that are used throughout this NOPR.
    \57\ NOI, 154 FERC ] 61,117 at P 45.
---------------------------------------------------------------------------

a. Comments in Support of Modifying the pro forma LGIA and pro forma 
SGIA
    24. Most commenters support, or are not opposed to, revising the 
pro forma LGIA and SGIA to impose primary frequency response capability 
requirements on all new generating facilities as suggested in the 
NOI.\58\ Several commenters indicate that the nation's changing 
resource mix could create reliability concerns related to the provision 
of primary frequency response. For example, PJM Utilities Coalition 
states that while newer generating facilities are not installing 
frequency response capability, the existing generating facilities that 
do provide this essential reliability service have more limited 
capability, due to the cost of operation and planned retirements, 
placing the grid at further risk.\59\ Peak Reliability, the reliability 
coordinator for the Western Interconnection, states that as baseload 
generation retires, the number of generators providing primary 
frequency response is reduced and may present reliability challenges 
for system operators, as fewer options are available to reduce 
frequency deviations following an unexpected loss of generation or 
load.\60\ CAISO asserts that due to the increased proportion of 
renewable generating facilities operating in CAISO's balancing 
authority area, there may not be sufficient frequency responsive 
capacity online when the system has high renewable output and low load 
levels.\61\ Bonneville states that the trend of declining frequency 
response capability will continue with a changing resource mix, unless 
provisions are put in place to assure that adequate inertial and 
primary frequency response capability are available in the future.\62\ 
NERC states that the rapidly changing resource mix may reduce the level 
of available frequency capability.\63\
---------------------------------------------------------------------------

    \58\ APPA, et al. Comments at 6; Bonneville Comments at 6; CAISO 
Comments at 2; California Cities Comments at 2; ELCON Comments at 5; 
EEI Comments at 12; EPSA, et al. Comments at 8; Howard F. Illian 
Comments at 43; Idaho Power Comments at 1; IEEE-PES Comments at 1; 
Indicated ISOs/RTOs Comments at 3; ITC, et al. Comments at 1; MISO 
Comments at 4; MISO TOs Comments at 6; NARUC Comments at 3; NERC 
Comments at 17; North American Generator Forum Comments at 2; Peak 
Reliability Comments at 4; PG&E Comments at 2; SoCal Edison Comments 
at 4; Southern Company Comments at 2; Tri-State Generation Comments 
at 3; WIRAB Comments at 3.
    \59\ PJM Utilities Coalition Comments at 3.
    \60\ Peak Reliability Comments at 4.
    \61\ CAISO Comments at 2.
    \62\ Bonneville Comments at 2.
    \63\ NERC Comments at 17.
---------------------------------------------------------------------------

    25. Numerous commenters assert that they recognize the benefits of 
revising the pro forma LGIA and pro forma SGIA to require primary 
frequency response capabilities for new generators. NERC, for example, 
asserts that new primary frequency response requirements for generators 
will improve operator flexibility for system restoration and island 
capability and help balancing authorities meet their frequency response 
obligations.\64\ NERC also asserts that revisions to the pro forma LGIA 
and pro forma SGIA would result in measurable, clear requirements 
applicable to all new generating facilities in a fair and equitable 
manner.\65\ NERC points out, however, that primary frequency response 
capability, by itself, would not require a resource to respond if 
called upon to help a balancing authority meet its frequency response 
obligation, and that, as a result, it is important to have mechanisms 
to ensure that sufficient frequency response capability is not only 
available but ready to respond at all times.\66\ CASIO, Indicated ISOs/
RTOs, MISO, and a number of trade associations also support 
modifications to the pro forma LGIA and pro forma SGIA for new 
generating facilities to install primary frequency response 
capability.\67\ PJM Utilities Coalition states that, with all new 
generating facilities (both synchronous and non-synchronous) being 
fully capable of providing primary frequency response, requiring this 
capability will ensure that system operators have the ability to 
reliably operate the grid of the future.\68\ Peak Reliability states 
that it supports modifications to the pro forma LGIA and pro forma SGIA 
and that requiring generating facilities to install or provide 
frequency response in the initial stages of the interconnection process 
will ensure that the grid is able to maintain

[[Page 85181]]

this essential service even as the resource mix changes.\69\
---------------------------------------------------------------------------

    \64\ Id.
    \65\ Id.
    \66\ Id. at 18.
    \67\ APPA, et al. Comments at 2; CAISO Comments at 2; EEI 
Comments at 3; EPSA, et al. Comments at 8; Indicated ISOs/RTOs 
Comments at 3; MISO Comments at 4; North American Generator Forum 
Comments at 2.
    \68\ PJM Utilities Coalition Comments at 4-5.
    \69\ Peak Reliability Comments at 4-5.
---------------------------------------------------------------------------

    26. Other commenters also express support for revising the pro 
forma LGIA and pro forma SGIA. Bonneville points out that selling 
primary frequency response capability would not provide sufficient 
incentive for new generating facilities to invest in such capability, 
and argues that the only way to ensure that there is enough primary 
frequency response capability is to require new generators to install 
it.\70\ WIRAB advises that while current studies do not indicate that 
there is a shortage of primary frequency response in the Western 
Interconnection and that all generators do not need to provide primary 
frequency response all of the time, the Commission should, however, 
require that all new generator owners install primary frequency 
response capability because of the changing resource mix in the Western 
Interconnection and the associated uncertainty regarding the future 
provision of primary frequency response.\71\
---------------------------------------------------------------------------

    \70\ Bonneville Comments at 21.
    \71\ WIRAB Comments at 5-6.
---------------------------------------------------------------------------

    27. Several commenters that generally support revising the pro 
forma LGIA and pro forma SGIA also express certain concerns. For 
example, Southern Company expresses support for revising the pro forma 
LGIA and pro forma SGIA, but caveats its support by arguing that new 
regulations for primary frequency response should include an ``opt-
out'' provision that would allow balancing authorities that do not 
anticipate frequency response shortfalls to delay the implementation of 
the new pro forma LGIA and pro forma SGIA requirements until these 
needs are actually anticipated in their regions in order to avoid 
higher costs.\72\ EPSA, et al. state that while they do not fully 
oppose amending the pro forma LGIA and pro forma SGIA, they recommend 
that the Commission explore more effective and cost efficient ways to 
address the range of issues posed in the NOI and consider a measured 
approach before mandating governors for all prospective interconnecting 
generation.\73\
---------------------------------------------------------------------------

    \72\ Southern Company Comments at 2-3.
    \73\ EPSA, et al. Comments at 8-9.
---------------------------------------------------------------------------

    28. Some commenters that support modifying the pro forma LGIA and 
pro forma SGIA also assert that the costs of implementing primary 
frequency response capability for new generating facilities are 
low.\74\ For example, APPA, et al. state that the capability for 
providing primary frequency response is almost always installed in 
synchronous generation, and that the inclusion of this additional 
control for new non-synchronous generating facilities would likely add 
only nominal costs.\75\ EEI asserts that all new generating facilities 
coming online can be fully capable of providing primary frequency 
response and that the associated cost of installing such capability 
during initial manufacturing or construction of a new VER is small when 
considering the overall cost of the new generating facility.\76\
---------------------------------------------------------------------------

    \74\ APPA, et al. Comments at 6; Bonneville Comments at 8; 
California Cities Comments at 2; EEI Comments at 13; Indicated ISOs/
RTOs Comments at 5; MISO Comments at 4; SoCal Edison Comments at 2.
    \75\ APPA, et al. Comments at 6.
    \76\ EEI Comments at 13.
---------------------------------------------------------------------------

    29. In contrast to new generating facilities, some entities, 
however, explain that the costs of retrofitting existing generating 
facilities with primary frequency response capability could be 
significant in some cases.\77\ For example, WIRAB states that the high 
cost of retrofitting existing generators to install the necessary 
control equipment supports limiting the requirement to new generators 
and taking early action now.\78\
---------------------------------------------------------------------------

    \77\ APPA, et al. Comments at 6; Bonneville Comments at 8; 
California Cities Comments at 8; EEI Comments at 14; Idaho Power 
Comments at 4; WIRAB Comments at 6.
    \78\ WIRAB Comments at 6.
---------------------------------------------------------------------------

    30. In regards to nuclear generating facilities, some commenters 
indicate that nuclear plants have separate licensing requirements under 
the Nuclear Regulatory Commission and should not be required to provide 
primary frequency response. For example, the Nuclear Energy Institute 
asserts that while nearly all new generating facilities should be able 
to provide primary frequency response, nuclear plants are not well-
suited to provide primary frequency response due to restrictions by 
their operating licenses issued by the Nuclear Regulatory 
Commission.\79\ The Nuclear Energy Institute also asserts that turbine 
controls on most nuclear units are designed to maintain the internal 
steam pressure and are not intended to react to changes in the 
grid.\80\ Similarly, the MISO TOs assert that requiring nuclear units 
to have primary frequency response capability would be contrary to 
Nuclear Regulatory Commission licensing requirements, and could have a 
detrimental effect on the safety of the nuclear fleet.\81\
---------------------------------------------------------------------------

    \79\ Nuclear Energy Institute Comments at 1 and 4.
    \80\ Nuclear Energy Institute Comments at 4.
    \81\ MISO TOs Comments at 7.
---------------------------------------------------------------------------

    31. In the NOI, the Commission also sought comment on whether it 
would be appropriate to include recommended governor settings contained 
within NERC's Primary Frequency Control Guideline in the pro forma LGIA 
and pro forma SGIA.\82\ Numerous commenters express support for 
including NERC's recommended governor control settings in the pro forma 
LGIA and pro forma SGIA.\83\ Some commenters note that NERC's Guideline 
is consistent with existing regulations or practices in certain 
regions.\84\ Indicated ISOs/RTOs point out that common primary 
frequency response settings for generators in an Interconnection will 
enhance reliability by reducing maneuvering by individual 
generators.\85\ MISO asserts that NERC's Guideline provides a sound 
baseline.\86\ NERC notes that its Guideline was developed by technical 
committees with expertise and judgment of the electric industry, and 
accordingly, the Guideline is the ``most advanced set of nation-wide 
best practices and information currently available to support frequency 
response capability.'' \87\
---------------------------------------------------------------------------

    \82\ NOI, 154 FERC ] 61,117 at P 45.
    \83\ See e.g., Bonneville Comments at 7; IEEE-PES Comments at 1; 
Indicated ISOs/RTOs Comments at 4; California Cities Comments at 2; 
WIRAB Comments at 7.
    \84\ Indicated ISOs/RTOs Comments at 4; SoCal Edison Comments at 
4; Peak Reliability Comments at 7; Manitoba Comments at 8.
    \85\ Indicated ISOs/RTOs Comments at 5.
    \86\ MISO Comments at 4.
    \87\ NERC Comments at 12.
---------------------------------------------------------------------------

    32. However, not all entities that support modifying the pro forma 
LGIA and pro forma SGIA endorse the inclusion of NERC's recommended 
governor settings. For example, EEI states that it does not support 
including prescriptive performance requirements for governor control 
settings or other performance indicators in the pro forma LGIA or pro 
forma SGIA due to the physical, technical, or operational limitations 
of new generating facilities to provide primary frequency response.\88\ 
Similarly, APPA, et al. state that they do not support revising the pro 
forma LGIA and pro forma SGIA to include the recommended settings 
contained within NERC's Guideline at this time.\89\ MISO TOs state that 
some transmission owners in MISO believe that NERC's recommended 
governor settings are appropriate for traditional synchronous 
generating facilities, but recommend additional consideration for other 
generation technologies.\90\ On the other hand, MISO TOs state that 
other transmission owners in MISO request

[[Page 85182]]

flexibility and assert that specified governor settings should not be 
``hard-wired'' or dictated in the pro forma LGIA and pro forma 
SGIA.\91\
---------------------------------------------------------------------------

    \88\ EEI Comments at 15-17.
    \89\ APPA, et al. Comments at 8.
    \90\ MISO TOs Comments at 8.
    \91\ MISO TOs Comments at 8.
---------------------------------------------------------------------------

b. Comments Opposed To Modifying the pro forma LGIA and pro forma SGIA
    33. Other commenters contend that the pro forma LGIA and pro forma 
SGIA should not be modified to require primary frequency response 
capability from new generating facilities.\92\ Some commenters argue 
that requiring all new generating facilities to have primary frequency 
response capability will result in extra costs above those necessary to 
ensure reliability.\93\ For example, APS argues that a global mandate 
to provide primary frequency response or to require generating 
facilities to be primary frequency response capable would result in 
significantly increased costs while providing a disproportionately 
minor impact on improving reliability.\94\ Powerex asserts that 
modifying the pro forma LGIA and pro forma SGIA to include minimum 
primary frequency response requirements will increase the cost of entry 
for new generators, particularly VERs, which typically are not designed 
with such capability.\95\ Several commenters note that there would be a 
significant opportunity cost for certain generating facilities to 
reserve headroom for the provision of primary frequency response.\96\
---------------------------------------------------------------------------

    \92\ AES Companies Comments at 6; Apex Comments at 6; APS 
Comments at 6; AWEA Comments at 12; Chelan County Comments at 2; ESA 
Comments at 2; Grid Storage Consulting Comments at 2; Microgrids 
Resources Coalition Comments at 3; NRECA Comments at 9; Powerex 
Comments at 5; SDG&E Comments at 3; SolarCity Comments at 1; TVA 
Comments at 2.
    \93\ Apex Comments at 5-6; APS Comments at 6; AWEA Comments at 
12; Chelan County Comments at 2; Powerex Comments at 5; Solar City 
Comments at 1.
    \94\ APS Comments at 6. It is unclear whether the increased 
costs referenced by APS refer only to the costs for the necessary 
equipment to provide primary frequency response or the costs 
associated with maintaining the headroom necessary to provide 
primary frequency response.
    \95\ Powerex Comments at 5.
    \96\ Apex Comments at 7; Solar City Comments at 1; AWEA Comments 
at 6.
---------------------------------------------------------------------------

    34. Some of the commenters that are opposed to modifying the pro 
forma LGIA and pro forma SGIA assert that they prefer a market-based 
approach instead of a requirement for new generating facilities to 
install primary frequency response capability.\97\ For example, AWEA 
asserts that, initially, the pro forma LGIA and pro forma SGIA should 
not be revised to require new generating facilities to have primary 
frequency response capability, and only if market-based steps do not 
satisfactorily address the need for primary frequency response, then 
the Commission could consider an additional requirement for new 
generating facilities to have such capability as a final step.\98\
---------------------------------------------------------------------------

    \97\ Apex Comments at 6; AWEA Comments at 12; Chelan County 
Comments at 2; ESA Comments at 2; SDG&E Comments at 3.
    \98\ AWEA Comments at 12.
---------------------------------------------------------------------------

    35. Other commenters oppose mandatory requirements and prefer a 
voluntary approach to improving primary frequency response 
performance.\99\ For example, TVA asserts that if current voluntary 
actions fail to show improvement in primary frequency response, then 
the pro forma LGIA and pro forma SGIA could be revised to contain a 
general primary frequency response requirement, similar to reactive 
power, but that NERC should be directed to establish governor settings 
and performance requirements through the NERC Standards Development 
Process instead of the Commission including such requirements in the 
pro forma LGIA and pro forma SGIA.\100\ Some commenters assert that 
governor control details are better left to individual balancing 
authorities.\101\ For example, APS argues that the Commission should 
allow balancing authorities to determine the type and magnitude of 
generating facilities within its balancing authority area that are 
frequency-response enabled.\102\ APS also points out that any need to 
install frequency response capability or otherwise support frequency 
response performance can and should be evaluated and agreed upon 
between a generating facility and the transmission provider during the 
interconnection study process.\103\
---------------------------------------------------------------------------

    \99\ APS Comments at 8; NRECA Comments at 6; TVA Comments at 2.
    \100\ TVA Comments at 2-3 and 5.
    \101\ APS Comments at 8; AES Companies Comments at 8.
    \102\ APS Comments at 8.
    \103\ Id. at 15.
---------------------------------------------------------------------------

II. Discussion

A. Primary Frequency Response Requirements

1. The Need for Reform
    36. Pursuant to FPA section 206, the Commission preliminarily finds 
that conditions have changed since the issuance of Order Nos. 2003 and 
2006 and certain aspects of the pro forma LGIA and pro forma SGIA may 
now be unjust, unreasonable, unduly discriminatory, or 
preferential.\104\ Specifically, as discussed above, the record 
indicates that while the frequency response performance of the Eastern 
and Western Interconnections is currently adequate, the frequency 
response performance of both Interconnections has significantly 
declined from historic values.\105\ Furthermore, the record shows that 
there is an ongoing evolution of the nation's generation resource mix, 
including significant retirements of baseload generation and an 
increasing proportion of VERs interconnecting to the electric 
grid.\106\ Several commenters point out that there is significant risk 
that the rapidly changing resource mix may reduce the level of 
available frequency response capability online.\107\ This is in part 
because, as noted in the NOI, VERs have not been consistently designed 
with primary frequency response capabilities.\108\ The record suggests, 
however, that VER manufacturers have made significant technological 
advancements in recent years to develop primary frequency response 
capability for VERs.\109\ In addition, NERC, in conjunction with 
various industry stakeholders, has developed more robust technical 
guidance for the operation of governors or equivalent controls.\110\ As 
a result of the evolving resource mix and the potential for adverse 
impacts on primary frequency response, the Commission is concerned that 
there may be potential reliability impacts if it does not undertake the 
reforms proposed in this NOPR. Moreover, the Commission is concerned 
that certain aspects of the existing pro forma LGIA and pro forma SGIA 
may no longer be just and reasonable.
---------------------------------------------------------------------------

    \104\ The Commission routinely evaluates the effectiveness of 
its regulations and policies in light of changing industry 
conditions to determine if changes are necessary. See, e.g., Order 
No. 764, FERC Stats. & Regs. ] 31,331.
    \105\ See NERC 2015 Frequency Response Webinar at 10, NERC 
Frequency Response Initiative Report at 22, and LBNL 2010 Report at 
pp xiv-xv.
    \106\ See, e.g., P 12, supra (describing recent and ongoing 
changes in the nation's generation mix).
    \107\ See, e.g., Bonneville Comments at 2; CAISO Comments at 2; 
NERC Comments at 17; Peak Reliability Comments at 4; PJM Utilities 
Coalition Comments at 3.
    \108\ NOI, 154 FERC ] 61,117 at PP 42-43.
    \109\ See, e.g., PJM Utilities Comments at 4-5; EEI Comments at 
13. See also PJM Interconnection, L.L.C., Docket No. ER15-1193-000 
(March 6, 2015) Transmittal Letter at 11. See also NERC 2014 LTRA, 
at 27 (Nov. 2014), http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014LTRA_ERATTA.pdf.
    \110\ See P 16, supra.
---------------------------------------------------------------------------

    37. First, the current requirements for governor controls in the 
pro forma LGIA do not reflect advances in technology or the latest 
recommended operating practices. Specifically, current Article 9.6.2.1 
states that ``speed governors,'' if installed, must be operated in 
automatic

[[Page 85183]]

mode. However, many of the new generating facilities interconnecting to 
the grid, such as wind and solar, do not utilize traditional speed 
governors; instead they utilize enhanced inverters and other plant 
supervisory control technology that can be designed to include primary 
frequency response capability.\111\ Therefore, due to advancements in 
technology, the Commission preliminarily finds that the existing 
references to ``speed governors'' in Article 9.6.2.1 that apply only to 
synchronous resources are outdated, and therefore may no longer be just 
and reasonable.
---------------------------------------------------------------------------

    \111\ See Electric Power Research Institute, Recommended 
Settings for Voltage and Frequency Ride Through of Distributed 
Energy Resources (May 2015) at 27, http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=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.
---------------------------------------------------------------------------

    38. Second, since the issuance of Order No. 2003 and the 
establishment of the pro forma LGIA, NERC, in conjunction with industry 
stakeholders, has amassed a significant body of knowledge in regards to 
the operation of generator governors and plant control systems. For 
example, as noted above, NERC observed in 2012 that a number of 
generators implemented deadband settings that were so wide as to 
effectively defeat the ability to provide primary frequency response, 
and that many generators provide frequency response in the wrong 
direction during a disturbance.\112\ Additionally, as noted above, NERC 
observed in 2015 that in many conventional steam plants, deadband 
settings exceed a 0.036 Hz dead band, resulting in primary 
frequency response that is not sustained, and that the vast majority of 
the gas turbine fleet is not frequency responsive.\113\
---------------------------------------------------------------------------

    \112\ See P 16, supra.
    \113\ Id.
---------------------------------------------------------------------------

    39. The record here suggests that the actual governor and plant 
control system settings that are being implemented by some generator 
owners and/or operators may be defeating the intent of Article 9.6.2.1 
of the pro forma LGIA. In response to these issues, NERC, through the 
work of its various task forces, subcommittees, and initiatives, has 
developed a voluntary Guideline that includes recommended droop and 
deadband settings based on significant investigation.\114\ However, the 
pro forma LGIA does not currently reflect these updated recommended 
practices for governor and plant control system settings of generating 
facilities.
---------------------------------------------------------------------------

    \114\ See NERC Primary Frequency Control Guideline.
---------------------------------------------------------------------------

    40. Third, given the nation's evolving resource mix and the 
potential adverse impacts on primary frequency response as noted in the 
NOI and pointed out by several commenters, the Commission believes that 
changes to the pro forma LGIA and pro forma SGIA may be necessary to 
provide for the continued reliable operation of the power system. As 
noted above, the Task Force concluded that all new generating 
facilities should be required to be capable of providing primary 
frequency response.\115\ However, the pro forma LGIA does not currently 
require large generating facilities to install such capability; rather, 
it only requires governor operation in ``automatic mode'' if a ``speed 
governor'' is installed.\116\
---------------------------------------------------------------------------

    \115\ See P 15, supra.
    \116\ Article 9.6.2.1 of the pro forma LGIA.
---------------------------------------------------------------------------

    41. In addition, the Commission is concerned that the current pro 
forma SGIA may be unduly discriminatory or preferential because it does 
not establish any specific requirements with respect to the 
installation or operation of governors or equivalent frequency control 
equipment. In particular, the pro forma SGIA does not have a similar 
provision to Article 9.6.2.1 of the pro forma LGIA. The Commission has 
previously acted under FPA section 206 to remove inconsistencies 
between the pro forma LGIA and pro forma SGIA when there is no economic 
or technical basis for treating large and small generating facilities 
differently.\117\ Similarly, in this instance, the record developed 
from the NOI appears to suggest that small generating facilities are 
capable of installing and enabling governors at low cost in a manner 
comparable to large generating facilities.\118\ As discussed above, the 
record indicates that there have been significant advances in 
technology, as well as the development of more robust technical 
guidance for the operation of governors or equivalent controls for both 
large and small generating facilities.\119\ In particular, the IEEE-
P1547 Working Group noted that its new IEEE-1547 standard for 
interconnecting distributed generation will likely include certain 
requirements for providing primary frequency response.\120\ Given these 
low-cost technological advances, the Commission does not anticipate 
that these additional requirements added in the pro forma SGIA will 
present a barrier to entry for small generating facilities. And, given 
the need for additional primary frequency response capability and an 
increasingly large market penetration of small generating facilities, 
the Commission believes that there is a need to add these requirements 
to the pro forma SGIA to help ensure adequate primary frequency 
response capability.
---------------------------------------------------------------------------

    \117\ See Requirements for Frequency and Voltage Ride Through 
Capability of Small Generating Facilities, Order No. 828, 81 FR 
50,290 (Aug. 1, 2016), 156 FERC ] 61,062 (2016), (The Final Rule 
revised the pro forma SGIA such that small generating facilities 
have frequency and voltage ride through requirements comparable to 
large generating facilities).
    \118\ IEEE-P1547 Working Group Comments at 1, 5, and 7. 
Moreover, the Commission notes that other commenters stated costs of 
installing primary frequency response capability are generally low, 
but did not differentiate between small and large generating 
facilities. See, e.g., APPA, et al. Comments at 6; California Cities 
Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at 
3-5; SoCal Edison Comments at 2.
    \119\ See PP 13, 36, supra.
    \120\ IEEE-P1547 Working Group Comments at 1, 5, and 7.
---------------------------------------------------------------------------

    42. Moreover, as noted above, a number of commenters assert that 
costs for new generating facilities to install the capability of 
providing primary frequency response are low, suggesting that there is 
not a financial barrier to small generating facilities installing the 
capability to provide frequency response.\121\ PJM's recent changes to 
require both small and large non-synchronous generating facilities to 
use enhanced inverters, which include primary frequency response 
capability, among other functions, further support this notion.\122\
---------------------------------------------------------------------------

    \121\ See, e.g., APPA, et al. Comments at 2; EEI Comments at 13; 
Indicated ISOs/RTOs Comments at 5; SoCal Edison Comments at 2.
    \122\ PJM Interconnection, L.L.C., 151 FERC ] 61,097 at P 28 
(the Commission stated that it ``find[s] that PJM's proposal will 
not present a barrier to non-synchronous resources.'').
---------------------------------------------------------------------------

2. Commission Proposal
    43. To remedy the potentially unjust, unreasonable, and unduly 
discriminatory or preferential practices described above, the 
Commission preliminarily finds that revisions to the pro forma LGIA and 
pro forma SGIA are appropriate. The Commission believes that revising 
the pro forma LGIA and pro forma SGIA to require all new generating 
facilities to install, maintain, and operate a functioning governor or 
equivalent controls, consistent with the proposed requirements 
described below, will help to ensure adequate primary frequency 
response capability as the resource mix continues to evolve, ensure 
fair and consistent treatment for all types of generating facilities, 
help balancing authorities meet their frequency response obligations 
pursuant to NERC Reliability Standard BAL-003-1.1, and help improve 
reliability during

[[Page 85184]]

system restoration and islanding situations.\123\
---------------------------------------------------------------------------

    \123\ See NERC Comments at 17. See also NERC Essential 
Reliability Services Task Force Measures Framework Report at iv.
---------------------------------------------------------------------------

    44. In particular, the Commission proposes to revise the pro forma 
LGIA and pro forma SGIA to include the following: (1) Requirements for 
new large and small generating facilities, both synchronous and non-
synchronous, to install, maintain, and operate equipment capable of 
providing primary frequency response as a condition of interconnection; 
(2) requirements for governor or equivalent controls to be operated, at 
a minimum, with maximum 5 percent droop and 0.036 Hz 
deadband settings; (3) requirements to ensure the timely and sustained 
response to frequency deviations, including provisions to prevent 
plant-level (i.e., outer-loop) control equipment from inhibiting 
primary frequency response and resulting in premature withdrawal; and 
(4) a requirement for droop parameters to be based on nameplate 
capability with a linear operating range of 59 to 61 Hz. Additionally, 
as informed by NOI commenters, the Commission believes that it is not 
necessary to impose a generic headroom requirement or subject newly 
interconnecting nuclear generating facilities to the new requirements. 
The Commission does not propose to mandate any separate compensation 
related to the proposed requirements. The Commission seeks comment on 
the proposed reforms, as discussed more fully below.
    45. Specifically, the Commission proposes to revise existing 
sections 9.6 and 9.6.2.1 of the pro forma LGIA and to include proposed 
new sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.3. Similarly, the 
Commission proposes to revise existing section 1.8 of the pro forma 
SGIA and add proposed new sections 1.8.4, 1.8.4.1, 1.8.4.1.1, 
1.8.4.1.2, and 1.8.4.1.3.\124\
---------------------------------------------------------------------------

    \124\ The specific proposed modifications and additions to the 
pro forma LGIA and pro forma SGIA are set forth at PP 52-53, below.
---------------------------------------------------------------------------

    46. The Commission's proposed revisions to the pro forma LGIA and 
pro forma SGIA would apply to new generating facilities that execute or 
request the unexecuted filing of interconnection agreements on or after 
the effective date of any Final Rule issued in Docket No. RM16-6-000. 
The Commission also proposes to apply the requirements to any large or 
small generating facility that has an executed or has requested the 
filing of an unexecuted LGIA or SGIA as of the effective date of any 
Final Rule in Docket No. RM16-6-000, but that takes any action that 
requires the submission of a new interconnection request that results 
in the filing of an executed or unexecuted interconnection agreement on 
or after the effective date of any Final Rule in Docket No. RM16-6-000.
    47. In particular, the proposed revisions to the pro forma LGIA and 
pro forma SGIA would require new large and small generating facilities 
to install, maintain, and operate a functioning governor or equivalent 
controls, which the Commission proposes to define as the required 
hardware and/or software that provides frequency responsive real power 
control with the ability to sense changes in system frequency and 
autonomously adjust the generating facility's real power output in 
accordance with the proposed maximum droop and deadband parameters and 
in the direction needed to correct frequency deviations. The Commission 
seeks comment on this proposal.
    48. The Commission also proposes to require new large and small 
generating facilities to install, maintain and operate governor or 
equivalent controls with the ability to operate with a maximum 5 
percent droop and 0.036 Hz deadband parameter, consistent 
with NERC's recommended guidance. As noted above, the Commission sought 
comment in the NOI on whether NERC's recommended guidance for governor 
settings related to droop and deadband should be included in the pro 
forma LGIA and pro forma SGIA, and numerous commenters agreed stating 
that NERC's Guideline provides a sound baseline.\125\ Therefore, the 
Commission preliminarily finds that a maximum droop setting of 5 
percent and deadband setting of 0.036 Hz are appropriate to 
include in the pro forma LGIA and pro forma SGIA as interconnection 
requirements for new generating facilities. The Commission notes that 
these proposed requirements are minimum requirements; therefore, if a 
new generating facility elects, in coordination with its transmission 
provider, to operate in a more responsive mode by using lower droop or 
tighter deadband settings, nothing in these requirements would prohibit 
it from doing so.\126\ The Commission seeks comment on these proposed 
requirements for droop and deadband settings.
---------------------------------------------------------------------------

    \125\ See e.g., Bonneville Comments at 7; California Cities 
Comments at 2; IEEE-PES Comments at 2; Indicated ISOs/RTOs Comments 
at 4; MISO Comments at 4; WIRAB Comments at 7.
    \126\ Moreover, the Commission proposes that nothing in these 
requirements would prohibit the implementation of asymmetrical droop 
settings (i.e., different droop settings for under-frequency and 
over-frequency conditions), provided that each segment has a droop 
value of no more than 5 percent.
---------------------------------------------------------------------------

    49. The Commission also proposes to prohibit all new large and 
small generating facilities from taking any action that would inhibit 
the provision of primary frequency response, except under certain 
conditions as discussed below. The lack of coordination between 
governor and plant-level control systems can result in premature 
withdrawal of primary frequency response by allowing additional plant 
control systems to reverse the action of the governor to return the 
unit to operating at a pre-selected target set-point.\127\ NERC's 
Guideline explains that ``in order to provide sustained primary 
frequency response, it is essential that the prime mover governor, 
plant controls and remote plant controls are coordinated.'' \128\ 
Accordingly, the Commission proposes to require new generating 
facilities that respond to frequency deviations to not inhibit primary 
frequency response, such as by coordinating plant-level, outer-loop 
control equipment with the governor or equivalent controls, except 
under certain operational constraints including, but not limited to, 
ambient temperature limitations, outages of mechanical equipment, or 
regulatory requirements. The Commission also proposes to require new 
generating facilities to respond to frequency deviations without undue 
delay and to sustain the response until at least system frequency 
returns to a stable value within the governor's deadband setting. The 
Commission believes this proposed requirement for sustained response is 
consistent with the current requirements of PJM and ISO-NE as well as 
similar OATT revisions recently implemented by CAISO.\129\ The 
Commission seeks comment on the proposed requirements for sustained 
response. In particular, the Commission seeks comment on whether these 
provisions will be sufficient to prevent plant-level (i.e., outer-loop) 
controls from inhibiting primary frequency response.
---------------------------------------------------------------------------

    \127\ NERC Frequency Response Initiative Report at 31. See also 
NOI, 154 FERC ] 61,117 at P 49 (stating that primary frequency 
response withdrawal ``has the potential to degrade the overall 
response of the Interconnection and result in a frequency that 
declines below the original nadir'').
    \128\ NERC Primary Frequency Control Guideline at 4.
    \129\ See, e.g., ISO-NE Operating Procedure OP-14 and PJM Manual 
14D. See also CAISO, 156 FERC ] 61,182 at PP 10-12 and 17.
---------------------------------------------------------------------------

    50. Regarding droop settings, in its comments to the NOI, MISO 
proposed that a linear droop should be available between 59 to 61 
Hz.\130\ The

[[Page 85185]]

Commission believes that this is reasonable because it would allow for 
new generating facilities that remain connected during frequency 
deviations to provide a proportional response within this range of 
frequencies. Accordingly, the Commission proposes to require the droop 
parameter to be based on the nameplate capability of the unit and 
linear in operating range between 59 to 61 Hz. The Commission seeks 
comment on these proposed requirements for droop settings.
---------------------------------------------------------------------------

    \130\ MISO Comments at 4.
---------------------------------------------------------------------------

    51. Several NOI commenters expressed concern about possible generic 
headroom requirements \131\ that could result in significant 
opportunity costs.\132\ The Commission clarifies that nothing in these 
proposed reforms will impose a generic headroom requirement for new 
generating facilities or affect the unit commitment and dispatch 
decisions of balancing authorities. Therefore, if a generating facility 
that is subject to these proposed requirements has been dispatched by 
its balancing authority to a set-point at which there is no available 
operating range to increase or decrease its output in response to 
frequency deviations, it would not be in violation of the proposed 
requirements in regards to providing sustained response. The Commission 
believes that the reliability benefits from the proposed modifications 
to the pro forma LGIA and pro forma SGIA do not require imposing 
additional costs that would result from a generic headroom requirement. 
The Commission also agrees with NOI commenters regarding the unique 
operating characteristics and regulatory requirements of nuclear 
generating facilities regulated by the Nuclear Regulatory Commission, 
and therefore proposes to exempt such generating facilities from the 
proposed reforms.\133\ The Commission seeks comment on the proposal to 
not impose a generic headroom requirement and to not apply the new 
requirements to nuclear generating facilities.
---------------------------------------------------------------------------

    \131\ A generic headroom requirement would require generating 
facilities to operate below maximum output at all times to ensure 
sufficient ability to increase their real power output in response 
to under-frequency conditions.
    \132\ See, e.g., Apex Comments at 7; Solar City Comments at 1; 
AWEA Comments at 6.
    \133\ See, e.g., Nuclear Energy Institute Comments at 1, 4; MISO 
TOs Comments at 7.
---------------------------------------------------------------------------

    52. In light of the above discussion, the Commission proposes to 
modify sections 9.6 and 9.6.2.1 of the pro forma LGIA and add new 
sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.3 as follows:

9.6 Reactive Power and Primary Frequency Response

    9.6.2.1 Voltage Regulators. Whenever the Large Generating 
Facility is operated in parallel with the Transmission System and 
voltage regulators are capable of operation, Interconnection 
Customer shall operate the Large Generating Facility with its 
voltage regulators in automatic operation. If the Large Generating 
Facility's voltage regulators are not capable of such automatic 
operation, Interconnection Customer shall immediately notify 
Transmission Provider's system operator, or its designated 
representative, and ensure that such Large Generating Facility's 
reactive power production or absorption (measured in MVARs) are 
within the design capability of the Large Generating Facility's 
generating unit(s) and steady state stability limits. 
Interconnection Customer shall not cause its Large Generating 
Facility to disconnect automatically or instantaneously from the 
Transmission System or trip any generating unit comprising the Large 
Generating Facility for an under or over frequency condition unless 
the abnormal frequency condition persists for a time period beyond 
the limits set forth in ANSI/IEEE Standard C37.106, or such other 
standard as applied to other generators in the Control Area on a 
comparable basis.
    9.6.4 Primary Frequency Response. Interconnection Customer shall 
ensure the primary frequency response capability of its Large 
Generating Facility by installing, maintaining, and operating a 
functioning governor or equivalent controls. The term ``functioning 
governor or equivalent controls'' as used herein shall mean the 
required hardware and/or software that provides frequency responsive 
real power control with the ability to sense changes in system 
frequency and autonomously adjust the Large Generating Facility's 
real power output in accordance with the droop and deadband 
parameters and in the direction needed to correct frequency 
deviations. Interconnection Customer is required to install a 
governor or equivalent controls with the capability of operating 
with a maximum 5 percent droop and 0.036 Hz 
deadband. The droop characteristic shall be based on the nameplate 
capacity of the Large Generating Facility, and shall be linear in 
the range of 59 to 61 Hz. The deadband parameter shall be the range 
of frequencies above and below nominal (60 Hz) in which the governor 
or equivalent controls is not expected to adjust the Large 
Generating Facility's real power output in response to frequency 
deviations. Interconnection Customer shall notify Transmission 
Provider that the primary frequency response capability of the Large 
Generating Facility has been tested and confirmed during 
commissioning. Once Interconnection Customer has synchronized the 
Large Generating Facility with the Transmission System, 
Interconnection Customer shall operate the Large Generating Facility 
consistent with provisions specified in Sections 9.6.4.1 and 9.6.4.2 
of this Agreement. The primary frequency response requirements 
contained herein shall apply to both synchronous and non-synchronous 
Large Generating Facilities. Nothing in Sections 9.6.4, 9.6.4.1 and 
9.6.4.2 shall require the Large Generating Facility to operate above 
its minimum operating limit or below its maximum operating limit, or 
otherwise alter its dispatch to have headroom to provide primary 
frequency response.
    9.6.4.1 Governor or Equivalent Controls. Whenever the Large 
Generating Facility is operated in parallel with the Transmission 
System, Interconnection Customer shall operate the Large Generating 
Facility with its governor or equivalent controls in service and 
responsive to frequency. Interconnection Customer shall, in 
coordination with Transmission Provider, set the deadband parameter 
to a maximum of 0.036 Hz and set the droop 
parameter to a maximum of 5 percent. Interconnection Customer shall 
be required to provide the status and settings of the governor or 
equivalent controls to Transmission Provider upon request. If 
Interconnection Customer needs to operate the Large Generating 
Facility with its governor or equivalent controls not in service, 
Interconnection Customer shall immediately notify Transmission 
Provider's system operator, or its designated representative. 
Interconnection Customer shall make Reasonable Efforts to return its 
governor or equivalent controls into service as soon as practicable.
    9.6.4.2 Sustained Response. Interconnection Customer shall 
ensure that the Large Generating Facility's real power response to 
sustained frequency deviations outside of the deadband setting is 
provided without undue delay, and ensure that the response is not 
inhibited, except under certain operational constraints including, 
but not limited to, ambient temperature limitations, outages of 
mechanical equipment, or regulatory requirements. The Large 
Generating Facility shall sustain the real power response at least 
until system frequency returns to a stable value within the deadband 
setting of the governor or equivalent controls.
    9.6.4.3 Exemptions. Large Generating Facilities that are 
regulated by the United States Nuclear Regulatory Commission shall 
be exempt from Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this 
Agreement.

    53. Similarly, the Commission proposes to modify section 1.8 of the 
pro forma SGIA and add new sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 
as follows:

1.8 Reactive Power and Primary Frequency Response

    1.8.4 Primary Frequency Response. Interconnection Customer shall 
ensure the primary frequency response capability of its Small 
Generating Facility by installing, maintaining, and operating a 
functioning governor or equivalent controls. The term ``functioning 
governor or equivalent controls'' as used herein shall mean the 
required hardware and/or software that provides frequency responsive 
real power control with the ability to sense changes in system 
frequency and autonomously adjust the Small Generating Facility's 
real power output in accordance with the droop and deadband 
parameters and in the direction needed to correct frequency 
deviations. Interconnection Customer is required to install a 
governor or

[[Page 85186]]

equivalent controls with the capability of operating with a maximum 
5 percent droop and 0.036 Hz deadband. The droop 
characteristic shall be based on the nameplate capacity of the Small 
Generating Facility, and shall be linear in the range of 59 to 61 
Hz. The deadband parameter shall be the range of frequencies above 
and below nominal (60 Hz) in which the governor or equivalent 
controls is not expected to adjust the Small Generating Facility's 
real power output in response to frequency deviations. 
Interconnection Customer shall notify Transmission Provider that the 
primary frequency response capability of the Small Generating 
Facility has been tested and confirmed during commissioning. Once 
Interconnection Customer has synchronized the Small Generating 
Facility with the Transmission System, Interconnection Customer 
shall operate the Small Generating Facility consistent with the 
provisions specified in Sections 1.8.4.1 and 1.8.4.2 of this 
Agreement. The primary frequency response requirements contained 
herein shall apply to both synchronous and non-synchronous Small 
Generating Facilities. Nothing in Sections 1.8.4, 1.8.4.1 and 
1.8.4.2 shall require the Small Generating Facility to operate above 
its minimum operating limit, below its maximum operating limit, or 
otherwise alter its dispatch to have headroom to provide primary 
frequency response.
    1.8.4.1 Governor or Equivalent Controls. Whenever the Small 
Generating Facility is operated in parallel with the Transmission 
System, Interconnection Customer shall operate the Small Generating 
Facility with its governor or equivalent controls in service and 
responsive to frequency. Interconnection Customer shall, in 
coordination with Transmission Provider, set the deadband parameter 
to a maximum of 0.036 Hz and set the droop 
parameter to a maximum of 5 percent. Interconnection Customer shall 
be required to provide the status and settings of the governor or 
equivalent controls to Transmission Provider upon request. If 
Interconnection Customer needs to operate the Small Generating 
facility with its governor or equivalent controls not in service, 
Interconnection Customer shall immediately notify Transmission 
Provider's system operator, or its designated representative. 
Interconnection Customer shall make Reasonable Efforts to return its 
governor or equivalent controls into service as soon as practicable.
    1.8.4.2 Sustained Response. Interconnection Customer shall 
ensure that the Small Generating Facility's real power response to 
sustained frequency deviations outside of the deadband setting is 
provided without undue delay, and ensure that the response is not 
inhibited, except under certain operational constraints including, 
but not limited to, ambient temperature limitations, outages of 
mechanical equipment, or regulatory requirements. The Small 
Generating Facility shall sustain the real power response at least 
until system frequency returns to a stable value within the deadband 
setting of the governor or equivalent controls.
    1.8.4.3 Exemptions. Small Generating Facilities that are 
regulated by the United States Nuclear Regulatory Commission shall 
be exempt from Sections 1.8.4, 1.8.4.1, 1.8.4.2 of this Agreement.

    54. The Commission proposes to apply the primary frequency response 
requirements to any new large or small generating facility that 
executes or requests the unexecuted filing of a LGIA or SGIA on or 
after the effective date of any Final Rule issued in this proceeding. 
In addition, the Commission proposes to apply the requirements to any 
large or small generating facility that has an executed or has 
requested the filing of an unexecuted LGIA or SGIA as of the effective 
date of any Final Rule in Docket No. RM16-6-000, but that takes any 
action that requires the submission of a new interconnection request 
that results in the filing of an executed or unexecuted interconnection 
agreement on or after the effective date of any Final Rule in Docket 
No. RM16-6-000. The Commission seeks comment on the proposed effective 
date including whether applying these requirements to existing 
generating facilities that take any action that requires the submission 
of a new interconnection request that results in the filing of an 
executed or unexecuted interconnection agreement on or after the 
effective date of any Final Rule in Docket No. RM16-6-000 would be 
unduly burdensome.
    55. The Commission does not propose in this NOPR to require that 
the interconnection customer receive any compensation for these 
proposed requirements. The Commission has previously accepted changes 
to transmission provider tariffs that similarly required 
interconnection customers to install primary frequency response 
capability or that established specified governor settings, without 
requiring any accompanying compensation.\134\ While the Commission has 
not required compensation for similar requirements in the past, it 
clarifies that nothing in this NOPR is meant to prohibit a public 
utility from filing a proposal for primary frequency response 
compensation under FPA section 205, if it so chooses.\135\
---------------------------------------------------------------------------

    \134\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58 
(2015); CAISO, 156 FERC ] 61,182, at PP 10-12 and 17 (2016); New 
England Power Pool, 109 FERC ] 61,155 (2004), order on reh'g, 110 
FERC ] 61,335 (2005).
    \135\ 16 U.S.C. 824d (2012).
---------------------------------------------------------------------------

B. Request for Comment

    56. The Commission seeks comment on the proposed: (1) Requirements 
for new large and small generating facilities to install, maintain, and 
operate a governor or equivalent controls; (2) requirements for droop 
and deadband settings of 5 percent and 0.036 Hz, 
respectively; (3) requirements for timely and sustained response; (4) 
requirement for droop parameters to be based on nameplate capability 
with a linear operating range of 59 to 61 Hz; (5) exemptions for new 
nuclear units; and (6) effective dates as discussed above. The 
Commission also seeks comment on its proposal to not impose a generic 
headroom requirement or mandate compensation related to the proposed 
reforms.
    57. In the NOI, the Commission also sought comment on the 
performance of existing resources and whether primary frequency 
response requirements for these resources are warranted.\136\ At this 
time, the Commission proposes only to adopt the reforms included in 
this NOPR regarding newly interconnecting large and small generating 
facilities. However, the Commission seeks comment regarding whether the 
reforms proposed in this NOPR are sufficient to ensure adequate levels 
of primary frequency response, or whether additional reforms are 
needed. In particular, the Commission seeks comment on whether 
additional primary frequency response performance or capability 
requirements for existing resources are needed, and if so, whether the 
Commission should impose those requirements by: (1) Directing the 
development or modification of a reliability standard pursuant to 
section 215(d)(5) of the FPA; or (2) acting pursuant to section 206 of 
the FPA to require changes to the pro forma OATT.
---------------------------------------------------------------------------

    \136\ NOI, 154 FERC ] 61,117 at PP 2, 46-52.
---------------------------------------------------------------------------

C. Proposed Compliance Procedures

    58. The Commission proposes to require all public utility 
transmission providers to adopt the requirements of any Final Rule in 
Docket No. RM16-6-000 as revisions to the LGIA and SGIA in their OATTs 
within 60 days after the publication of the Final Rule in the Federal 
Register.
    59. Some public utility transmission providers may have provisions 
in their existing LGIAs and SGIAs that the Commission has found to be 
consistent with or superior to the pro forma LGIA and pro forma SGIA. 
Where these provisions would be modified by the Final Rule, public 
utility transmission providers must either comply with the Final Rule 
or demonstrate that these previously-approved variations continue to be 
consistent with or superior to the pro forma LGIA and pro forma SGIA as 
modified by the Final Rule. The Commission also proposes to permit 
appropriate entities to seek

[[Page 85187]]

``independent entity variations'' from the proposed revisions to the 
pro forma LGIA and pro forma SGIA.\137\
---------------------------------------------------------------------------

    \137\ See, e.g., Order No. 2003, FERC Stats. & Regs. ] 31,146 at 
P 827.
---------------------------------------------------------------------------

    60. The Commission would assess whether each compliance filing 
satisfies the proposed requirements stated above and issue additional 
orders as necessary to ensure that each public utility transmission 
provider meets the requirements of the subsequent Final Rule.
    61. The Commission also proposes that transmission providers that 
are not public utilities would have to adopt the requirements of this 
proposal and subsequent Final Rule as a condition of maintaining the 
status of their safe harbor tariff or otherwise satisfying the 
reciprocity requirement of Order No. 888.\138\
---------------------------------------------------------------------------

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

III. Information Collection Statement

    62. The Paperwork Reduction Act (PRA) \139\ requires each federal 
agency to seek and obtain Office of Management and Budget (OMB) 
approval before undertaking a collection of information directed to ten 
or more persons, or contained in a rule of general applicability. OMB's 
regulations require the approval of certain information collection 
requirements imposed by agency rules.\140\ Upon approval of a 
collection of information, OMB will assign an OMB control number and an 
expiration date. Respondents subject to the filing requirements of this 
proposal will not be penalized for failing to respond to this 
collection of information unless the collection of information displays 
a valid OMB control number. Transmission providers are subject to the 
proposed revisions to the pro forma LGIA and SGIA.
---------------------------------------------------------------------------

    \139\ 44 U.S.C. 3501-3520 (2012).
    \140\ 5 CFR 1320.11 (2016).
---------------------------------------------------------------------------

    63. In this NOPR, the Commission proposes to amend its pro forma 
LGIA and pro forma SGIA in accordance with section 35.28(f)(1) of its 
regulations.\141\ The proposed revisions to the pro forma LGIA and pro 
forma SGIA would require new large and small generating facilities to 
install, maintain, and operate a functioning governor or equivalent 
controls which the Commission proposes to define as the required 
hardware and/or software that provides frequency responsive real power 
control with the ability to sense changes in system frequency and 
autonomously adjust the generating facility's real power output in 
accordance with the proposed maximum droop and dead band parameters and 
in the direction needed to correct frequency deviations. The NOPR 
proposes to require each public utility transmission provider to amend 
its pro forma LGIA and pro forma SGIA to require that all newly 
interconnecting large and small generating facilities, as well as all 
existing large and small generating facilities that take any action 
that requires the submission of a new interconnection request that 
results in the filing of an executed or unexecuted interconnection 
agreement, to adhere to the proposed requirements, on or after the 
effective date of any Final Rule issued in this proceeding.
---------------------------------------------------------------------------

    \141\ 18 CFR 35.28(f)(1) (2016).
---------------------------------------------------------------------------

    64. The reforms in this NOPR would require filings of pro forma 
LGIAs and pro forma SGIAs with the Commission. The Commission 
anticipates the proposed reforms, once implemented, would not 
significantly change currently existing burdens on an ongoing basis. 
With regard to those public utility transmission providers that believe 
that they already comply with the proposed reforms in this NOPR, they 
could demonstrate their compliance in the filing required 60 days after 
publication of the Final Rule in the Federal Register. The Commission 
will submit the proposed reporting requirements to OMB for its review 
and approval under section 3507(d) of the Paperwork Reduction Act.\142\ 
The Commission will use FERC-516B as a temporary ``placeholder'' 
information collection number.\143\
---------------------------------------------------------------------------

    \142\ 44 U.S.C. 3507(d) (2012).
    \143\ The reporting requirements in this NOPR would normally be 
included under FERC-516 (OMB Control No. 1902-0096). However, FERC-
516 is pending review at OMB in an unrelated action. Because only 
one item per OMB Control No. can be pending OMB review at a time, 
the Commission is temporarily using the information collection 
number FERC-516B (OMB Control No. 1902-0286) to ensure timely 
submittal of this NOPR to OMB.
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    Burden Estimate: \144\ The Commission believes that the burden 
estimates below are representative of the average burden on 
respondents. The estimated burden and cost for the requirements 
contained in this NOPR follow.\145\
---------------------------------------------------------------------------

    \144\ Burden means the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, 
disclose or provide information to or for a Federal agency, 
including: The time, effort, and financial resources necessary to 
comply with a collection of information that would be incurred by 
persons in the normal course of their activities (e.g., in compiling 
and maintaining business records) will be excluded from the 
``burden'' if the agency demonstrates that the reporting, 
recordkeeping, or disclosure activities needed to comply are usual 
and customary.
    \145\ For this information collection, the Commission staff 
estimates that industry is similarly situated in terms of hourly 
cost (wages plus benefits). Based on the Commission's average cost 
(wages plus benefits) for 2016, the Commission is using $74.50/hour.

                                                              FERC 516B, in NOPR in RM16-6
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        Number of    Annual  number
                                       respondents    of  responses   Total number   Average burden (hours) & cost    Total annual burden hours & total
                                          \146\      per respondent   of responses          ($) per response                   annual cost ($)
                                                (1)             (2)     (1) * (2) =  (4)..........................  (3) * (4) = (5)
                                                                                (3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LGIA & SGIA changes/revisions......              74               1              74  10 hours; $745.00............  740 hours; $55,130.00.
                                    --------------------------------------------------------------------------------------------------------------------
    Total..........................  ..............  ..............              74  .............................  740 hours; $55,130.00.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    There are no maintenance cost, installation cost or any additional 
cost or requirements after year 1.
---------------------------------------------------------------------------

    \146\ The NERC Compliance Registry lists 80 entities that 
administer a transmission tariff and provide transmission service. 
The Commission identifies only 74 as being subject to the proposed 
requirements because 6 are Canadian entities and are not under the 
Commission's jurisdiction.
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    Title: FERC-516B, Electric Rate Schedules and Tariff Filings.
    Action: Revision of currently approved collection of information.
    OMB Control No.: 1902-0286.
    Respondents for this Rulemaking: Businesses or other for profit 
and/or not-for-profit institutions.
    Frequency of Information: One-time during year 1.
    Necessity of Information: The Commission proposes to revise its 
regulations to require all newly interconnecting large and small

[[Page 85188]]

generating facilities, both synchronous and non-synchronous, to 
install, maintain, and operate equipment capable of providing primary 
frequency response as a condition of interconnection. To implement 
these requirements, the Commission proposes to revise the pro forma 
LGIA and the pro forma SGIA.
    Internal Review: The Commission has reviewed the proposed changes 
and has determined that the changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has assured itself, by means of internal review, that there 
is specific, objective support for the burden estimates associated with 
the information collection requirements.
    65. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
    66. Comments on the collection of information and the associated 
burden estimate in the proposed rule should be sent to the Commission 
in this docket and may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission], at the following email address: 
oira_submission@omb.eop.gov. Please refer to OMB Control No. 1902-0286 
in your submission.

IV. Environmental Analysis

    67. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\147\ The 
Commission concludes that neither an Environmental Assessment or an 
Environmental Impact Statement is required for proposed revisions under 
section 380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale of electric energy subject to 
the Commission's jurisdiction, plus the classification, practices, 
contracts and regulations that affect rates, charges, classifications, 
and services.\148\ The revisions proposed in this NOPR update and 
clarify the application of the Commission's standard interconnection 
requirements to synchronous and non-synchronous generators. Therefore, 
this NOPR falls within the categorical exemptions provided in the 
Commission's regulations, and therefore neither an Environmental 
Assessment nor an Environmental Impact Statement is required.
---------------------------------------------------------------------------

    \147\ Order No. 486, Regulations Implementing the National 
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 
Regs. Preambles 1986-1990 ] 30,783 (1987).
    \148\ 18 CFR 380.4(a)(15) (2015).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act

    68. The Regulatory Flexibility Act of 1980 (RFA) \149\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities. 
The RFA does not mandate any particular outcome in a rulemaking. It 
only requires consideration of alternatives that are less burdensome to 
small entities and an agency explanation of why alternatives were 
rejected.
---------------------------------------------------------------------------

    \149\ 5 U.S.C. 601-612 (2012).
---------------------------------------------------------------------------

    69. The Small Business Administration (SBA) revised its size 
standards (effective January 22, 2014) for electric utilities from a 
standard based on megawatt hours to a standard based on the number of 
employees, including affiliates. Under SBA's standards, some 
transmission owners will fall under the following category and 
associated size threshold: Electric bulk power transmission and 
control, at 500 employees.\150\
---------------------------------------------------------------------------

    \150\ 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121 
(Electric Bulk Power Transmission and Control).
---------------------------------------------------------------------------

    70. The Commission estimates that the total number of transmission 
providers, both public and non-public, affected by this NOPR is 
74.\151\ Of these, the Commission estimates that approximately 27.5 
percent are small entities. The Commission estimates the average total 
cost to each of these entities will be minimal, requiring on average 10 
hours, or $745.00. According to SBA guidance, the determination of 
significance of impact ``should be seen as relative to the size of the 
business, the size of the competitor's business, and the impact the 
regulation has on larger competitors.'' \152\ The Commission does not 
consider the estimated burden to be a significant economic impact. As a 
result, the Commission believes this NOPR would not have a significant 
economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \151\ The NERC Compliance Registry lists 80 entities that 
administer a transmission tariff and provide transmission service. 
The Commission identifies only 74 as being subject to the proposed 
requirements because 6 are Canadian entities and are not under the 
Commission's jurisdiction.
    \152\ U.S. Small Business Administration, A Guide for Government 
Agencies: How to Comply with the Regulatory Flexibility Act, at 18 
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------

    71. The Commission estimates that the total annual number of new 
non-synchronous interconnections per year for the first few years of 
potential implementation under this NOPR would be approximately 200, 
representing approximately 5,000 MW of installed capacity. Of these, 
the Commission estimates that the majority are small entities. The 
Commission estimates the average total cost to each of these entities 
will be minimal, requiring on average approximately $3,300 per MW of 
installed capacity. According to SBA guidance, the determination of 
significance of impact ``should be seen as relative to the size of the 
business, the size of the competitor's business, and the impact the 
regulation has on larger competitors.'' The Commission does not 
consider the estimated burden to be a significant economic impact on 
these entities because the cost is relatively minimal compared to the 
average capital cost per MW for wind and solar PV generation.\153\ 
Additionally, the Commission does not believe that there will be 
substantial additional costs for new synchronous generators because 
synchronous generators already come equipped with governors that 
provide the capability to provide primary frequency response. 
Accordingly, the Commission believes that this NOPR would not have a 
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \153\ LBNL estimates that capital cost per MW of installed wind 
capacity is $1,690,000. See LBNL 2015 Wind Market Report (Aug. 
2016), https://emp.lbl.gov/sites/all/files/2015-windtechreport.final_.pdf). NREL estimates that the capital cost per 
MW of installed solar PV capacity is $1,770,000. See NREL U.S. 
Photovoltaic Prices and Cost Breakdowns (Sep. 2015), http://www.nrel.gov/docs/fy15osti/64746.pdf.
---------------------------------------------------------------------------

VI. Comment Procedures

    72. The Commission invites interested persons to submit comments on 
the matters and issues proposed in this notice to be adopted, including 
any related matters or alternative proposals that commenters may wish 
to discuss. Comments are due January 24, 2017. Comments must refer to 
Docket No. RM16-6-000, and must include the commenter's name, the 
organization they represent, if applicable, and their address in their 
comments.

[[Page 85189]]

    73. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    74. Commenters that are not able to file comments electronically 
must send an original of their comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    75. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

VII. Document Availability

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

    By direction of the Commission.

    Issued: November 17, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Appendix



               List of Commenters (Docket No. RM16-6-000)
------------------------------------------------------------------------
 
------------------------------------------------------------------------
AES Companies................  AES Corporation/AES Energy Storage/Dayton
                                Power and Light Company/Indianapolis
                                Power and Light Company.
APPA, et al..................  American Public Power Association/Large
                                Public Power Council/Transmission Access
                                Policy Study Group.
AWEA.........................  American Wind Energy Association.
Apex.........................  Apex Compressed Air Energy Storage.
APS..........................  Arizona Public Service Company.
Bonneville...................  Bonneville Power Administration.
CAISO........................  California Independent System Operator.
Chelan County................  Chelan County Public Utility District.
California Cities............  City of Anaheim/City of Azusa/City of
                                Banning/City of Colton/City of Pasadena/
                                City of Riverside.
EEI..........................  Edison Electric Institute.
EDP..........................  EDP Renewables North America.
EPRI.........................  Electric Power Research Institute.
EPSA, et al..................  Electric Power Supply Association/
                                Independent Power Producers of New York/
                                New England Power Generators Association/
                                Western Power Trading Forum.
ELCON........................  Electricity Consumers Resource Council.
ESA..........................  Energy Storage Association.
Grid Storage Consulting......  Grid Storage Consulting.
Howard F. Illian.............  Howard F. Illian
Idaho Power..................  Idaho Power Company.
Indicated ISOs/RTOs..........  Independent Electricity System Operator/
                                ISO New England/New York Independent
                                System Operator/PJM Interconnection/
                                Southwest Power Pool.
IEEE-P1547 Working Group.....  Institute of Electrical and Electronics
                                Engineers (IEEE) P1547 Standards Working
                                Group.
IEEE-PES.....................  IEEE Power and Energy Society Technical
                                Council.
ITC, et al...................  International Transmission Company/
                                Michigan Electric Transmission Company/
                                ITC Great Plains/ITC Midwest.
Manitoba.....................  Manitoba Hydro.
Microgrids Resources           Microgrids Resources Coalition.
 Coalition.
MISO.........................  Midcontinent Independent System Operator.
MISO TOs.....................  Midcontinent Independent System Operator
                                Transmission Owners.
NARUC........................  National Association of Regulatory
                                Utility Commissioners.
NRECA........................  National Rural Electric Cooperative
                                Association.
NERC.........................  North American Electric Reliability
                                Corporation.
North American Generator       North American Generator Forum.
 Forum.
Nuclear Energy Institute.....  Nuclear Energy Institute.
PG&E.........................  Pacific Gas and Electric Company.
Peak Reliability.............  Peak Reliability.
PJM Utilities Coalition......  PJM Utilities Coalition.
Powerex......................  Powerex Corp.
Public Interest Organizations  Public Interest Organizations.
Ralph D. Masiello............  Ralph D. Masiello.
SDG&E........................  San Diego Gas & Electric Company.
Solar City...................  Solar City Corporation.
SoCal Edison.................  Southern California Edison Company.
Southern Company.............  Southern Company.
Steel Producers..............  Steel Producers.

[[Page 85190]]

 
Tacoma Power.................  Tacoma Power.
TVA..........................  Tennessee Valley Authority.
Tri-State Generation.........  Tri-State Generation and Transmission
                                Association.
Union of Concerned Scientists  Union of Concerned Scientists.
WIRAB........................  Western Interconnection Regional Advisory
                                Body.
------------------------------------------------------------------------

[FR Doc. 2016-28321 Filed 11-23-16; 8:45 am]
 BILLING CODE 6717-01-P