Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response, 9182-9192 [2016-03837]

Download as PDF 9182 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Docket No. EL16–39–000] mstockstill on DSK4VPTVN1PROD with NOTICES Tri-State Generation and Transmission Association, Inc.; Notice of Petition for Declaratory Order Take notice that on February 17, 2016, pursuant to Rule 207 of the Commission’s Rules of Practice and Procedure of the Federal Energy Regulatory Commission’s (Commission), 18 CFR 385.207(2015), Tri-State Generation and Transmission Association, Inc. (Tri-State) filed a petition for declaratory order finding that Tri-State’s fixed cost recovery proposal contained in revised Board Policy 101 is consistent with the Public Utility Regulatory Policies Act of 1978 and the Commission’s implementing regulaltions, as more fully explained in the petition. Any person desiring to intervene or to protest in this proceeding must file in accordance with Rules 211 and 214 of the Commission’s Rules of Practice and Procedure (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. Anyone filing a motion to intervene or protest must serve a copy of that document on the Petitioner. The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at http:// www.ferc.gov. To facilitate electronic service, persons with Internet access who will eFile a document and/or be listed as a contact for an intervenor must create and validate an eRegistration account using the eRegistration link. Select the eFiling link to log on and submit the intervention or protests. Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426. The filings in the above proceeding are accessible in the Commission’s eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 Commission’s Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email FERCOnlineSupport@ferc.gov.or call (866) 208–3676 (toll free). For TTY, call (202) 502–8659. Comment Date: 5:00 p.m. Eastern time on March 18, 2016. Dated: February 18, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. SUPPLEMENTARY INFORMATION: [FR Doc. 2016–03835 Filed 2–23–16; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Docket No. RM16–6–000] Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response Federal Energy Regulatory Commission, Energy. ACTION: Notice of Inquiry. AGENCY: In this Notice of Inquiry, the Federal Energy Regulatory Commission (Commission) seeks comment on the need for reforms to its rules and regulations regarding the provision and compensation of primary frequency response. DATES: Comments are due April 25, 2016. ADDRESSES: You may submit comments, identified by docket number and in accordance with the requirements posted on the Commission’s Web site, http://www.ferc.gov. Comments may be submitted by any of the following methods: • Agency Web site: Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format, at http://www.ferc.gov/docs-filing/ efiling.asp. • Mail/Hand Delivery: Those unable to file electronically must 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: SUMMARY: PO 00000 Frm 00022 Fmt 4703 Sfmt 4703 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. 1. In this Notice of Inquiry (NOI), the Commission seeks comment on the need for reforms to its rules and regulations regarding the provision and compensation of primary frequency response. In recent years, the nation’s electric supply portfolio has transformed to a point where fewer resources may now be providing primary frequency response than when the Commission considered this issue in other relevant proceedings. As discussed below, in light of the changing resource mix and other factors, it is reasonable to expect this trend to continue. Considering the significance of primary frequency response to the reliable operation of the Bulk-Power System,1 the Commission seeks input on whether and what action is needed to address the provision and compensation of primary frequency response. 2. Specifically, the Commission seeks comment on whether amendments to the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA) are warranted to require all new generation resources to have frequency response capabilities as a precondition of interconnection. The Commission also seeks comment on the performance of existing resources and whether primary frequency response requirements for these resources are warranted. Further, the Commission seeks comment on the requirement to provide and compensate for primary frequency response. 1 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). E:\FR\FM\24FEN1.SGM 24FEN1 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices I. Background mstockstill on DSK4VPTVN1PROD with NOTICES A. Technical Overview: The Nature and Operation of Frequency Response 3. Reliably operating an Interconnection 2 requires maintaining balance between generation and load so that frequency remains within predetermined boundaries around a scheduled value (60 Hz in the United States). Interconnections occasionally experience system contingencies (e.g., the loss of a large generator) that disrupt the balance between generation and load. These contingencies result in frequency deviations that can potentially cause under frequency load shedding (UFLS), additional generation tripping, or cascading outages.3 Consequently, some generators within an Interconnection automatically deploy frequency control actions, including inertial response and primary frequency response, during disturbances to arrest and stabilize frequency deviations. The reliability of the Bulk-Power System depends in part on the operating characteristics of generating resources that balancing authorities 4 commit to serve load. However, not all generating resources provide frequency support services, which are essential to maintaining the reliability and stability of the Bulk-Power System.5 4. Frequency response is a measure of an Interconnection’s ability to arrest and stabilize frequency deviations within pre-determined limits following the sudden loss of generation or load. Frequency response is affected by the collective responses of generation and load resources throughout the entire Interconnection. Inertial response, primary frequency response, and secondary frequency response all contribute to stabilizing the Bulk-Power System by correcting frequency deviations. 2 An Interconnection is a geographic area in which the operation of Bulk-Power System components is synchronized. In the continental United States, there are three Interconnections, namely the Eastern, Electric Reliability Council of Texas (ERCOT), 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. Automatic Underfrequency Load Shedding and Load Shedding Plans Reliability Standards, Notice of Proposed Rulemaking, 137 FERC ¶ 61,067 (2011). 4 The North American Electric Reliability Corporation’s (NERC) 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.’’ 5 As discussed below, NERC Reliability Standard BAL–003–1 has requirements related to frequency response, but it is applicable to balancing authorities and not individual generating resources. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 5. Inertial response, or system inertia, involves the release or absorption of kinetic energy by the rotating masses of online generation and load within an Interconnection, and is the result of the coupling between the rotating masses of synchronous generation and load and the electric system.6 An Interconnection’s inertial response influences how fast frequency drops after the loss of generation and how fast it rises after a reduction of load. The less system inertia there is, the faster the rate of change of frequency 7 during disturbances. An adequate amount of system inertia is important since following the sudden loss of generation, inertia serves to reduce the rate of change of frequency, allowing time for primary frequency response actions to arrest the frequency deviation and stabilize the power system. 6. Primary frequency response, net of changes in generation real power (MW) output and power consumed by load in response to a frequency deviation, is the first stage of overall frequency control, begins within seconds after the frequency changes, and is critical to the reliable operation of the Bulk-Power System.8 Primary frequency response is mostly provided by the automatic and autonomous actions (i.e., outside of system operator control) of turbinegovernors, while some response is provided by frequency responsive loads due to changes in system frequency. Primary frequency response actions are intended to arrest the frequency deviation until it reaches the minimum frequency, or nadir.9 An important goal for system planners and operators is for the frequency nadir, during large disturbances, to remain above the first stage of firm UFLS set points within an Interconnection. The time-frame to arrest frequency deviations typically ranges from five to 15 seconds, depending on the Interconnection. 7. Secondary frequency response involves changes to the MW output of 6 See, e.g., Use of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable Integration of Variable Renewable Generation, Ernest Orlando Lawrence Berkeley National Laboratory, at 13–14 (December 2010), available at: http://energy.lbl.gov/ea/certs/pdf/lbnl4142e.pdf (LBNL Frequency Response Metrics Report). 7 Rate of change of frequency is mainly a function of the magnitude of the loss of generation (or load) and system inertia and is measured in Hz/second. 8 See, e.g., LBNL Frequency Response Metrics Report at 15–16. 9 The point at which the frequency decline is arrested (following the sudden loss of generation) is called the frequency nadir, and represents the point in which the net primary frequency response (MW) output from all generating units and the decrease in power consumed by the load within an Interconnection matches the net initial MW loss of generation. PO 00000 Frm 00023 Fmt 4703 Sfmt 4703 9183 resources on automatic generation control (e.g., regulation resources) that respond to dispatch instructions.10 Secondary frequency response actions usually begin after 30 seconds or more following a contingency, and can take 5 minutes or more to restore system frequency to its scheduled value. B. Evolving Generation Resource Mix 8. The nation’s generation resource mix is undergoing a transformation that includes the retirement of baseload, synchronous units, with large rotational inertia. The changing resource mix also includes the integration of more distributed generation, demand response, and natural gas resources, and the rapid expansion of variable energy resources (VERs) 11 such as wind and solar.12 Several factors, such as existing and proposed federal and state environmental regulations, renewable portfolio standards, tax incentives, and low natural gas prices, have driven these developments. 9. During 2015, natural gas-fired generation surpassed coal as the predominant fuel source for electric generation, and is now the leading fuel type for capacity additions.13 In addition, NERC recently determined that there has been almost 50 GW of baseload (e.g., coal, nuclear, petroleum, and natural gas) retirements since 2011.14 10. In addition, between 2014 and 2015, all three U.S. Interconnections have experienced growth in the installed nameplate capacity of wind and solar generation. For example, as illustrated by the figure below, NERC 10 See e.g., LBNL Frequency Response Metrics Report at 9–11. 11 For the purposes of this proceeding, the term Variable Energy Resource refers to 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. This includes, for example, wind, solar thermal and photovoltaic, and hydrokinetic generating facilities. See Integration of Variable Energy Resources, Order No. 764, FERC Stats. & Regs. ¶ 31,331 at n. 1 (2012), order on reh’g and clarification, Order No. 764–A, 141 FERC ¶ 61,232 (2012), order on clarification and reh’g, Order No. 764–B, 144 FERC ¶ 61,222 (2013). 12 The Solar Energy Industries Association (SEIA) recently reported that more than 50 percent of newly installed electric generating capacity in the U.S. came from solar generation in the first quarter of 2015. See SEIA Solar Market Insight Report 2015 Q1 (2015), http://www.seia.org/research-resources/ solar-market-insight-report-2015-q1. 13 See NERC 2015 Long Term Reliability Assessment at 1 (December 2015), http:// www.nerc.com/pa/RAPA/ra/ Reliability%20Assessments%20DL/2015LTRA%20%20Final%20Report.pdf. 14 See NERC 2015 Summer Reliability Assessment at 5 (May 2015), http://www.nerc.com/ pa/RAPA/ra/Reliability%20Assessments%20DL/ 2015_Summer_Reliability_Assessment.pdf. E:\FR\FM\24FEN1.SGM 24FEN1 9184 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices solar capacity, representing a growth rate of 12 percent and 116 percent over the respective 2014 levels of 33.5 GW and 0.73 GW;16 (2) ERCOT had 14.7 GW of wind and 0.18 GW of solar, representing a growth rate of 29 percent and 50 percent over the respective 2014 levels of 11.4 GW and 0.12 GW;17 and (3) Western Interconnection had 24.8 GW of wind and 8.4 GW of solar, representing a growth rate of 17 percent and 11 percent over the respective 2014 levels of 21.1 GW and 7.6 GW.18 11. The changing generation resource mix has the potential to reduce the inertial response within some Interconnections, as VERs do not contribute to inertia unless they are specifically designed to do so. For example, solar photovoltaic resources have no rotating mass and thus no rotational inertia. Similarly, while wind turbines have a rotating mass, power converters that interconnect modern wind turbines decouple the rotation of their turbines from the grid. As such, modern wind turbines do not contribute to the system’s inertia unless specifically configured to do so.19 Therefore, increased numbers of VERs, in conjunction with significant retirements of large conventional resources with large rotational inertia, have the potential to reduce system inertia. 12. In addition, VERs do not provide primary frequency response unless specifically configured to do so. Furthermore, since VERs typically have low marginal costs of production, they would likely not be dispatched in a manner necessary to provide primary frequency response, since the provision of primary frequency response involves the reservation of capacity (or ‘‘headroom’’) in order for a resource to automatically increase its MW output in response to drops in system frequency. Therefore, there is a significant risk that, as conventional synchronous resources retire or are displaced by increased numbers of VERs that do not typically have primary frequency response capabilities, the net amount of frequency responsive generation online will be reduced.20 13. The combined impacts of lower system inertia and lower frequency responsive capability online may adversely affect reliability during disturbances because lower system inertia results in more rapid frequency deviations during disturbances. This, in turn, may result in lower frequency nadirs, particularly if the primary frequency capability online is not sufficiently fast. This is a potential reliability concern because, as the frequency nadir lowers, it approaches the Interconnection’s UFLS trip setting, which could result in the loss of load and additional generation across the Interconnection. 14. These developments and their potential impacts could challenge system operators in maintaining reliability. The Commission believes that a substantial body of evidence has emerged warranting consideration of possible actions to ensure that resources capable of providing primary frequency 15 NERC 2015 Summer Reliability Assessment, Table 3 at page 7. 16 Id. 17 Id. 18 Id. 19 See, e.g., General Electric WindINERTIA Control Fact Sheet (2009), http://site.ge-energy.com/ prod_serv/products/renewable_energy/en/ downloads/GEA17210.pdf. 20 Non-synchronous generators such as VERs (e.g., wind and solar resources) produce electricity that is not synchronized to the electric grid (i.e., direct current (DC) power or alternating current (AC) power at a frequency other than 60 hertz). Inverters convert non-synchronized AC or DC power into synchronized AC power that can be transmitted on the transmission system. These resources do not operate in the same way as conventional generators and respond differently to network disturbances. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00024 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1 EN24FE16.030</GPH> mstockstill on DSK4VPTVN1PROD with NOTICES has observed that the three Interconnections collectively added approximately 11.1 GW of wind and 1.73 GW of solar generation between 2014 and 2015.15 More specifically, in 2015: (1) The Eastern Interconnection had 37.6 GW of wind and 1.6 GW of Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices mstockstill on DSK4VPTVN1PROD with NOTICES response are adequately maintained as the nation’s resource mix continues to evolve. 15. 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.21 The Task Force focused on three essential reliability services: frequency support, ramping capability, and voltage support.22 16. The Task Force considered the seven ancillary services 23 adopted by the Commission in Order Nos. 888 24 and 890 25 as a subset of the essential reliability services that may need to be augmented by additional services as the Bulk-Power System characteristics change. However, the Task Force did not intend to recommend new reliability standards or propose actions to alter the existing suite of ancillary services.26 Instead, its focus was on educating and informing industry and other stakeholders about essential reliability services, developing measures and industry best practices for tracking essential reliability services, and developing recommendations to ensure 21 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 (April 2014), http://www.nerc.com/ comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ ERSTF_Final.pdf. 22 Essential Reliability Services Task Force Measures Report at 22 (December 2015), http:// www.nerc.com/comm/Other/ essntlrlbltysrvcstskfrcDL/ ERSTF%20Framework%20Report%20%20Final.pdf. 23 The seven ancillary services 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. 24 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). 25 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). 26 NERC Essential Reliability Services Task Force Scope Document at 2. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 that essential reliability services continue to be provided as the nation’s generation resource mix evolves.27 17. The reliability of the Bulk-Power System will be increasingly dependent upon the operational characteristics of natural gas and renewable generating units, as these types of resources are expected to comprise an increasing percentage of the future generation resource mix. The Task Force stated that ‘‘the reliability of the electric grid depends on the operating characteristics of the replacement resources.’’ 28 NERC observed that ‘‘wind, solar, and other variable energy resources that are an increasingly greater share of the BulkPower System provide a significantly lower level of essential reliability services than conventional generation.’’ 29 The Task Force concluded that it is prudent and necessary to ensure that primary frequency capabilities are present in the future generation resource mix, and recommends that all new generators support the capability to manage frequency.30 18. Contributing to the concerns associated with the nature and operational characteristics of the evolving resource mix is the uncertainty whether a resource configured to provide primary frequency response is willing and able to offer such a service when called upon to do so. While almost all existing synchronous resources and some non-synchronous resources have governors or equivalent control equipment capable of providing primary frequency response, generator owners and operators can independently decide whether units provide primary frequency response.31 19. For example, at present, it is possible for a generator owner/operator to block or disable the governor or to set a wide dead band setting. A wide dead band setting can result in a unit not providing primary frequency response for most frequency deviations. As discussed more fully below, in February 2015, NERC issued an Industry 27 Id. 28 Essential Reliability Services Task Force Measures Report at iv. 29 See NERC State of Reliability 2015 Report at 16 (May 2015), http://www.nerc.com/pa/RAPA/PA/ Performance%20Analysis%20DL/ 2015%20State%20of%20Reliability.pdf. 30 Essential Reliability Services Task Force Measures Report at vi. 31 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 MW output due to variations in system frequency. A governor also has a dead band which establishes a minimum frequency deviation (from nominal) that must be exceeded in order for the governor to act. Example droop and dead band settings are 5 percent and ±0.036 Hz, respectively. PO 00000 Frm 00025 Fmt 4703 Sfmt 4703 9185 Advisory which determined that a significant portion of generators within the Eastern Interconnection utilize dead bands or governor control settings that either inhibit or prevent the provision of primary frequency response.32 In response to this issue and other concerns, NERC’s Operating Committee recently approved a 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.33 20. NERC’s State of Reliability Report for 2015 explained that the three U.S. Interconnections currently exhibit stable frequency response performance above their Interconnection Frequency Response Obligations.34 However, NERC has pointed out a historic decline in frequency response performance in both the Western and Eastern Interconnections.35 NERC identified several key reasons for the decline, mainly tied to the primary frequency response performance of generators.36 C. Prior Commission and Industry Actions 21. In this proceeding, the Commission seeks comment on the need 32 NERC Generator Governor Frequency Response Industry Advisory (February 2015), http:// www.nerc.com/pa/rrm/bpsa/Alerts%20DL/ 2015%20Alerts/NERC%20Alert%20A-2015-02-0501%20Generator%20Governor%20Frequency%20 Response.pdf. 33 See NERC Primary Frequency Control Guideline Final Draft (December 2015), http:// www.nerc.com/comm/OC/ Reliability%20Guideline%20DL/Primary_ Frequency_Control_final.pdf. See also NERC Operating Committee Meeting Minutes (January 2016), http://www.nerc.com/comm/OC/Agendas HighlightsMinutes/Operating%20 Committee%20Minutes%20-%20Dec%2015-16 %202015-Final.pdf. 34 NERC State of Reliability Report 2015 at 9 (May 2015). See http://www.nerc.com/pa/RAPA/PA/ Performance%20Analysis%20DL/2015%20State %20of%20Reliability.pdf. Reliability Standard BAL–003–1 establishes Interconnection Frequency Response Obligations that are designed to require sufficient frequency response for each Interconnection to arrest frequency declines even for severe, but possible, contingencies. 35 See NERC Frequency Response Initiative Industry Advisory—Generator Governor Frequency Response at slide 10 (April 2015), http:// www.nerc.com/pa/rrm/Webinars%20DL/Generator_ Governor_Frequency_Response_Webinar_April_ 2015.pdf. See also Review of the Recent Frequency Performance of the Eastern, Western and ERCOT Interconnections, Ernest Orlando Lawrence Berkeley National Laboratory, at pp xiv–xv (December 2010), http://energy.lbl.gov/ea/certs/pdf/ lbnl-4144e.pdf. 36 See NERC Frequency Response Initiative Report: The Reliability Role of Frequency Response (October 2012), http://www.nerc.com/docs/pc/FRI_ Report_10-30-12_Master_w-appendices.pdf (Frequency Response Initiative Report). E:\FR\FM\24FEN1.SGM 24FEN1 9186 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices for reforms to its rules and regulations regarding the provision of primary frequency response. This section offers an overview of Commission and industry action to date related to frequency response to provide the context for the consideration of what, if any, actions the Commission should take to ensure that adequate frequency response is available to maintain grid reliability. 22. In April 1996, the Commission issued Order No. 888, to address undue discrimination in transmission service by requiring all public utilities to provide open access transmission service consistent with the terms of a pro forma Open Access Transmission Tariff (OATT).37 The pro forma OATT sets forth the terms of transmission service including, among other things, the provision of ancillary services. Additionally, the Commission adopted six ancillary services stating they are ‘‘needed to accomplish transmission service while maintaining reliability within and among control areas affected by the transmission service.’’ 38 The ancillary service involved in this proceeding is Regulation and Frequency Response Service, found in Schedule 3 of the pro forma OATT. 23. In July 2003, the Commission issued Order No. 2003, which revised the pro forma OATT to include a pro forma LGIA, which applies to interconnection requests of large generators (i.e., generators larger than 20 MW).39 While the pro forma LGIA adopted standard procedures and a standard agreement for the interconnection of large generating facilities, it was ‘‘designed around the needs of large synchronous generators.’’ 40 The Commission also added a blank Appendix G (Requirements of Generators Relying on Newer Technologies) to the LGIA to serve as a means by which to apply interconnection requirements specific for generators relying on newer technologies, such as wind generators.41 24. In May 2005, the Commission issued Order No. 2006, which required all public utilities to adopt standard 37 Order No. 888, FERC Stats. & Regs. ¶ 31,036. at 31,705. 39 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146, app. 6 (LGIP), app. C (LGIA) (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). 40 Order No. 2003–A, FERC Stats. & Regs. ¶ 31,160 at P 407 & n.85. 41 Id. mstockstill on DSK4VPTVN1PROD with NOTICES 38 Id. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 terms and conditions for new interconnecting small generators (i.e., those no larger than 20 MW) under a pro forma SGIA.42 25. The Commission recently issued a notice of proposed rulemaking to revise the pro forma LGIA and SGIA to eliminate the exemption for wind generators and other non-synchronous generators regarding reactive power requirements.43 The proposed rule proposes to require all newly interconnecting generators, both synchronous and non-synchronous, to provide reactive power. 26. Although the Commission has previously included technical requirements for generators in the LGIA and Large Generator Interconnection Procedures (LGIP),44 both the pro forma LGIA and SGIA are silent with respect to primary frequency response requirements. 27. In a final rule issued on January 16, 2014, the Commission approved Reliability Standard BAL–003–1, which establishes frequency response requirements for balancing authorities.45 Reliability Standard BAL– 003–1 established Interconnection Frequency Response Obligations that prescribe the minimum frequency response that must be maintained by an Interconnection. The purpose of the Interconnection Frequency Response Obligation is to maintain the minimum frequency (nadir) above UFLS set points following the largest contingency of the Interconnection as defined by the resource contingency criteria in BAL– 003–1. Each balancing authority is assigned a Frequency Response Obligation 46 that is a proportionate 42 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). 43 Reactive Power Requirements for NonSynchronous Generation, 153 FERC ¶ 61,175 (2015). 44 For example, in Order Nos. 661 and 661–A, the Commission adopted standard procedures and technical requirements related to low voltage ride thru and power factor design criteria for the interconnection of large wind plants, and required all public utilities that own, control, or operate facilities for transmitting electric energy in interstate commerce to append Appendix G to their LGIPs and LGIAs in their OATTs to include these requirements. Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186, order on reh’g, Order No. 661–A, FERC Stats. & Regs. ¶ 31,198 (2005). 45 Frequency Response and Frequency Bias Setting Reliability Standard, Order No. 794, 146 FERC ¶ 61,024 (2014). Reliability Standards proposed by NERC are submitted to the Commission for approval pursuant to section 215(d) of the FPA; 16 U.S.C. 824o(d). 46 NERC’s Glossary of Terms defines Frequency Response Obligation as ‘‘[t]he balancing authority’s share of the required Frequency Response needed for the reliable operation of an Interconnection.’’ PO 00000 Frm 00026 Fmt 4703 Sfmt 4703 share of the Interconnection Frequency Response Obligation, and is based on its annual generation and load.47 Requirement R1 of BAL–003–1 requires each balancing authority to achieve an annual Frequency Response Measure that equals or exceeds its Frequency Response Obligation. The Frequency Response Measure is the median value of a balancing authority’s frequency response performance during selected events over the course of a year.48 Requirement R1 of BAL–003–1 becomes effective on April 1, 2016, and compliance begins on December 1, 2016. 28. Although Reliability Standard BAL–003–1 requires sufficient frequency response from balancing authorities, on average, to maintain Interconnection frequency, it does not require generators to provide primary frequency response. In the rulemaking in which the Commission approved Reliability Standard BAL–003–1, some commenters expressed concern that the standard does not address the availability of generator resources to provide primary frequency response or the premature withdrawal 49 of primary frequency response. In Order No. 794, the Commission directed NERC to submit a report by July 2018 analyzing the availability of resources for each balancing authority and Frequency Response Sharing Group 50 to meet their Frequency Response Obligation.51 Furthermore, the Commission stated that, if NERC learns that balancing authorities are experiencing difficulty in procuring sufficient resources to satisfy their Frequency Response Obligations, 47 The Interconnection Frequency Response Obligation and Frequency Response Obligation are expressed in MW per 0.1 Hertz (MW/0.1 Hz). 48 Attachment A of BAL–003–1. NERC will identify between 20 to 35 events annually in each Interconnection for calculating the Frequency Response Measure. See also Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard, (November 30, 2012), http:// www.nerc.com/pa/Stand/Project%20200712%20 Frequency%20Response%20DL/Procedure_Clean_ 20121130.pdf. 49 NERC has stated that ‘‘[w]ithdrawal of primary frequency response is an undesirable characteristic associated most often with digital turbine-generator control systems using setpoint output targets for generator output. These are typically outer-loop control systems that defeat the primary frequency response of the governors after a short time to return the unit to operating at a requested MW output.’’ See Order No. 794, 146 FERC ¶ 61,024 at P 65 (citing NERC’s Frequency Response Initiative Report). 50 NERC’s Glossary of Terms defines a Frequency Response Sharing Group as a ‘‘group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the sum of the Frequency Response Obligations of its members.’’ 51 Order No. 794, 146 FERC ¶ 61,024 at P 60. E:\FR\FM\24FEN1.SGM 24FEN1 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices NERC should immediately report it to the Commission with appropriate recommendations for mitigation.52 29. Additionally, in Order No. 794, the Commission stated that the nature and extent of the problems that could result from the premature withdrawal of primary frequency response, and how best to address them, will be better understood after NERC and balancing authorities have more experience with Reliability Standard BAL–003–1.53 The Commission also stated that the need to take action regarding the premature withdrawal of primary frequency response, including requiring load controllers to include a frequency bias term to sustain frequency response or otherwise modifying Reliability Standard BAL–003–1, should be decided after we have actual experience with the Reliability Standard.54 30. In light of the ongoing evolution of the nation’s generation resource mix, and other factors, such as NERC’s Generator Governor Industry Advisory released in February 2015, the Commission believes that it is prudent to take a proactive approach to better understand the issues related to primary frequency response performance and determine what additional actions beyond Reliability Standard BAL–003–1 may be appropriate. Thus, the Commission is proceeding with a Notice of Inquiry at this time rather than waiting until NERC submits a report in 2018. 31. In the absence of national primary frequency response requirements applicable to individual generating resources, some areas, including ERCOT, ISO New England Inc. (ISO– NE), and PJM Interconnection, L.L.C. (PJM), have implemented regional requirements for individual generating resources within their regions in order to maintain reliability. 32. For example, the Commission accepted Texas Reliability Entity Inc.’s Regional Reliability Standard BAL–001– TRE–01 (Primary Frequency Response in the ERCOT Region) as mandatory and enforceable, which places requirements on generator owners and operators with respect to the provision of primary frequency response within the ERCOT region.55 In particular, BAL–001–TRE– mstockstill on DSK4VPTVN1PROD with NOTICES 52 Id. P 63. P 75. 54 Id. P 76. 55 North American Electric Reliability Corporation, 146 FERC ¶ 61,025 (2014). The requirements of BAL–001–TRE–01 help to ensure that generation and load remain balanced—or are quickly restored to balance—in the ERCOT Interconnection so that system frequency is restored to stability and near normal frequency even after a significant event occurs on the system. In Order No. 53 Id. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 01 requires generator owners to operate each generating unit/generating facility that is connected to the interconnected transmission system with the governor in service and responsive to frequency when the generating unit/generating facility is online and released for dispatch, and to promptly notify the balancing authority of any change in governor status.56 Additionally, BAL– 001–TRE–01 requires generator owners to set specified governor dead band and droop parameters.57 Moreover, BAL– 001–TRE–01 requires generator owners to provide minimum initial and sustained primary frequency response performance.58 NERC recently noted that ERCOT experienced a significant improvement in its frequency response performance as generators within its region adjusted their governor settings for compliance with BAL–001–TRE– 01.59 33. ISO–NE requires each generator within its region with a capability of ten MW or more, including renewable resources, to operate with a functioning governor with specified dead band and droop settings, and to also ensure that the provision of primary frequency response is not inhibited by the effects of outer-loop controls.60 34. PJM has pro forma interconnection agreements that obligate interconnection customers within its region to abide by all PJM rules and procedures pertaining to generation and transmission, including rules and procedures set forth in the PJM Manuals.61 PJM requires large, conventional generators to operate on unrestricted governor control to assist in maintaining Interconnection frequency, and recently established specified governor dead band and droop 693, the Commission approved a regional difference for the ERCOT Interconnection from Reliability Standard BAL–001–0, allowing ERCOT to be exempt from Requirement R2, and found that ERCOT’s approach to frequency response under its own market protocols appeared to be more stringent than Requirement R2. Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 313–315. 56 Reliability Standard BAL–001–TRE–01, at Requirements R7 and R8. 57 Reliability Standard BAL–001–TRE–01, at Requirement R6. 58 Reliability Standard BAL–001–TRE–01, at Requirements R9 and R10. 59 NERC 2014 Frequency Response Annual Analysis Report at 6 (February 2015), http:// www.nerc.com/FilingsOrders/us/ NERC%20Filings%20to%20FERC%20DL/Final_ Info_Filing_Freq_Resp_Annual_Report_ 03202015.pdf. See also Table 3 at 6. 60 Section I of ISO–NE’s Operating Procedure No. 14—Technical Requirements for Generators, Demand Resources, Asset Related Demands and Alternative Technology Regulation Resources, http://www.iso-ne.com/rules_proceds/operating/ isone/op14/op14_rto_final.pdf. 61 PJM Tariff, Attachment O § 8.0. PO 00000 Frm 00027 Fmt 4703 Sfmt 4703 9187 requirements for all generating resources (excluding nuclear units) with a gross plant/facility aggregate nameplate rating greater than 75 MVA.62 In addition, PJM recently added new interconnection requirements for interconnection customers entering its queue after May 2015 and seeking to interconnect non-synchronous generators, including wind generators, to use ‘‘enhanced inverters’’ with the capability to, among other things, provide primary frequency response.63 PJM stated that the installed capacity of VERs in its region is expected to increase to approximately 15 GW by the 2016–17 delivery year, and that it has an additional 25 GW of VERs in its interconnection queue.64 PJM expressed a need for VERs to install the capability to automatically reduce or increase their real power output in order to respond to a variety of system conditions, including high or low frequencies. PJM also stated that this capability will provide flexibility in responding to transmission system events using all available resources which, according to PJM, will be increasingly important as VERs displace synchronous generators that have these capabilities.65 D. Compensation for Primary Frequency Response Service 35. This section offers an overview of Commission and industry action to date related to compensation for primary frequency response. At present, there are few, if any, entities receiving compensation for selling primary frequency response as a stand-alone product, and there are no current rates applicable to sales of primary frequency response alone. However, several options for transactions involving primary frequency response have been developed. Transmission providers may sell primary frequency response service in combination with regulation service under the bundled pro forma OATT Schedule 3 product, Regulation and Frequency Response Service.66 62 PJM Manual 14D. Interconnection, L.L.C., 151 FERC ¶ 61,097, at n.58 (2015). 64 PJM Interconnection, L.L.C., Transmittal Letter, Docket No. ER15–1193–000, at 2 (filed Mar. 6, 2015). 65 Id. at 11. 66 Regulation service is different than primary frequency response because regulation resources respond to automatic generation control signals, which responds to Area Control Error. Regulation is centrally coordinated by the balancing authority. Primary frequency response, in contrast, is autonomous and is not centrally coordinated. Schedule 3 lumps these different services together, despite their differences. The Commission in Order No. 888 found that ‘‘while the services provided by Regulation Service and Frequency Response Service 63 PJM E:\FR\FM\24FEN1.SGM Continued 24FEN1 9188 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices mstockstill on DSK4VPTVN1PROD with NOTICES Schedule 3 in the pro forma OATT in Order Nos. 888 67 and 890 68 permits jurisdictional transmission providers to outline their rates for this regulation and frequency response service through a filing under FPA section 205. Schedule 3 charges are cost-based rates paid by transmission customers to the transmission provider. Additionally, Order No. 784 made it possible for third-party sellers to offer Schedule 3 service to the transmission provider at a rate up to the published Schedule 3 rate, or at rates that result from an appropriate competitive solicitation.69 Such third-party sales could involve any combination of regulation and primary frequency response services, including unbundled primary frequency response service by itself. 36. Finally, in Order No. 819, the Commission revised its regulations to foster competition in the sale of primary frequency response service.70 In the final rule, the Commission approved the sale of primary frequency response service at market-based rates by entities that qualify for market-based rate authority for sales of energy and capacity to any willing buyer. Order No. 819 focused on how jurisdictional entities can qualify for market-based rates for primary frequency response service in the context of voluntary bilateral sales, and did not place any limits on the types of transactions available to procure primary frequency response service; they may be costbased or market-based, bundled with other services or unbundled, and inside or outside of organized markets.71 Order No. 819 did not require any entity to purchase primary frequency response from third parties or develop an organized market for primary frequency response.72 are different, they are complementary services that are made available using the same equipment. For this reason, we believe that Frequency Response Service and Regulation Service should not be offered separately, but should be offered as part of one service.’’ Order No. 888, FERC Stats. & Regs. ¶ 31,036, at PP 212–213 (1996). 67 Order No. 888, FERC Stats. & Regs. ¶ 31,036. 68 Order No. 890, FERC Stats. & Regs. ¶ 31,241. 69 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, FERC Stats. & Regs. ¶ 31,349, at PP 6–7 (2013), order on clarification, Order No. 784–A, 146 FERC ¶ 61,114 (2014). 70 Third-Party Provision of Primary Frequency Response Service, Order No. 819, 153 FERC ¶ 61,220 (2015). 71 Id. P 13. 72 Id. P 37. The Commission denied Calpine Corporation’s request for Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) to be given a deadline to develop tariff changes that would enable them to implement primary frequency response compensation mechanisms. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 II. Request for Comments 37. The Commission seeks comment on the need for reforms to its rules and regulations regarding the provision and compensation of primary frequency response. Specifically, the Commission seeks comment on possible actions to ensure that the provision of primary frequency response continues to remain at levels adequate to maintain the reliability of the Bulk-Power System in light of the ongoing transformation of the nation’s generation resource mix. The Commission understands that this transformation in the nation’s generation portfolio could eventually result in a reduction of system inertia and fewer generation resources with primary frequency response capabilities. In addition, as discussed above, NERC has indicated that a significant number of generators within the Eastern Interconnection utilize dead bands or governor control settings that either inhibit or prevent the provision of primary frequency response. Together, these factors could result in potential downward shifts of the frequency nadir during disturbances, closer to UFLS set points that would trigger significant widespread outages. 38. Presently, there are no pro forma agreements for primary frequency response transactions. Voluntary sales of primary frequency response, would most likely involve negotiated, bilateral contracts between buyers and sellers. In this regard, considering their compliance obligations under Reliability Standard BAL–003–1, balancing authorities will be the most likely source of demand for voluntary purchases of primary frequency response service from third-party sellers, including those who have not provided the service in the past. Accordingly, as discussed further below, the Commission seeks comment on whether and to what extent balancing authority demand for voluntary purchases of frequency response would be reduced if all or all newly interconnecting resources were required to provide frequency response service. Further, we also seek comment on the impact this would have on the Commission’s efforts under Order No. 819 to foster the development of a bilateral market for market-based rate sales of primary frequency response service as a means of cost-effectively meeting such demand. 39. Within RTO/ISO markets, no current stand-alone primary frequency response product exists. Any RTO/ISO that desires to explicitly procure and compensate primary frequency response would need new tariff provisions PO 00000 Frm 00028 Fmt 4703 Sfmt 4703 because no RTO/ISO currently defines or procures such a product. As discussed below, the Commission seeks comment on the need for and the nature of frequency response compensation within the context of current RTO/ISO market optimization processes. 40. Accordingly, the Commission seeks comment on the following possible actions, discussed in more detail below: (1) Modifications to the pro forma LGIA and SGIA mandating primary frequency response requirements for new resources, among other changes; (2) new primary frequency response requirements for existing resources; and (3) the requirement to provide and compensate for primary frequency response. A. Modifications to the pro forma LGIA and SGIA 41. Reliability Standard BAL–003–1 and the pro forma LGIA and SGIA do not specifically address generators’ provision of primary frequency response. Article 9.6.2.1 of the pro forma LGIA (Governors and Regulators) requires that if speed governors are installed, they should be operated in automatic mode.73 Reliability Standard BAL–003–1 and the pro forma LGIA and SGIA do not explicitly: (1) Require generators to install the necessary capability to provide primary frequency response; (2) prescribe specific governor settings that would support the provision of primary frequency response; 74 or (3) establish generator primary frequency response performance requirements during disturbances (e.g., require the response to be sustained, and not prematurely withdrawn prior to the initiation of secondary frequency response actions to return system frequency back to its nominal value and back within a generator’s dead band setting).75 42. The Commission’s pro forma generator interconnection agreements and procedures were developed at a time when traditional generating resources with standard governor controls and large rotational inertia were the predominant sources of electricity generation. However, circumstances are evolving, with NERC and others predicting significant 73 Order No. 2003, FERC Stats. & Regs. ¶ 31,146, app. C (LGIA). 74 Generator governors can be enabled or disabled which determines whether or not primary frequency response is provided at all by the generator. In addition, even if a governor is enabled, its control settings can limit the conditions under which the generator provides primary frequency response. 75 Primary frequency response would not be expected to be provided if no capacity (or ‘‘headroom’’) is reserved on a unit. E:\FR\FM\24FEN1.SGM 24FEN1 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices mstockstill on DSK4VPTVN1PROD with NOTICES retirements of conventional synchronous resources, all of which contribute to system inertia, and some of which provide primary frequency response. In addition, VERs are projected to comprise an increasing portion of the installed capacity in many regions of the country, but they do not typically provide inertial response or primary frequency response unless specifically configured to do so. 43. Regarding VERs, the Commission understands that in previous years, many non-synchronous resources were not consistently designed with primary frequency response capabilities. However, NERC and others have stated that VER manufacturers have made significant advancements in recent years to develop the necessary controls that would enable VERs to provide frequency response.76 NERC recommends that the industry analyze how wind and solar photovoltaic resources can contribute to frequency response and to work toward interconnection requirements that ensure system operators will continue to maintain essential reliability services.77 Also relevant are PJM’s recent additions of new interconnection requirements for VERs entering its queue after May 2015.78 PJM has stated that the necessary capabilities for nonsynchronous resources to provide primary frequency response, among other services, are now ‘‘baked in’’ as enhancements to inverter capabilities.79 44. In light of the ongoing changes in the nation’s resource mix as well as NERC’s concerns regarding the primary frequency response performance of existing resources, the Commission seeks comment on whether and how to modify the pro forma LGIA and SGIA to require primary frequency response capability and performance of new generating resources. 45. To that end, the Commission seeks comment on the following questions: 1. Should the pro forma LGIA and SGIA be revised to include requirements for all newly interconnecting generating resources, including non-synchronous resources, to: 1.1. Install the capability necessary to provide primary frequency response? 1.2. Ensure that prime mover governors (or equivalent frequency control devices) are enabled and set 76 NERC Long Term Reliability Assessment at 27 (November 2014), http://www.nerc.com/pa/RAPA/ ra/Reliability%20Assessments%20DL/2014LTRA_ ERATTA.pdf. 77 Id. 78 PJM Interconnection, L.L.C., 151 FERC ¶ 61,097, at n.58 (2015). 79 PJM Interconnection, L.L.C., Docket No. ER15– 1193–000 (March 6, 2015) Transmittal Letter at 11. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 pursuant to NERC’s Primary Frequency Control Guideline (i.e., droop characteristics not to exceed 5 percent, and dead band settings not to exceed ±0.036 Hz)? 1.3. Ensure that the MW response provided (when there is available headroom) in response to frequency deviations above or below the governor’s dead band from 60 Hz is: 1.3.1. Sustained until system frequency returns to within the governor’s dead band setting? 1.3.2. Provided without undue delay and responds in accordance with a specified droop parameter? 2. What are the costs associated with making a newly interconnecting generation resource capable of providing primary frequency response? Specifically, what are the pieces of equipment or software needed to provide primary frequency response, and what are the costs associated with those pieces of equipment or software? Are there significant differences between synchronous and nonsynchronous resources in providing primary frequency response, (e.g., the type of equipment necessary)? 3. Regarding question (1) above, are the governor control settings recommended by NERC’s Primary Frequency Control Guideline the appropriate settings to include in the pro forma LGIA and SGIA? Why or why not? 4. Regarding new resources, including non-synchronous resources, are there physical, technical, or operational limitations/concerns to promptly providing sustained primary frequency response in the direction necessary to counteract under-frequency and overfrequency deviations? How should new requirements account for such limitations? 5. Are metrics or monitoring useful to evaluate whether new resources: 5.1. Operate with governors (or equivalent frequency control devices) enabled? 5.2. Set governor control settings as described in question (1) above? 5.3. Provide sustained MW response (when the unit has available headroom and system frequency deviates outside of the dead band) that is in the direction necessary to correct the frequency deviation and responsive in accordance with a specified droop parameter? 6. How would transmission providers verify that new resources provide adequate primary frequency response performance? 6.1. What information is necessary in order to facilitate performance verification? PO 00000 Frm 00029 Fmt 4703 Sfmt 4703 9189 6.2. What changes, if any, to existing infrastructure (including, but not limited to telemetry and software tools) would be required in order to verify primary frequency response performance? 6.3. What limitations based on resource type, if any, should be considered when evaluating primary frequency response performance? 7. How would transmission providers ensure compliance with the new rules? 7.1. Are penalties appropriate to ensure that new generating resources adhere to the new requirements described in question (1) above, and if so, how should such penalties be structured and implemented? 7.2. Are penalties appropriate only if a resource receives compensation for adhering to the new requirements described in question (1) above? B. New Primary Frequency Response Requirements for Existing Resources 46. The Commission seeks comment on how it might address the issue of primary frequency response performance in existing generators. As discussed above, the Commission is considering amendments to the pro forma LGIA and SGIA that would apply prospectively and only to new generating resources and not the existing generating fleet. However, the Commission notes that NERC has also expressed concerns related to the primary frequency response performance of the existing generating fleet. 47. For example, in 2010, NERC conducted a governor response survey to gain insight into governor settings from several turbine governors across the three U.S. Interconnections.80 Analysis revealed a wide disparity in the reported governor control settings. For example, NERC found that several generator owners or operators reported dead bands between 0.05 Hz and 0.3 Hz, which are wider than those prescribed by ERCOT’S BAL–001–TRE–01 Regional Standard or recommended by NERC’s 2015 Generator Governor Frequency Response Industry Advisory 81 and Primary Frequency Control Guideline.82 48. In February 2015, NERC issued an Industry Advisory, which expressed its determination that a significant portion of generators within the Eastern Interconnection utilize governor dead bands or other control settings that 80 Frequency Response Initiative Report at 87. Generator Governor Frequency Response Industry Advisory. 82 NERC Primary Frequency Control Guideline Final Draft. 81 NERC E:\FR\FM\24FEN1.SGM 24FEN1 9190 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices mstockstill on DSK4VPTVN1PROD with NOTICES either inhibit or prevent the provision of primary frequency response.83 49. Furthermore, some generating units have controls that withdraw primary frequency response prior to the initiation of secondary frequency controls, which is a significant concern in the Eastern Interconnection and a somewhat smaller issue in the Western Interconnection. These controls are known as outer-loop controls to distinguish them from more direct, lower-level control of the generator operations. Primary frequency response withdrawal occurs when outer-loop controls deliberately act to nullify a generator’s governor response and return the unit to operate at a predisturbance scheduled MW output. This is especially problematic when it occurs prior to the activation of secondary response, and has the potential to degrade the overall response of the Interconnection and result in a frequency that declines below the original nadir. NERC has observed that early withdrawal of primary frequency response continues to occur within the Eastern Interconnection.84 50. Furthermore, NERC’s Resources Subcommittee has determined that the majority of gas turbines operate in some type of MW Set Point control mode.85 According to the NERC Resources Subcommittee, the Eastern Interconnection Initiative has uncovered that in order for gas turbines to respond in MW Set Point control mode, an additional frequency algorithm has to be installed.86 Moreover, NERC’s Resources Subcommittee stated that ‘‘the net result is that the gas turbine fleet that has been installed in the past 20+ years is not frequency responsive, [which] has to be corrected.’’ 87 NERC has also observed that in many conventional steam plants, dead band settings exceed the maximum ±0.036 Hz dead band, and the resulting response is squelched and not sustained.88 83 NERC Generator Governor Frequency Response Industry Advisory. 84 NERC 2015 Frequency Response Annual Analysis Report at vi (September 2015), http:// www.nerc.com/comm/OC/ RS%20Landing%20Page%20DL/Related%20Files/ 2015_FRAA_Report_Final.pdf. 85 See News from SERC’s NERC Resources Subcommittee Rep—Primary Frequency Response at 1 (May 2015), https://www.serc1.org/docs/ default-source/outreach/communications/resourcedocuments/serc-transmission-reference/201505---st/ primary-frequency-response.pdf?sfvrsn=2. MW setpoint control mode automatically interrupts governor response in order for a generating unit to maintain a pre-disturbance dispatch. 86 Id. 87 Id. 88 See NERC Generator Governor Frequency Response Advisory—Webinar Questions and Answers at 1 (April 2015), http://www.nerc.com/ VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 51. As noted above, in December 2015, NERC’s Operating Committee approved a 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 during major grid events in order to stabilize and maintain system frequency within allowable limits.89 However, the Commission notes that NERC’s Primary Frequency Control Guideline is not mandatory and enforceable and does not alter any approved Reliability Standards. 52. In light of the above discussion, the Commission seeks to further explore issues regarding the provision of primary frequency response by the existing generation fleet and seeks comment on the following questions: 1. Should the Commission implement primary frequency response requirements for existing resources, as discussed above for new generators? If so, what is an appropriate means of doing so (e.g., changes to transmission provider tariffs or improvements to existing reliability standards)? How would transmission providers ensure that existing resources adhere to new primary frequency response requirements? 2. As noted above, some existing generating units set dead bands wider than those recommended by NERC’s Primary Frequency Control Guideline, and some units have control settings set in a manner that results in the premature withdrawal of primary frequency response. Should the Commission prohibit these practices? If so, by what means? 3. What are the costs of retrofitting existing units, including nonsynchronous resources, and with specific reference to such factors as equipment types and MW capacity, to be capable of providing sustained primary frequency response? 4. Regarding existing units, are there physical, technical, or operational limitations or concerns to promptly providing sustained primary frequency response in the direction necessary to counteract under-frequency and overfrequency deviations? pa/rrm/Webinars%20DL/Generator_Governor_ Frequency_Response_Webinar_QandA_April_ 2015.pdf. 89 NERC Primary Frequency Control Guideline Final Draft. PO 00000 Frm 00030 Fmt 4703 Sfmt 4703 C. Requirement to Provide and Compensate for Primary Frequency Response Service 53. Without the explicit requirement to provide primary frequency response or appropriate compensation for the provision of such service, resource owners may choose to disable or otherwise reduce the provision of primary frequency response from their existing resources or not install the equipment on their new resources.90 54. The Commission seeks information on whether there is a need to establish or modify procurement and compensation mechanisms for primary frequency response, and whether these mechanisms will ensure that the resulting rates are just and reasonable. The Commission invites commenters to share their overall views, including the operational, technical and commercial impacts that may result from mandates to provide primary frequency response. To that end, the Commission seeks comment on the following questions: 1. Should all resources be required to provide minimum levels of: (1) Primary frequency response capability; and (2) primary frequency response performance in real-time? 1.1. ‘‘Capability’’ involves having a turbine governor or equivalent equipment that has the ability to sense changes in system frequency, and is enabled and set with appropriate governor settings (e.g., droop and dead band), and assuming capacity (or ‘‘headroom’’) has been set aside, the physical ability to ramp the resource quickly enough in order to provide useful levels of primary frequency response to help arrest the frequency deviation. 1.2. ‘‘Performance’’ would involve putting the ‘‘capability’’ into actual service: i.e., actually operating the resource with governors or equivalent equipment enabled, ensuring that governor controls (e.g., droop and dead band) and other settings are properly set and coordinated, such that when capacity (or ‘‘headroom’’) has been set aside, the unit promptly provides sustained primary frequency response during frequency excursions, until system frequency returns to within the governor’s dead band setting. 2. Is it necessary for every generating resource to install the capability necessary to provide primary frequency 90 IEEE, Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns (May 2007) (citing Cost of Providing Ancillary Services from Power Plants— Volume 1: A Primer, EPRI TR–1 07270–V1, 4161, Final Report, March 1997), http:// resourcecenter.ieee-pes.org/pes/product/technicalreports/PESTR13. E:\FR\FM\24FEN1.SGM 24FEN1 mstockstill on DSK4VPTVN1PROD with NOTICES Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices response? Or is it more appropriate for balancing authorities to identify and procure the amount of primary frequency response service that they need to meet their obligations under Reliability Standard BAL–003–1 and the optimum mix of resources to meet that need? 2.1. To the extent that balancing authorities are responsible for procuring adequate primary frequency response service, does the current framework for blackstart provide a useful guide for how primary frequency response service could be procured? 2.2. Does the Commission’s recent rulemaking allowing third-party sales of frequency response services at market based rates allow balancing authorities to procure sufficient amounts of primary frequency response as required by BAL– 003–1? 2.3. To the extent that balancing authorities centrally optimize primary frequency response, wherein an algorithm optimizes in the operating horizon the set of resources in which to allocate primary frequency response headroom: Should all newly interconnecting resources be required to install the necessary capability in these areas? Can balancing authorities predict far ahead of the operating horizon the least-cost set of resources from which it will optimize the provision of primary frequency response? 2.4. Would the costs of requiring all resources to have the capability to provide primary frequency response be significantly greater than the costs that would result from an Interconnectionwide or balancing authority-wide optimization of which generators should be capable of providing primary frequency response? 2.5. Would the costs of requiring all new resources to enable and set their governors, or equivalent equipment, to be able to provide primary frequency response in real-time be significantly greater than the costs that would result from an Interconnection-wide or balancing authority-wide optimization of which generators should provide primary frequency response in realtime? 2.6. Please discuss the viability of implementing an Interconnection-wide optimization mechanism. 2.7. Would requiring every resource to be capable of providing primary frequency response result in overprocurement or inefficient investment in primary frequency response capability to the detriment of customers? 2.8. Without rules to compel performance, how would balancing authorities ensure that the optimal set of VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 resources chosen by an optimization algorithm actually enable governor controls with appropriate governor settings so that they provide sustained primary frequency response when capacity (or ‘‘headroom’’) has been reserved and frequency deviates outside of their dead band settings? 3. If generation resources were required to have minimum levels of primary frequency response capability or performance, should such resources be compensated for providing primary frequency response capability, performance, or both? If so, why? If not, why? 3.1. If payment is based on capacity (or ‘‘headroom’’) that is set aside for primary frequency response, how should such a capacity payment be structured and determined? 3.2. If payment is based on actual performance, either alone or in combination with a capacity-based payment, please discuss possible rate structures applicable to primary frequency response performance. 3.3. Will a market price provide resources with sufficient incentive to invest in primary frequency response capability and make the service available to the balancing authority in real-time, absent a requirement that resources maintain the capability to provide primary frequency response and perform as required? 4. Currently, how do RTOs/ISOs ensure that they have the appropriate amount of primary frequency response capability during operations? 4.1. Are resources contracted for primary frequency response outside of the market optimization and dispatch? 4.2. Alternatively, does the market optimization and dispatch incorporate primary frequency response in its optimization? 5. Would it be appropriate for RTOs/ ISOs to create a product for primary frequency response service? 5.1. Should this product be similar to a capacity product for the procurement of primary frequency response capability from resources? 5.2. Should this product be similar to other ancillary service products in which certain resources would be selected in the day-ahead or real-time markets to provide primary frequency response? 5.3. Are there benefits to cooptimizing the capacity (or ‘‘headroom’’) allocated on generating units for primary frequency response with the market optimization and dispatch of RTOs/ISOs? If so, what are the challenges associated with doing so? 6. Are there benefits to separating Frequency Response Service under PO 00000 Frm 00031 Fmt 4703 Sfmt 4703 9191 Schedule 3 and creating a separate ancillary service covering each individually? If so, how should a new pro forma Primary Frequency Response Ancillary Service be structured? 7. When compensating for primary frequency response, should compensation be different inside and outside of RTOs/ISOs? 8. What procurement requirements or compensation mechanisms could be used for primary frequency response from stored energy resources? When considering requirements or compensation for stored energy resources, how should possible additional costs or other concerns be addressed? III. Comment Procedures 55. The Commission invites interested persons to submit comments, and other information on the matters, issues and specific questions identified in this notice. Comments are due April 25, 2016. 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. 56. 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. 57. 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. 58. 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. IV. Document Availability 59. 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 FERC’s Home Page (http:// www.ferc.gov) and in FERC’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern E:\FR\FM\24FEN1.SGM 24FEN1 9192 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices time) at 888 First Street NE., Room 2A, Washington, DC 20426. 60. From FERC’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. 61. User assistance is available for eLibrary and the FERC’s Web site during normal business hours from FERC 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: February 18, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2016–03837 Filed 2–23–16; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Docket No. RM11–6–000] mstockstill on DSK4VPTVN1PROD with NOTICES Billing Procedures for Annual Charges for Recompensing the United States for the Use, Occupancy, and Enjoyment of Federal Lands; Notice of Statement of Annual Charges for the Use of Government Lands for Fiscal Year 2016 By this notice, the Commission states that in accordance to the Final Rule issued on January 17, 2013 1 the federal lands fee schedule of per-acre rates have been calculated for Fiscal Years (FY) 2016 through 2020. Pursuant to the Final Rule, the Commission recalculates the federal lands fee schedule every five years by using the per-acre land values published in the National Agricultural Statistics Service (NASS) Census. The Commission established the FY 2016 through FY 2020 federal lands fee schedule based on data published in the 2012 NASS Census. In addition, the Commission determines a state-specific reduction that removes the value of irrigated lands on a state-bystate basis, plus a seven percent reduction to remove the value of buildings. An encumbrance factor of 50 1 Annual Charges for Use of Government Lands, Final Rule, Order No. 774, 78 FR 5256 (January 25, 2013), 142 FERC Stats & Regs. ¶ 61,045 (2013). VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 percent along with a rate of return of 5.77 percent are calculated with the peracre land values less the state-specific reduction to derive at the individual state/county per-acre federal land rates assessed to hydropower projects. The FY 2016 federal lands fee schedule rates have significantly increased in comparison to the FY 2015 federal lands fee schedule rates issued on January 8, 2015 for a number of hydropower projects located in multiple states/counties. In particular, hydropower projects located in the Kenai Peninsula Area of Alaska land rates increased by 71 percent in comparison to land rates assessed in FY 2015. The FY 2016 increase of per-acre land rates was mainly attributed to the increase of per-acre land and building values published in the 2012 NASS Census. The per-acre land value for land in the Kenai Peninsula Area was increased from $1,328 in the 2007 NASS Census to $2,423 in the 2012 NASS Census. This increase along with factoring in the state-specific reduction, the 50 percent encumbrance factor, and the 5.77 percent rate of return ultimately resulted in a 71 percent increase of peracre land rates assessed to hydropower projects located in the Kenai Peninsula Area. In addition, per-acre land values for San Bernardino County located in California, Boulder and Clear Creek Counties located in Colorado, and Blaine County located in Idaho all significantly increased as a result of the 2012 published NASS Census. Conversely, the FY 2016 federal lands fee schedule rates have significantly decreased in comparison to the FY 2015 federal lands fee schedule rates issued on January 8, 2015 for a number of hydropower projects located in other locations as a result of the decreased per-acre land values published in the 2012 NASS Census. Specifically hydropower projects occupying federal lands in Alpine, Lake, and Riverside Counties located in California, Aleutian Islands Area located in Alaska, and Grays Harbor County located in Washington will receive as much as a 37 percent decrease in comparison to the federal lands annual charges issued in FY 2015. If you have any questions regarding this notice, please contact Steven Bromberek at (202) 502–8001 or Norman Richardson at (202) 502–6219. Dated: February 18, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2016–03829 Filed 2–23–16; 8:45 am] BILLING CODE 6717–01–P PO 00000 Frm 00032 Fmt 4703 Sfmt 4703 DEPARTMENT OF ENERGY Federal Energy Regulatory Commission Notice Revising Post-Technical Conference Comment Schedule Docket Nos. PJM Interconnection, L.L.C ... Consolidated Edison Company of New York, Inc. v. PJM Interconnection, L.L.C. Linden VFT, LLC v. PJM Interconnection, L.L.C. Delaware Public Service Commission and Maryland Public Service Commission v. PJM Interconnection, L.L.C. PJM Interconnection, L.L.C ... PJM Interconnection, L.L.C ... ER15–2562–000, ER15–2563–000. EL15–18–001. EL15–67–000. EL15–95–000. ER14–972–003. ER14–1485–005, Not Consolidated. In an order dated November 24, 2015,1 the Commission found that the assignment of cost allocation for the projects in the filings and complaints listed in the caption using PJM’s solution-based distribution factor (DFAX) cost allocation method had not been shown to be just and reasonable and may be unjust, unreasonable, or unduly discriminatory or preferential. The Commission directed its staff to establish a technical conference to explore both whether there is a definable category of reliability projects within PJM for which the solution-based DFAX cost allocation method may not be just and reasonable, such as projects addressing reliability violations that are not related to flow on the planned transmission facility, and whether an alternative just and reasonable ex ante cost allocation method could be established for any such category of projects. The technical conference was held on January 12, 2016. At the technical conference, staff indicated that it would establish a schedule for post-technical conference comments after reviewing the technical conference transcript. On February 9, 2016 a technical conference transcript was place in the abovereferenced dockets, and a post-technical conference comment schedule was established. On February 18, 2016, an errata transcript of the February 9, 2016 transcript was placed in the dockets. The schedule for post-technical conference comments is revised accordingly. Post-technical conference comments, not to exceed 20 pages, are due on or before March 9, 2016. 1 PJM Interconnection, L.L.C., et al., 153 FERC ¶ 61,245 (2015). E:\FR\FM\24FEN1.SGM 24FEN1

Agencies

[Federal Register Volume 81, Number 36 (Wednesday, February 24, 2016)]
[Notices]
[Pages 9182-9192]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-03837]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RM16-6-000]


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

AGENCY:  Federal Energy Regulatory Commission, Energy.

ACTION:  Notice of Inquiry.

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SUMMARY:  In this Notice of Inquiry, the Federal Energy Regulatory 
Commission (Commission) seeks comment on the need for reforms to its 
rules and regulations regarding the provision and compensation of 
primary frequency response.

DATES:  Comments are due April 25, 2016.

ADDRESSES:  You may submit comments, identified by docket number and in 
accordance with the requirements posted on the Commission's Web site, 
http://www.ferc.gov. Comments may be submitted by any of the following 
methods:
     Agency Web site: Documents created electronically using 
word processing software should be filed in native applications or 
print-to-PDF format and not in a scanned format, at http://www.ferc.gov/docs-filing/efiling.asp.
     Mail/Hand Delivery: Those unable to file electronically 
must 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 Inquiry (NOI), the Commission seeks comment on 
the need for reforms to its rules and regulations regarding the 
provision and compensation of primary frequency response. In recent 
years, the nation's electric supply portfolio has transformed to a 
point where fewer resources may now be providing primary frequency 
response than when the Commission considered this issue in other 
relevant proceedings. As discussed below, in light of the changing 
resource mix and other factors, it is reasonable to expect this trend 
to continue. Considering the significance of primary frequency response 
to the reliable operation of the Bulk-Power System,\1\ the Commission 
seeks input on whether and what action is needed to address the 
provision and compensation of primary frequency response.
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    \1\ 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).
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    2. Specifically, the Commission seeks comment on whether amendments 
to the pro forma Large Generator Interconnection Agreement (LGIA) and 
Small Generator Interconnection Agreement (SGIA) are warranted to 
require all new generation resources to have frequency response 
capabilities as a precondition of interconnection. The Commission also 
seeks comment on the performance of existing resources and whether 
primary frequency response requirements for these resources are 
warranted. Further, the Commission seeks comment on the requirement to 
provide and compensate for primary frequency response.

[[Page 9183]]

I. Background

A. Technical Overview: The Nature and Operation of Frequency Response

    3. Reliably operating an Interconnection \2\ requires maintaining 
balance between generation and load so that frequency remains within 
predetermined boundaries around a scheduled value (60 Hz in the United 
States). Interconnections occasionally experience system contingencies 
(e.g., the loss of a large generator) that disrupt the balance between 
generation and load. These contingencies result in frequency deviations 
that can potentially cause under frequency load shedding (UFLS), 
additional generation tripping, or cascading outages.\3\ Consequently, 
some generators within an Interconnection automatically deploy 
frequency control actions, including inertial response and primary 
frequency response, during disturbances to arrest and stabilize 
frequency deviations. The reliability of the Bulk-Power System depends 
in part on the operating characteristics of generating resources that 
balancing authorities \4\ commit to serve load. However, not all 
generating resources provide frequency support services, which are 
essential to maintaining the reliability and stability of the Bulk-
Power System.\5\
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    \2\ An Interconnection is a geographic area in which the 
operation of Bulk-Power System components is synchronized. In the 
continental United States, there are three Interconnections, namely 
the Eastern, Electric Reliability Council of Texas (ERCOT), 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. Automatic Underfrequency Load Shedding and 
Load Shedding Plans Reliability Standards, Notice of Proposed 
Rulemaking, 137 FERC ] 61,067 (2011).
    \4\ The North American Electric Reliability Corporation's (NERC) 
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.''
    \5\ As discussed below, NERC Reliability Standard BAL-003-1 has 
requirements related to frequency response, but it is applicable to 
balancing authorities and not individual generating resources.
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    4. Frequency response is a measure of an Interconnection's ability 
to arrest and stabilize frequency deviations within pre-determined 
limits following the sudden loss of generation or load. Frequency 
response is affected by the collective responses of generation and load 
resources throughout the entire Interconnection. Inertial response, 
primary frequency response, and secondary frequency response all 
contribute to stabilizing the Bulk-Power System by correcting frequency 
deviations.
    5. Inertial response, or system inertia, involves the release or 
absorption of kinetic energy by the rotating masses of online 
generation and load within an Interconnection, and is the result of the 
coupling between the rotating masses of synchronous generation and load 
and the electric system.\6\ An Interconnection's inertial response 
influences how fast frequency drops after the loss of generation and 
how fast it rises after a reduction of load. The less system inertia 
there is, the faster the rate of change of frequency \7\ during 
disturbances. An adequate amount of system inertia is important since 
following the sudden loss of generation, inertia serves to reduce the 
rate of change of frequency, allowing time for primary frequency 
response actions to arrest the frequency deviation and stabilize the 
power system.
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    \6\ See, e.g., Use of Frequency Response Metrics to Assess the 
Planning and Operating Requirements for Reliable Integration of 
Variable Renewable Generation, Ernest Orlando Lawrence Berkeley 
National Laboratory, at 13-14 (December 2010), available at: http://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf (LBNL Frequency Response 
Metrics Report).
    \7\ Rate of change of frequency is mainly a function of the 
magnitude of the loss of generation (or load) and system inertia and 
is measured in Hz/second.
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    6. Primary frequency response, net of changes in generation real 
power (MW) output and power consumed by load in response to a frequency 
deviation, is the first stage of overall frequency control, begins 
within seconds after the frequency changes, and is critical to the 
reliable operation of the Bulk-Power System.\8\ Primary frequency 
response is 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 due to changes 
in system frequency. Primary frequency response actions are intended to 
arrest the frequency deviation until it reaches the minimum frequency, 
or nadir.\9\ An important goal for system planners and operators is for 
the frequency nadir, during large disturbances, to remain above the 
first stage of firm UFLS set points within an Interconnection. The 
time-frame to arrest frequency deviations typically ranges from five to 
15 seconds, depending on the Interconnection.
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    \8\ See, e.g., LBNL Frequency Response Metrics Report at 15-16.
    \9\ The point at which the frequency decline is arrested 
(following the sudden loss of generation) is called the frequency 
nadir, and represents the point in which the net primary frequency 
response (MW) output from all generating units and the decrease in 
power consumed by the load within an Interconnection matches the net 
initial MW loss of generation.
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    7. Secondary frequency response involves changes to the MW output 
of resources on automatic generation control (e.g., regulation 
resources) that respond to dispatch instructions.\10\ Secondary 
frequency response actions usually begin after 30 seconds or more 
following a contingency, and can take 5 minutes or more to restore 
system frequency to its scheduled value.
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    \10\ See e.g., LBNL Frequency Response Metrics Report at 9-11.
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B. Evolving Generation Resource Mix

    8. The nation's generation resource mix is undergoing a 
transformation that includes the retirement of baseload, synchronous 
units, with large rotational inertia. The changing resource mix also 
includes the integration of more distributed generation, demand 
response, and natural gas resources, and the rapid expansion of 
variable energy resources (VERs) \11\ such as wind and solar.\12\ 
Several factors, such as existing and proposed federal and state 
environmental regulations, renewable portfolio standards, tax 
incentives, and low natural gas prices, have driven these developments.
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    \11\ For the purposes of this proceeding, the term Variable 
Energy Resource refers to 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. This includes, for example, wind, solar thermal and 
photovoltaic, and hydrokinetic generating facilities. See 
Integration of Variable Energy Resources, Order No. 764, FERC Stats. 
& Regs. ] 31,331 at n. 1 (2012), order on reh'g and clarification, 
Order No. 764-A, 141 FERC ] 61,232 (2012), order on clarification 
and reh'g, Order No. 764-B, 144 FERC ] 61,222 (2013).
    \12\ The Solar Energy Industries Association (SEIA) recently 
reported that more than 50 percent of newly installed electric 
generating capacity in the U.S. came from solar generation in the 
first quarter of 2015. See SEIA Solar Market Insight Report 2015 Q1 
(2015), http://www.seia.org/research-resources/solar-market-insight-report-2015-q1.
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    9. During 2015, natural gas-fired generation surpassed coal as the 
predominant fuel source for electric generation, and is now the leading 
fuel type for capacity additions.\13\ In addition, NERC recently 
determined that there has been almost 50 GW of baseload (e.g., coal, 
nuclear, petroleum, and natural gas) retirements since 2011.\14\
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    \13\ See NERC 2015 Long Term Reliability Assessment at 1 
(December 2015), http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015LTRA%20-%20Final%20Report.pdf.
    \14\ See NERC 2015 Summer Reliability Assessment at 5 (May 
2015), http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015_Summer_Reliability_Assessment.pdf
.
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    10. In addition, between 2014 and 2015, all three U.S. 
Interconnections have experienced growth in the installed nameplate 
capacity of wind and solar generation. For example, as illustrated by 
the figure below, NERC

[[Page 9184]]

has observed that the three Interconnections collectively added 
approximately 11.1 GW of wind and 1.73 GW of solar generation between 
2014 and 2015.\15\ More specifically, in 2015: (1) The Eastern 
Interconnection had 37.6 GW of wind and 1.6 GW of solar capacity, 
representing a growth rate of 12 percent and 116 percent over the 
respective 2014 levels of 33.5 GW and 0.73 GW;\16\ (2) ERCOT had 14.7 
GW of wind and 0.18 GW of solar, representing a growth rate of 29 
percent and 50 percent over the respective 2014 levels of 11.4 GW and 
0.12 GW;\17\ and (3) Western Interconnection had 24.8 GW of wind and 
8.4 GW of solar, representing a growth rate of 17 percent and 11 
percent over the respective 2014 levels of 21.1 GW and 7.6 GW.\18\
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    \15\ NERC 2015 Summer Reliability Assessment, Table 3 at page 7.
    \16\ Id.
    \17\ Id.
    \18\ Id.
    [GRAPHIC] [TIFF OMITTED] TN24FE16.030
    
    11. The changing generation resource mix has the potential to 
reduce the inertial response within some Interconnections, as VERs do 
not contribute to inertia unless they are specifically designed to do 
so. For example, solar photovoltaic resources have no rotating mass and 
thus no rotational inertia. Similarly, while wind turbines have a 
rotating mass, power converters that interconnect modern wind turbines 
decouple the rotation of their turbines from the grid. As such, modern 
wind turbines do not contribute to the system's inertia unless 
specifically configured to do so.\19\ Therefore, increased numbers of 
VERs, in conjunction with significant retirements of large conventional 
resources with large rotational inertia, have the potential to reduce 
system inertia.
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    \19\ See, e.g., General Electric WindINERTIA Control Fact Sheet 
(2009), http://site.ge-energy.com/prod_serv/products/renewable_energy/en/downloads/GEA17210.pdf.
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    12. In addition, VERs do not provide primary frequency response 
unless specifically configured to do so. Furthermore, since VERs 
typically have low marginal costs of production, they would likely not 
be dispatched in a manner necessary to provide primary frequency 
response, since the provision of primary frequency response involves 
the reservation of capacity (or ``headroom'') in order for a resource 
to automatically increase its MW output in response to drops in system 
frequency. Therefore, there is a significant risk that, as conventional 
synchronous resources retire or are displaced by increased numbers of 
VERs that do not typically have primary frequency response 
capabilities, the net amount of frequency responsive generation online 
will be reduced.\20\
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    \20\ Non-synchronous generators such as VERs (e.g., wind and 
solar resources) produce electricity that is not synchronized to the 
electric grid (i.e., direct current (DC) power or alternating 
current (AC) power at a frequency other than 60 hertz). Inverters 
convert non-synchronized AC or DC power into synchronized AC power 
that can be transmitted on the transmission system. These resources 
do not operate in the same way as conventional generators and 
respond differently to network disturbances.
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    13. The combined impacts of lower system inertia and lower 
frequency responsive capability online may adversely affect reliability 
during disturbances because lower system inertia results in more rapid 
frequency deviations during disturbances. This, in turn, may result in 
lower frequency nadirs, particularly if the primary frequency 
capability online is not sufficiently fast. This is a potential 
reliability concern because, as the frequency nadir lowers, it 
approaches the Interconnection's UFLS trip setting, which could result 
in the loss of load and additional generation across the 
Interconnection.
    14. These developments and their potential impacts could challenge 
system operators in maintaining reliability. The Commission believes 
that a substantial body of evidence has emerged warranting 
consideration of possible actions to ensure that resources capable of 
providing primary frequency

[[Page 9185]]

response are adequately maintained as the nation's resource mix 
continues to evolve.
    15. 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.\21\ The Task Force focused on three essential 
reliability services: frequency support, ramping capability, and 
voltage support.\22\
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    \21\ 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 (April 2014), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
    \22\ Essential Reliability Services Task Force Measures Report 
at 22 (December 2015), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report%20-%20Final.pdf.
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    16. The Task Force considered the seven ancillary services \23\ 
adopted by the Commission in Order Nos. 888 \24\ and 890 \25\ as a 
subset of the essential reliability services that may need to be 
augmented by additional services as the Bulk-Power System 
characteristics change. However, the Task Force did not intend to 
recommend new reliability standards or propose actions to alter the 
existing suite of ancillary services.\26\ Instead, its focus was on 
educating and informing industry and other stakeholders about essential 
reliability services, developing measures and industry best practices 
for tracking essential reliability services, and developing 
recommendations to ensure that essential reliability services continue 
to be provided as the nation's generation resource mix evolves.\27\
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    \23\ The seven ancillary services 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.
    \24\ 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).
    \25\ 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).
    \26\ NERC Essential Reliability Services Task Force Scope 
Document at 2.
    \27\ Id.
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    17. The reliability of the Bulk-Power System will be increasingly 
dependent upon the operational characteristics of natural gas and 
renewable generating units, as these types of resources are expected to 
comprise an increasing percentage of the future generation resource 
mix. The Task Force stated that ``the reliability of the electric grid 
depends on the operating characteristics of the replacement 
resources.'' \28\ NERC observed that ``wind, solar, and other variable 
energy resources that are an increasingly greater share of the Bulk-
Power System provide a significantly lower level of essential 
reliability services than conventional generation.'' \29\ The Task 
Force concluded that it is prudent and necessary to ensure that primary 
frequency capabilities are present in the future generation resource 
mix, and recommends that all new generators support the capability to 
manage frequency.\30\
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    \28\ Essential Reliability Services Task Force Measures Report 
at iv.
    \29\ See NERC State of Reliability 2015 Report at 16 (May 2015), 
http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2015%20State%20of%20Reliability.pdf.
    \30\ Essential Reliability Services Task Force Measures Report 
at vi.
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    18. Contributing to the concerns associated with the nature and 
operational characteristics of the evolving resource mix is the 
uncertainty whether a resource configured to provide primary frequency 
response is willing and able to offer such a service when called upon 
to do so. While almost all existing synchronous resources and some non-
synchronous resources have governors or equivalent control equipment 
capable of providing primary frequency response, generator owners and 
operators can independently decide whether units provide primary 
frequency response.\31\
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    \31\ 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 MW output due to 
variations in system frequency. A governor also has a dead band 
which establishes a minimum frequency deviation (from nominal) that 
must be exceeded in order for the governor to act. Example droop and 
dead band settings are 5 percent and 0.036 Hz, 
respectively.
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    19. For example, at present, it is possible for a generator owner/
operator to block or disable the governor or to set a wide dead band 
setting. A wide dead band setting can result in a unit not providing 
primary frequency response for most frequency deviations. As discussed 
more fully below, in February 2015, NERC issued an Industry Advisory 
which determined that a significant portion of generators within the 
Eastern Interconnection utilize dead bands or governor control settings 
that either inhibit or prevent the provision of primary frequency 
response.\32\ In response to this issue and other concerns, NERC's 
Operating Committee recently approved a 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.\33\
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    \32\ NERC Generator Governor Frequency Response Industry 
Advisory (February 2015), http://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A-2015-02-05-01%20Generator%20Governor%20Frequency%20Response.pdf.
    \33\ See NERC Primary Frequency Control Guideline Final Draft 
(December 2015), http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_final.pdf. 
See also NERC Operating Committee Meeting Minutes (January 2016), 
http://www.nerc.com/comm/OC/AgendasHighlightsMinutes/Operating%20Committee%20Minutes%20-%20Dec%2015-16%202015-Final.pdf.
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    20. NERC's State of Reliability Report for 2015 explained that the 
three U.S. Interconnections currently exhibit stable frequency response 
performance above their Interconnection Frequency Response 
Obligations.\34\ However, NERC has pointed out a historic decline in 
frequency response performance in both the Western and Eastern 
Interconnections.\35\ NERC identified several key reasons for the 
decline, mainly tied to the primary frequency response performance of 
generators.\36\
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    \34\ NERC State of Reliability Report 2015 at 9 (May 2015). See 
http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2015%20State%20of%20Reliability.pdf. Reliability Standard BAL-003-1 
establishes Interconnection Frequency Response Obligations that are 
designed to require sufficient frequency response for each 
Interconnection to arrest frequency declines even for severe, but 
possible, contingencies.
    \35\ See NERC Frequency Response Initiative Industry Advisory--
Generator Governor Frequency Response at slide 10 (April 2015), 
http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. See 
also Review of the Recent Frequency Performance of the Eastern, 
Western and ERCOT Interconnections, Ernest Orlando Lawrence Berkeley 
National Laboratory, at pp xiv-xv (December 2010), http://energy.lbl.gov/ea/certs/pdf/lbnl-4144e.pdf.
    \36\ See NERC Frequency Response Initiative Report: The 
Reliability Role of Frequency Response (October 2012), http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf 
(Frequency Response Initiative Report).
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C. Prior Commission and Industry Actions

    21. In this proceeding, the Commission seeks comment on the need

[[Page 9186]]

for reforms to its rules and regulations regarding the provision of 
primary frequency response. This section offers an overview of 
Commission and industry action to date related to frequency response to 
provide the context for the consideration of what, if any, actions the 
Commission should take to ensure that adequate frequency response is 
available to maintain grid reliability.
    22. In April 1996, the Commission issued Order No. 888, to address 
undue discrimination in transmission service by requiring all public 
utilities to provide open access transmission service consistent with 
the terms of a pro forma Open Access Transmission Tariff (OATT).\37\ 
The pro forma OATT sets forth the terms of transmission service 
including, among other things, the provision of ancillary services. 
Additionally, the Commission adopted six ancillary services stating 
they are ``needed to accomplish transmission service while maintaining 
reliability within and among control areas affected by the transmission 
service.'' \38\ The ancillary service involved in this proceeding is 
Regulation and Frequency Response Service, found in Schedule 3 of the 
pro forma OATT.
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    \37\ Order No. 888, FERC Stats. & Regs. ] 31,036.
    \38\ Id. at 31,705.
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    23. In July 2003, the Commission issued Order No. 2003, which 
revised the pro forma OATT to include a pro forma LGIA, which applies 
to interconnection requests of large generators (i.e., generators 
larger than 20 MW).\39\ While the pro forma LGIA adopted standard 
procedures and a standard agreement for the interconnection of large 
generating facilities, it was ``designed around the needs of large 
synchronous generators.'' \40\ The Commission also added a blank 
Appendix G (Requirements of Generators Relying on Newer Technologies) 
to the LGIA to serve as a means by which to apply interconnection 
requirements specific for generators relying on newer technologies, 
such as wind generators.\41\
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    \39\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, app. 6 
(LGIP), app. C (LGIA) (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).
    \40\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 407 & 
n.85.
    \41\ Id.
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    24. In May 2005, the Commission issued Order No. 2006, which 
required all public utilities to adopt standard terms and conditions 
for new interconnecting small generators (i.e., those no larger than 20 
MW) under a pro forma SGIA.\42\
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    \42\ 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).
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    25. The Commission recently issued a notice of proposed rulemaking 
to revise the pro forma LGIA and SGIA to eliminate the exemption for 
wind generators and other non-synchronous generators regarding reactive 
power requirements.\43\ The proposed rule proposes to require all newly 
interconnecting generators, both synchronous and non-synchronous, to 
provide reactive power.
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    \43\ Reactive Power Requirements for Non-Synchronous Generation, 
153 FERC ] 61,175 (2015).
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    26. Although the Commission has previously included technical 
requirements for generators in the LGIA and Large Generator 
Interconnection Procedures (LGIP),\44\ both the pro forma LGIA and SGIA 
are silent with respect to primary frequency response requirements.
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    \44\ For example, in Order Nos. 661 and 661-A, the Commission 
adopted standard procedures and technical requirements related to 
low voltage ride thru and power factor design criteria for the 
interconnection of large wind plants, and required all public 
utilities that own, control, or operate facilities for transmitting 
electric energy in interstate commerce to append Appendix G to their 
LGIPs and LGIAs in their OATTs to include these requirements. 
Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs. 
] 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs. ] 
31,198 (2005).
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    27. In a final rule issued on January 16, 2014, the Commission 
approved Reliability Standard BAL-003-1, which establishes frequency 
response requirements for balancing authorities.\45\ Reliability 
Standard BAL-003-1 established Interconnection Frequency Response 
Obligations that prescribe the minimum frequency response that must be 
maintained by an Interconnection. The purpose of the Interconnection 
Frequency Response Obligation is to maintain the minimum frequency 
(nadir) above UFLS set points following the largest contingency of the 
Interconnection as defined by the resource contingency criteria in BAL-
003-1. Each balancing authority is assigned a Frequency Response 
Obligation \46\ that is a proportionate share of the Interconnection 
Frequency Response Obligation, and is based on its annual generation 
and load.\47\ Requirement R1 of BAL-003-1 requires each balancing 
authority to achieve an annual Frequency Response Measure that equals 
or exceeds its Frequency Response Obligation. The Frequency Response 
Measure is the median value of a balancing authority's frequency 
response performance during selected events over the course of a 
year.\48\ Requirement R1 of BAL-003-1 becomes effective on April 1, 
2016, and compliance begins on December 1, 2016.
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    \45\ Frequency Response and Frequency Bias Setting Reliability 
Standard, Order No. 794, 146 FERC ] 61,024 (2014). Reliability 
Standards proposed by NERC are submitted to the Commission for 
approval pursuant to section 215(d) of the FPA; 16 U.S.C. 824o(d).
    \46\ NERC's Glossary of Terms defines Frequency Response 
Obligation as ``[t]he balancing authority's share of the required 
Frequency Response needed for the reliable operation of an 
Interconnection.''
    \47\ The Interconnection Frequency Response Obligation and 
Frequency Response Obligation are expressed in MW per 0.1 Hertz (MW/
0.1 Hz).
    \48\ Attachment A of BAL-003-1. NERC will identify between 20 to 
35 events annually in each Interconnection for calculating the 
Frequency Response Measure. See also Procedure for ERO Support of 
Frequency Response and Frequency Bias Setting Standard, (November 
30, 2012), http://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/Procedure_Clean_20121130.pdf.
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    28. Although Reliability Standard BAL-003-1 requires sufficient 
frequency response from balancing authorities, on average, to maintain 
Interconnection frequency, it does not require generators to provide 
primary frequency response. In the rulemaking in which the Commission 
approved Reliability Standard BAL-003-1, some commenters expressed 
concern that the standard does not address the availability of 
generator resources to provide primary frequency response or the 
premature withdrawal \49\ of primary frequency response. In Order No. 
794, the Commission directed NERC to submit a report by July 2018 
analyzing the availability of resources for each balancing authority 
and Frequency Response Sharing Group \50\ to meet their Frequency 
Response Obligation.\51\ Furthermore, the Commission stated that, if 
NERC learns that balancing authorities are experiencing difficulty in 
procuring sufficient resources to satisfy their Frequency Response 
Obligations,

[[Page 9187]]

NERC should immediately report it to the Commission with appropriate 
recommendations for mitigation.\52\
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    \49\ NERC has stated that ``[w]ithdrawal of primary frequency 
response is an undesirable characteristic associated most often with 
digital turbine-generator control systems using setpoint output 
targets for generator output. These are typically outer-loop control 
systems that defeat the primary frequency response of the governors 
after a short time to return the unit to operating at a requested MW 
output.'' See Order No. 794, 146 FERC ] 61,024 at P 65 (citing 
NERC's Frequency Response Initiative Report).
    \50\ NERC's Glossary of Terms defines a Frequency Response 
Sharing Group as a ``group whose members consist of two or more 
Balancing Authorities that collectively maintain, allocate, and 
supply operating resources required to jointly meet the sum of the 
Frequency Response Obligations of its members.''
    \51\ Order No. 794, 146 FERC ] 61,024 at P 60.
    \52\ Id. P 63.
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    29. Additionally, in Order No. 794, the Commission stated that the 
nature and extent of the problems that could result from the premature 
withdrawal of primary frequency response, and how best to address them, 
will be better understood after NERC and balancing authorities have 
more experience with Reliability Standard BAL-003-1.\53\ The Commission 
also stated that the need to take action regarding the premature 
withdrawal of primary frequency response, including requiring load 
controllers to include a frequency bias term to sustain frequency 
response or otherwise modifying Reliability Standard BAL-003-1, should 
be decided after we have actual experience with the Reliability 
Standard.\54\
---------------------------------------------------------------------------

    \53\ Id. P 75.
    \54\ Id. P 76.
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    30. In light of the ongoing evolution of the nation's generation 
resource mix, and other factors, such as NERC's Generator Governor 
Industry Advisory released in February 2015, the Commission believes 
that it is prudent to take a proactive approach to better understand 
the issues related to primary frequency response performance and 
determine what additional actions beyond Reliability Standard BAL-003-1 
may be appropriate. Thus, the Commission is proceeding with a Notice of 
Inquiry at this time rather than waiting until NERC submits a report in 
2018.
    31. In the absence of national primary frequency response 
requirements applicable to individual generating resources, some areas, 
including ERCOT, ISO New England Inc. (ISO-NE), and PJM 
Interconnection, L.L.C. (PJM), have implemented regional requirements 
for individual generating resources within their regions in order to 
maintain reliability.
    32. For example, the Commission accepted Texas Reliability Entity 
Inc.'s Regional Reliability Standard BAL-001-TRE-01 (Primary Frequency 
Response in the ERCOT Region) as mandatory and enforceable, which 
places requirements on generator owners and operators with respect to 
the provision of primary frequency response within the ERCOT 
region.\55\ In particular, BAL-001-TRE-01 requires generator owners to 
operate each generating unit/generating facility that is connected to 
the interconnected transmission system with the governor in service and 
responsive to frequency when the generating unit/generating facility is 
online and released for dispatch, and to promptly notify the balancing 
authority of any change in governor status.\56\ Additionally, BAL-001-
TRE-01 requires generator owners to set specified governor dead band 
and droop parameters.\57\ Moreover, BAL-001-TRE-01 requires generator 
owners to provide minimum initial and sustained primary frequency 
response performance.\58\ NERC recently noted that ERCOT experienced a 
significant improvement in its frequency response performance as 
generators within its region adjusted their governor settings for 
compliance with BAL-001-TRE-01.\59\
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    \55\ North American Electric Reliability Corporation, 146 FERC ] 
61,025 (2014). The requirements of BAL-001-TRE-01 help to ensure 
that generation and load remain balanced--or are quickly restored to 
balance--in the ERCOT Interconnection so that system frequency is 
restored to stability and near normal frequency even after a 
significant event occurs on the system. In Order No. 693, the 
Commission approved a regional difference for the ERCOT 
Interconnection from Reliability Standard BAL-001-0, allowing ERCOT 
to be exempt from Requirement R2, and found that ERCOT's approach to 
frequency response under its own market protocols appeared to be 
more stringent than Requirement R2. Order No. 693, FERC Stats. & 
Regs. ] 31,242 at PP 313-315.
    \56\ Reliability Standard BAL-001-TRE-01, at Requirements R7 and 
R8.
    \57\ Reliability Standard BAL-001-TRE-01, at Requirement R6.
    \58\ Reliability Standard BAL-001-TRE-01, at Requirements R9 and 
R10.
    \59\ NERC 2014 Frequency Response Annual Analysis Report at 6 
(February 2015), http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Final_Info_Filing_Freq_Resp_Annual_Report_03202015.pdf. See also 
Table 3 at 6.
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    33. ISO-NE requires each generator within its region with a 
capability of ten MW or more, including renewable resources, to operate 
with a functioning governor with specified dead band and droop 
settings, and to also ensure that the provision of primary frequency 
response is not inhibited by the effects of outer-loop controls.\60\
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    \60\ Section I of ISO-NE's Operating Procedure No. 14--Technical 
Requirements for Generators, Demand Resources, Asset Related Demands 
and Alternative Technology Regulation Resources, http://www.iso-ne.com/rules_proceds/operating/isone/op14/op14_rto_final.pdf.
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    34. PJM has pro forma interconnection agreements that obligate 
interconnection customers within its region to abide by all PJM rules 
and procedures pertaining to generation and transmission, including 
rules and procedures set forth in the PJM Manuals.\61\ PJM requires 
large, conventional generators to operate on unrestricted governor 
control to assist in maintaining Interconnection frequency, and 
recently established specified governor dead band and droop 
requirements for all generating resources (excluding nuclear units) 
with a gross plant/facility aggregate nameplate rating greater than 75 
MVA.\62\ In addition, PJM recently added new interconnection 
requirements for interconnection customers entering its queue after May 
2015 and seeking to interconnect non-synchronous generators, including 
wind generators, to use ``enhanced inverters'' with the capability to, 
among other things, provide primary frequency response.\63\ PJM stated 
that the installed capacity of VERs in its region is expected to 
increase to approximately 15 GW by the 2016-17 delivery year, and that 
it has an additional 25 GW of VERs in its interconnection queue.\64\ 
PJM expressed a need for VERs to install the capability to 
automatically reduce or increase their real power output in order to 
respond to a variety of system conditions, including high or low 
frequencies. PJM also stated that this capability will provide 
flexibility in responding to transmission system events using all 
available resources which, according to PJM, will be increasingly 
important as VERs displace synchronous generators that have these 
capabilities.\65\
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    \61\ PJM Tariff, Attachment O Sec.  8.0.
    \62\ PJM Manual 14D.
    \63\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58 
(2015).
    \64\ PJM Interconnection, L.L.C., Transmittal Letter, Docket No. 
ER15-1193-000, at 2 (filed Mar. 6, 2015).
    \65\ Id. at 11.
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D. Compensation for Primary Frequency Response Service

    35. This section offers an overview of Commission and industry 
action to date related to compensation for primary frequency response. 
At present, there are few, if any, entities receiving compensation for 
selling primary frequency response as a stand-alone product, and there 
are no current rates applicable to sales of primary frequency response 
alone. However, several options for transactions involving primary 
frequency response have been developed. Transmission providers may sell 
primary frequency response service in combination with regulation 
service under the bundled pro forma OATT Schedule 3 product, Regulation 
and Frequency Response Service.\66\

[[Page 9188]]

Schedule 3 in the pro forma OATT in Order Nos. 888 \67\ and 890 \68\ 
permits jurisdictional transmission providers to outline their rates 
for this regulation and frequency response service through a filing 
under FPA section 205. Schedule 3 charges are cost-based rates paid by 
transmission customers to the transmission provider. Additionally, 
Order No. 784 made it possible for third-party sellers to offer 
Schedule 3 service to the transmission provider at a rate up to the 
published Schedule 3 rate, or at rates that result from an appropriate 
competitive solicitation.\69\ Such third-party sales could involve any 
combination of regulation and primary frequency response services, 
including unbundled primary frequency response service by itself.
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    \66\ Regulation service is different than primary frequency 
response because regulation resources respond to automatic 
generation control signals, which responds to Area Control Error. 
Regulation is centrally coordinated by the balancing authority. 
Primary frequency response, in contrast, is autonomous and is not 
centrally coordinated. Schedule 3 lumps these different services 
together, despite their differences. The Commission in Order No. 888 
found that ``while the services provided by Regulation Service and 
Frequency Response Service are different, they are complementary 
services that are made available using the same equipment. For this 
reason, we believe that Frequency Response Service and Regulation 
Service should not be offered separately, but should be offered as 
part of one service.'' Order No. 888, FERC Stats. & Regs. ] 31,036, 
at PP 212-213 (1996).
    \67\ Order No. 888, FERC Stats. & Regs. ] 31,036.
    \68\ Order No. 890, FERC Stats. & Regs. ] 31,241.
    \69\ Third-Party Provision of Ancillary Services; Accounting and 
Financial Reporting for New Electric Storage Technologies, Order No. 
784, FERC Stats. & Regs. ] 31,349, at PP 6-7 (2013), order on 
clarification, Order No. 784-A, 146 FERC ] 61,114 (2014).
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    36. Finally, in Order No. 819, the Commission revised its 
regulations to foster competition in the sale of primary frequency 
response service.\70\ In the final rule, the Commission approved the 
sale of primary frequency response service at market-based rates by 
entities that qualify for market-based rate authority for sales of 
energy and capacity to any willing buyer. Order No. 819 focused on how 
jurisdictional entities can qualify for market-based rates for primary 
frequency response service in the context of voluntary bilateral sales, 
and did not place any limits on the types of transactions available to 
procure primary frequency response service; they may be cost-based or 
market-based, bundled with other services or unbundled, and inside or 
outside of organized markets.\71\ Order No. 819 did not require any 
entity to purchase primary frequency response from third parties or 
develop an organized market for primary frequency response.\72\
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    \70\ Third-Party Provision of Primary Frequency Response 
Service, Order No. 819, 153 FERC ] 61,220 (2015).
    \71\ Id. P 13.
    \72\ Id. P 37. The Commission denied Calpine Corporation's 
request for Regional Transmission Organizations (RTOs) and 
Independent System Operators (ISOs) to be given a deadline to 
develop tariff changes that would enable them to implement primary 
frequency response compensation mechanisms.
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II. Request for Comments

    37. The Commission seeks comment on the need for reforms to its 
rules and regulations regarding the provision and compensation of 
primary frequency response. Specifically, the Commission seeks comment 
on possible actions to ensure that the provision of primary frequency 
response continues to remain at levels adequate to maintain the 
reliability of the Bulk-Power System in light of the ongoing 
transformation of the nation's generation resource mix. The Commission 
understands that this transformation in the nation's generation 
portfolio could eventually result in a reduction of system inertia and 
fewer generation resources with primary frequency response 
capabilities. In addition, as discussed above, NERC has indicated that 
a significant number of generators within the Eastern Interconnection 
utilize dead bands or governor control settings that either inhibit or 
prevent the provision of primary frequency response. Together, these 
factors could result in potential downward shifts of the frequency 
nadir during disturbances, closer to UFLS set points that would trigger 
significant widespread outages.
    38. Presently, there are no pro forma agreements for primary 
frequency response transactions. Voluntary sales of primary frequency 
response, would most likely involve negotiated, bilateral contracts 
between buyers and sellers. In this regard, considering their 
compliance obligations under Reliability Standard BAL-003-1, balancing 
authorities will be the most likely source of demand for voluntary 
purchases of primary frequency response service from third-party 
sellers, including those who have not provided the service in the past. 
Accordingly, as discussed further below, the Commission seeks comment 
on whether and to what extent balancing authority demand for voluntary 
purchases of frequency response would be reduced if all or all newly 
interconnecting resources were required to provide frequency response 
service. Further, we also seek comment on the impact this would have on 
the Commission's efforts under Order No. 819 to foster the development 
of a bilateral market for market-based rate sales of primary frequency 
response service as a means of cost-effectively meeting such demand.
    39. Within RTO/ISO markets, no current stand-alone primary 
frequency response product exists. Any RTO/ISO that desires to 
explicitly procure and compensate primary frequency response would need 
new tariff provisions because no RTO/ISO currently defines or procures 
such a product. As discussed below, the Commission seeks comment on the 
need for and the nature of frequency response compensation within the 
context of current RTO/ISO market optimization processes.
    40. Accordingly, the Commission seeks comment on the following 
possible actions, discussed in more detail below: (1) Modifications to 
the pro forma LGIA and SGIA mandating primary frequency response 
requirements for new resources, among other changes; (2) new primary 
frequency response requirements for existing resources; and (3) the 
requirement to provide and compensate for primary frequency response.

A. Modifications to the pro forma LGIA and SGIA

    41. Reliability Standard BAL-003-1 and the pro forma LGIA and SGIA 
do not specifically address generators' provision of primary frequency 
response. Article 9.6.2.1 of the pro forma LGIA (Governors and 
Regulators) requires that if speed governors are installed, they should 
be operated in automatic mode.\73\ Reliability Standard BAL-003-1 and 
the pro forma LGIA and SGIA do not explicitly: (1) Require generators 
to install the necessary capability to provide primary frequency 
response; (2) prescribe specific governor settings that would support 
the provision of primary frequency response; \74\ or (3) establish 
generator primary frequency response performance requirements during 
disturbances (e.g., require the response to be sustained, and not 
prematurely withdrawn prior to the initiation of secondary frequency 
response actions to return system frequency back to its nominal value 
and back within a generator's dead band setting).\75\
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    \73\ Order No. 2003, FERC Stats. & Regs. ] 31,146, app. C 
(LGIA).
    \74\ Generator governors can be enabled or disabled which 
determines whether or not primary frequency response is provided at 
all by the generator. In addition, even if a governor is enabled, 
its control settings can limit the conditions under which the 
generator provides primary frequency response.
    \75\ Primary frequency response would not be expected to be 
provided if no capacity (or ``headroom'') is reserved on a unit.
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    42. The Commission's pro forma generator interconnection agreements 
and procedures were developed at a time when traditional generating 
resources with standard governor controls and large rotational inertia 
were the predominant sources of electricity generation. However, 
circumstances are evolving, with NERC and others predicting significant

[[Page 9189]]

retirements of conventional synchronous resources, all of which 
contribute to system inertia, and some of which provide primary 
frequency response. In addition, VERs are projected to comprise an 
increasing portion of the installed capacity in many regions of the 
country, but they do not typically provide inertial response or primary 
frequency response unless specifically configured to do so.
    43. Regarding VERs, the Commission understands that in previous 
years, many non-synchronous resources were not consistently designed 
with primary frequency response capabilities. However, NERC and others 
have stated that VER manufacturers have made significant advancements 
in recent years to develop the necessary controls that would enable 
VERs to provide frequency response.\76\ NERC recommends that the 
industry analyze how wind and solar photovoltaic resources can 
contribute to frequency response and to work toward interconnection 
requirements that ensure system operators will continue to maintain 
essential reliability services.\77\ Also relevant are PJM's recent 
additions of new interconnection requirements for VERs entering its 
queue after May 2015.\78\ PJM has stated that the necessary 
capabilities for non-synchronous resources to provide primary frequency 
response, among other services, are now ``baked in'' as enhancements to 
inverter capabilities.\79\
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    \76\ NERC Long Term Reliability Assessment at 27 (November 
2014), http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014LTRA_ERATTA.pdf.
    \77\ Id.
    \78\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58 
(2015).
    \79\ PJM Interconnection, L.L.C., Docket No. ER15-1193-000 
(March 6, 2015) Transmittal Letter at 11.
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    44. In light of the ongoing changes in the nation's resource mix as 
well as NERC's concerns regarding the primary frequency response 
performance of existing resources, the Commission seeks comment on 
whether and how to modify the pro forma LGIA and SGIA to require 
primary frequency response capability and performance of new generating 
resources.
    45. To that end, the Commission seeks comment on the following 
questions:
    1. Should the pro forma LGIA and SGIA be revised to include 
requirements for all newly interconnecting generating resources, 
including non-synchronous resources, to:
    1.1. Install the capability necessary to provide primary frequency 
response?
    1.2. Ensure that prime mover governors (or equivalent frequency 
control devices) are enabled and set pursuant to NERC's Primary 
Frequency Control Guideline (i.e., droop characteristics not to exceed 
5 percent, and dead band settings not to exceed 0.036 Hz)?
    1.3. Ensure that the MW response provided (when there is available 
headroom) in response to frequency deviations above or below the 
governor's dead band from 60 Hz is:
    1.3.1. Sustained until system frequency returns to within the 
governor's dead band setting?
    1.3.2. Provided without undue delay and responds in accordance with 
a specified droop parameter?
    2. What are the costs associated with making a newly 
interconnecting generation resource capable of providing primary 
frequency response? Specifically, what are the pieces of equipment or 
software needed to provide primary frequency response, and what are the 
costs associated with those pieces of equipment or software? Are there 
significant differences between synchronous and non-synchronous 
resources in providing primary frequency response, (e.g., the type of 
equipment necessary)?
    3. Regarding question (1) above, are the governor control settings 
recommended by NERC's Primary Frequency Control Guideline the 
appropriate settings to include in the pro forma LGIA and SGIA? Why or 
why not?
    4. Regarding new resources, including non-synchronous resources, 
are there physical, technical, or operational limitations/concerns to 
promptly providing sustained primary frequency response in the 
direction necessary to counteract under-frequency and over-frequency 
deviations? How should new requirements account for such limitations?
    5. Are metrics or monitoring useful to evaluate whether new 
resources:
    5.1. Operate with governors (or equivalent frequency control 
devices) enabled?
    5.2. Set governor control settings as described in question (1) 
above?
    5.3. Provide sustained MW response (when the unit has available 
headroom and system frequency deviates outside of the dead band) that 
is in the direction necessary to correct the frequency deviation and 
responsive in accordance with a specified droop parameter?
    6. How would transmission providers verify that new resources 
provide adequate primary frequency response performance?
    6.1. What information is necessary in order to facilitate 
performance verification?
    6.2. What changes, if any, to existing infrastructure (including, 
but not limited to telemetry and software tools) would be required in 
order to verify primary frequency response performance?
    6.3. What limitations based on resource type, if any, should be 
considered when evaluating primary frequency response performance?
    7. How would transmission providers ensure compliance with the new 
rules?
    7.1. Are penalties appropriate to ensure that new generating 
resources adhere to the new requirements described in question (1) 
above, and if so, how should such penalties be structured and 
implemented?
    7.2. Are penalties appropriate only if a resource receives 
compensation for adhering to the new requirements described in question 
(1) above?

B. New Primary Frequency Response Requirements for Existing Resources

    46. The Commission seeks comment on how it might address the issue 
of primary frequency response performance in existing generators. As 
discussed above, the Commission is considering amendments to the pro 
forma LGIA and SGIA that would apply prospectively and only to new 
generating resources and not the existing generating fleet. However, 
the Commission notes that NERC has also expressed concerns related to 
the primary frequency response performance of the existing generating 
fleet.
    47. For example, in 2010, NERC conducted a governor response survey 
to gain insight into governor settings from several turbine governors 
across the three U.S. Interconnections.\80\ Analysis revealed a wide 
disparity in the reported governor control settings. For example, NERC 
found that several generator owners or operators reported dead bands 
between 0.05 Hz and 0.3 Hz, which are wider than those prescribed by 
ERCOT'S BAL-001-TRE-01 Regional Standard or recommended by NERC's 2015 
Generator Governor Frequency Response Industry Advisory \81\ and 
Primary Frequency Control Guideline.\82\
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    \80\ Frequency Response Initiative Report at 87.
    \81\ NERC Generator Governor Frequency Response Industry 
Advisory.
    \82\ NERC Primary Frequency Control Guideline Final Draft.
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    48. In February 2015, NERC issued an Industry Advisory, which 
expressed its determination that a significant portion of generators 
within the Eastern Interconnection utilize governor dead bands or other 
control settings that

[[Page 9190]]

either inhibit or prevent the provision of primary frequency 
response.\83\
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    \83\ NERC Generator Governor Frequency Response Industry 
Advisory.
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    49. Furthermore, some generating units have controls that withdraw 
primary frequency response prior to the initiation of secondary 
frequency controls, which is a significant concern in the Eastern 
Interconnection and a somewhat smaller issue in the Western 
Interconnection. These controls are known as outer-loop controls to 
distinguish them from more direct, lower-level control of the generator 
operations. Primary frequency response withdrawal occurs when outer-
loop controls deliberately act to nullify a generator's governor 
response and return the unit to operate at a pre-disturbance scheduled 
MW output. This is especially problematic when it occurs prior to the 
activation of secondary response, and has the potential to degrade the 
overall response of the Interconnection and result in a frequency that 
declines below the original nadir. NERC has observed that early 
withdrawal of primary frequency response continues to occur within the 
Eastern Interconnection.\84\
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    \84\ NERC 2015 Frequency Response Annual Analysis Report at vi 
(September 2015), http://www.nerc.com/comm/OC/RS%20Landing%20Page%20DL/Related%20Files/2015_FRAA_Report_Final.pdf.
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    50. Furthermore, NERC's Resources Subcommittee has determined that 
the majority of gas turbines operate in some type of MW Set Point 
control mode.\85\ According to the NERC Resources Subcommittee, the 
Eastern Interconnection Initiative has uncovered that in order for gas 
turbines to respond in MW Set Point control mode, an additional 
frequency algorithm has to be installed.\86\ Moreover, NERC's Resources 
Subcommittee stated that ``the net result is that the gas turbine fleet 
that has been installed in the past 20+ years is not frequency 
responsive, [which] has to be corrected.'' \87\ NERC has also observed 
that in many conventional steam plants, dead band settings exceed the 
maximum 0.036 Hz dead band, and the resulting response is 
squelched and not sustained.\88\
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    \85\ See News from SERC's NERC Resources Subcommittee Rep--
Primary Frequency Response at 1 (May 2015), https://www.serc1.org/
docs/default-source/outreach/communications/resource-documents/serc-
transmission-reference/201505_-st/primary-frequency-
response.pdf?sfvrsn=2. MW set-point control mode automatically 
interrupts governor response in order for a generating unit to 
maintain a pre-disturbance dispatch.
    \86\ Id.
    \87\ Id.
    \88\ See NERC Generator Governor Frequency Response Advisory--
Webinar Questions and Answers at 1 (April 2015), http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_QandA_April_2015.pdf.
---------------------------------------------------------------------------

    51. As noted above, in December 2015, NERC's Operating Committee 
approved a 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 during major grid events in order to stabilize and maintain 
system frequency within allowable limits.\89\ However, the Commission 
notes that NERC's Primary Frequency Control Guideline is not mandatory 
and enforceable and does not alter any approved Reliability Standards.
---------------------------------------------------------------------------

    \89\ NERC Primary Frequency Control Guideline Final Draft.
---------------------------------------------------------------------------

    52. In light of the above discussion, the Commission seeks to 
further explore issues regarding the provision of primary frequency 
response by the existing generation fleet and seeks comment on the 
following questions:
    1. Should the Commission implement primary frequency response 
requirements for existing resources, as discussed above for new 
generators? If so, what is an appropriate means of doing so (e.g., 
changes to transmission provider tariffs or improvements to existing 
reliability standards)? How would transmission providers ensure that 
existing resources adhere to new primary frequency response 
requirements?
    2. As noted above, some existing generating units set dead bands 
wider than those recommended by NERC's Primary Frequency Control 
Guideline, and some units have control settings set in a manner that 
results in the premature withdrawal of primary frequency response. 
Should the Commission prohibit these practices? If so, by what means?
    3. What are the costs of retrofitting existing units, including 
non-synchronous resources, and with specific reference to such factors 
as equipment types and MW capacity, to be capable of providing 
sustained primary frequency response?
    4. Regarding existing units, are there physical, technical, or 
operational limitations or concerns to promptly providing sustained 
primary frequency response in the direction necessary to counteract 
under-frequency and over-frequency deviations?

C. Requirement to Provide and Compensate for Primary Frequency Response 
Service

    53. Without the explicit requirement to provide primary frequency 
response or appropriate compensation for the provision of such service, 
resource owners may choose to disable or otherwise reduce the provision 
of primary frequency response from their existing resources or not 
install the equipment on their new resources.\90\
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    \90\ IEEE, Interconnected Power System Response to Generation 
Governing: Present Practice and Outstanding Concerns (May 2007) 
(citing Cost of Providing Ancillary Services from Power Plants--
Volume 1: A Primer, EPRI TR-1 07270-V1, 4161, Final Report, March 
1997), http://resourcecenter.ieee-pes.org/pes/product/technical-reports/PESTR13.
---------------------------------------------------------------------------

    54. The Commission seeks information on whether there is a need to 
establish or modify procurement and compensation mechanisms for primary 
frequency response, and whether these mechanisms will ensure that the 
resulting rates are just and reasonable. The Commission invites 
commenters to share their overall views, including the operational, 
technical and commercial impacts that may result from mandates to 
provide primary frequency response. To that end, the Commission seeks 
comment on the following questions:
    1. Should all resources be required to provide minimum levels of: 
(1) Primary frequency response capability; and (2) primary frequency 
response performance in real-time?
    1.1. ``Capability'' involves having a turbine governor or 
equivalent equipment that has the ability to sense changes in system 
frequency, and is enabled and set with appropriate governor settings 
(e.g., droop and dead band), and assuming capacity (or ``headroom'') 
has been set aside, the physical ability to ramp the resource quickly 
enough in order to provide useful levels of primary frequency response 
to help arrest the frequency deviation.
    1.2. ``Performance'' would involve putting the ``capability'' into 
actual service: i.e., actually operating the resource with governors or 
equivalent equipment enabled, ensuring that governor controls (e.g., 
droop and dead band) and other settings are properly set and 
coordinated, such that when capacity (or ``headroom'') has been set 
aside, the unit promptly provides sustained primary frequency response 
during frequency excursions, until system frequency returns to within 
the governor's dead band setting.
    2. Is it necessary for every generating resource to install the 
capability necessary to provide primary frequency

[[Page 9191]]

response? Or is it more appropriate for balancing authorities to 
identify and procure the amount of primary frequency response service 
that they need to meet their obligations under Reliability Standard 
BAL-003-1 and the optimum mix of resources to meet that need?
    2.1. To the extent that balancing authorities are responsible for 
procuring adequate primary frequency response service, does the current 
framework for blackstart provide a useful guide for how primary 
frequency response service could be procured?
    2.2. Does the Commission's recent rulemaking allowing third-party 
sales of frequency response services at market based rates allow 
balancing authorities to procure sufficient amounts of primary 
frequency response as required by BAL-003-1?
    2.3. To the extent that balancing authorities centrally optimize 
primary frequency response, wherein an algorithm optimizes in the 
operating horizon the set of resources in which to allocate primary 
frequency response headroom: Should all newly interconnecting resources 
be required to install the necessary capability in these areas? Can 
balancing authorities predict far ahead of the operating horizon the 
least-cost set of resources from which it will optimize the provision 
of primary frequency response?
    2.4. Would the costs of requiring all resources to have the 
capability to provide primary frequency response be significantly 
greater than the costs that would result from an Interconnection-wide 
or balancing authority-wide optimization of which generators should be 
capable of providing primary frequency response?
    2.5. Would the costs of requiring all new resources to enable and 
set their governors, or equivalent equipment, to be able to provide 
primary frequency response in real-time be significantly greater than 
the costs that would result from an Interconnection-wide or balancing 
authority-wide optimization of which generators should provide primary 
frequency response in real-time?
    2.6. Please discuss the viability of implementing an 
Interconnection-wide optimization mechanism.
    2.7. Would requiring every resource to be capable of providing 
primary frequency response result in over-procurement or inefficient 
investment in primary frequency response capability to the detriment of 
customers?
    2.8. Without rules to compel performance, how would balancing 
authorities ensure that the optimal set of resources chosen by an 
optimization algorithm actually enable governor controls with 
appropriate governor settings so that they provide sustained primary 
frequency response when capacity (or ``headroom'') has been reserved 
and frequency deviates outside of their dead band settings?
    3. If generation resources were required to have minimum levels of 
primary frequency response capability or performance, should such 
resources be compensated for providing primary frequency response 
capability, performance, or both? If so, why? If not, why?
    3.1. If payment is based on capacity (or ``headroom'') that is set 
aside for primary frequency response, how should such a capacity 
payment be structured and determined?
    3.2. If payment is based on actual performance, either alone or in 
combination with a capacity-based payment, please discuss possible rate 
structures applicable to primary frequency response performance.
    3.3. Will a market price provide resources with sufficient 
incentive to invest in primary frequency response capability and make 
the service available to the balancing authority in real-time, absent a 
requirement that resources maintain the capability to provide primary 
frequency response and perform as required?
    4. Currently, how do RTOs/ISOs ensure that they have the 
appropriate amount of primary frequency response capability during 
operations?
    4.1. Are resources contracted for primary frequency response 
outside of the market optimization and dispatch?
    4.2. Alternatively, does the market optimization and dispatch 
incorporate primary frequency response in its optimization?
    5. Would it be appropriate for RTOs/ISOs to create a product for 
primary frequency response service?
    5.1. Should this product be similar to a capacity product for the 
procurement of primary frequency response capability from resources?
    5.2. Should this product be similar to other ancillary service 
products in which certain resources would be selected in the day-ahead 
or real-time markets to provide primary frequency response?
    5.3. Are there benefits to co-optimizing the capacity (or 
``headroom'') allocated on generating units for primary frequency 
response with the market optimization and dispatch of RTOs/ISOs? If so, 
what are the challenges associated with doing so?
    6. Are there benefits to separating Frequency Response Service 
under Schedule 3 and creating a separate ancillary service covering 
each individually? If so, how should a new pro forma Primary Frequency 
Response Ancillary Service be structured?
    7. When compensating for primary frequency response, should 
compensation be different inside and outside of RTOs/ISOs?
    8. What procurement requirements or compensation mechanisms could 
be used for primary frequency response from stored energy resources? 
When considering requirements or compensation for stored energy 
resources, how should possible additional costs or other concerns be 
addressed?

III. Comment Procedures

    55. The Commission invites interested persons to submit comments, 
and other information on the matters, issues and specific questions 
identified in this notice. Comments are due April 25, 2016. 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.
    56. 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.
    57. 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.
    58. 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.

IV. Document Availability

    59. 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 FERC's Home Page (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5:00 
p.m. Eastern

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time) at 888 First Street NE., Room 2A, Washington, DC 20426.
    60. From FERC'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.
    61. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC 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: February 18, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2016-03837 Filed 2-23-16; 8:45 am]
BILLING CODE 6717-01-P