Disturbance Control Standard-Contingency Reserve for Recovery From a Balancing Contingency Event Reliability Standard, 8994-9004 [2017-02175]

Download as PDF 8994 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (202) 502–6593, Raymond.OroccoJohn@ferc.gov. Julie Greenisen (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (202) 502–6362, julie.greenisen@ferc.gov. SUPPLEMENTARY INFORMATION: On June 16, 2016, the Commission issued a final rule amending its regulations to require NERC to provide the Commission, and Commission staff, with access to certain databases compiled and maintained by NERC.1 The compliance date for the new regulation was deferred based on issuance of the final rule in a related rulemaking, Commission Docket No. RM16–15–000. The final rule in the related proceeding has now been issued and was published in the Federal Register on December 21, 2016, to become effective February 21, 2017. This document provides notice of the corresponding date for compliance with the regulations adopted in Docket No. RM15–25–000. Kimberly D. Bose, Secretary. [FR Doc. 2017–02228 Filed 2–1–17; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission return their Area Control Error to defined values following a Reportable Balancing Contingency Event. In addition, the Commission directs NERC to develop modifications to Reliability Standard BAL–002–2 to address concerns regarding extensions of the 15minute period for Area Control Error recovery and contingency reserve restoration. The Commission also directs NERC to collect and report on data regarding additional megawatt losses following Reportable Balancing Contingency Events during the Contingency Reserve Restoration Period and to study and report on the reliability risks associated with megawatt losses above the most severe single contingency that do not cause energy emergencies. DATES: This rule is effective April 3, 2017. FOR FURTHER INFORMATION CONTACT: Enakpodia Agbedia (Technical Information), Office of Electric Reliability, Division of Reliability Standards, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (202) 502–6750, Enakpodia.Agbedia@ ferc.gov. Mark Bennett (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (202) 502–8524, Mark.Bennett@ferc.gov. SUPPLEMENTARY INFORMATION: ORDER NO. 835 18 CFR Part 40 FINAL RULE [Docket No. RM16–7–000; Order No. 835] (Issued January 19, 2017) Disturbance Control Standard— Contingency Reserve for Recovery From a Balancing Contingency Event Reliability Standard Federal Energy Regulatory Commission, Department of Energy. ACTION: Final rule. AGENCY: The Commission approves Reliability Standard BAL–002–2 (Disturbance Control Standard— Contingency Reserve for Recovery from a Balancing Contingency Event) submitted by the North American Electric Reliability Corporation (NERC). Reliability Standard BAL–002–2 is designed to ensure that balancing authorities and reserve sharing groups balance resources and demand and mstockstill on DSK3G9T082PROD with RULES SUMMARY: 1 Availability of Certain North American Electric Reliability Corporation Databases to the Commission, Order No. 824, 155 FERC ¶ 61,275 (2016). VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 1. Pursuant to section 215 of the Federal Power Act (FPA),1 the Commission approves Reliability Standard BAL–002–2 (Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing Contingency Event). The North American Electric Reliability Corporation (NERC), the Commissioncertified Electric Reliability Organization (ERO), developed and submitted Reliability Standard BAL– 002–2 for Commission approval. Reliability Standard BAL–002–2 is intended to ensure that balancing authorities and reserve sharing groups are able to recover from system contingencies by deploying adequate reserves to return their Area Control Error (ACE) to defined values and by replacing the capacity and energy lost due to generation or transmission 1 16 PO 00000 U.S.C. 824(o). Frm 00010 Fmt 4700 Sfmt 4700 equipment outages.2 In addition, the Commission approves eight new and revised definitions proposed by NERC for inclusion in the NERC Glossary and the retirement of currently-effective Reliability Standard BAL–002–1 immediately prior to the effective date of Reliability Standard BAL–002–2. The Commission also approves, with one modification, Reliability Standard BAL– 002–2’s associated violation risk factors and violation severity levels, and implementation plan. 2. Pursuant to section 215(d)(5) of the FPA,3 the Commission directs NERC to develop modifications to Reliability Standard BAL–002–2, Requirement R1 to address concerns related to the potential reliability impact of repeated extensions of the period for ACE recovery. To address the concerns, the Notice of Proposed Rulemaking (NOPR) proposed directing that NERC modify the Reliability Standard to require reliability coordinator approval of extensions of the ACE recovery period. Numerous commenters opposed the proposal, arguing that the proposal has the potential to complicate an already challenging situation. Thus, to address the underlying concern while cognizant of the NOPR comments, the final rule adopts a different approach of directing NERC to develop modifications to Reliability Standard BAL–002–2 that would require an entity to provide certain information to the reliability coordinator when the entity does not timely recover ACE due to an intervening disturbance. As discussed below, the Commission also directs NERC: (1) To collect and report on data related to resets of the contingency reserve restoration period; and (2) to study and report on the reliability risks associated with megawatt losses above an applicable entity’s most severe single contingency (MSSC) that do not cause energy emergencies. I. Background 3. Section 215 of the FPA requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards that are subject to Commission review and approval. The Commission may approve, by rule or order, a proposed Reliability Standard or modification to a Reliability Standard 2 ACE is the instantaneous difference between a balancing authority’s Net Actual and Scheduled Interchange, taking into account the effects of Frequency Bias, correction for meter error, and Automatic Time Error Correction (ATEC), if operating in ATEC mode. ATEC is only applicable to balancing authorities in the Western Interconnection. NERC Glossary of Terms Used in NERC Reliability Standards (NERC Glossary) at 7 (updated September 29, 2016). 3 16 U.S.C. 824o(d)(5). E:\FR\FM\02FER1.SGM 02FER1 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations if it determines that the Reliability Standard is just, reasonable, not unduly discriminatory or preferential and in the public interest.4 Once approved, the Reliability Standards may be enforced by NERC, subject to Commission oversight, or by the Commission independently.5 Pursuant to section 215 of the FPA, the Commission established a process to select and certify an ERO,6 and subsequently certified NERC.7 4. On March 16, 2007, the Commission issued Order No. 693, approving 83 of the 107 Reliability Standards filed by NERC, including Reliability Standard BAL–002–0.8 In addition, pursuant to section 215(d)(5) of the FPA, the Commission directed the ERO to develop modifications to Reliability Standard BAL–002–0: (1) To include a requirement that explicitly provides that demand side management may be used as a resource for contingency reserves; (2) to develop a continent-wide contingency reserve policy; and (3) to refer to the ERO rather than the NERC Operating Committee in Requirements R4.2 and R6.2.9 On January 10, 2011, the Commission approved Reliability Standard BAL– 002–1, which addressed the third directive described above.10 II. NERC Petition and Reliability Standard BAL–002–2 5. On January 29, 2016, NERC filed a petition seeking approval of Reliability Standard BAL–002–2; 11 eight new or revised definitions to be added to the NERC Glossary; and Reliability Standard BAL–002–2’s associated violation risk factors and violation severity levels, effective date, and implementation plan.12 NERC stated mstockstill on DSK3G9T082PROD with RULES 4 Id. 824o(d)(2). 5 Id. 824o(e). 6 Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh’g, Order No. 672–A, FERC Stats. & Regs. ¶ 31,212 (2006). 7 North American Electric Reliability Corp., 116 FERC ¶ 61,062, order on reh’g and compliance, 117 FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009). 8 Mandatory Reliability Standards for the BulkPower System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693–A, 120 FERC ¶ 61,053 (2007). 9 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 356. 10 North American Electric Reliability Corp., 134 FERC ¶ 61,015 (2011). 11 Reliability Standard BAL–002–2 is available on the Commission’s eLibrary document retrieval system in Docket No. RM16–7–000 and on the NERC Web site, www.nerc.com. 12 The eight proposed new and revised definitions for inclusion in the NERC Glossary are for the following terms: Balancing Contingency Event, Most Severe Single Contingency, Reportable VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 that Reliability Standard BAL–002–2 is just, reasonable, not unduly discriminatory or preferential, and in the public interest because it satisfies the factors set forth in Order No. 672, which the Commission applies when reviewing a proposed Reliability Standard.13 NERC also asserted that Reliability Standard BAL–002–2 addresses the outstanding directives from Order No. 693 regarding the use of demand side management as a resource for contingency reserve and the development of a continent-wide contingency reserve policy. 6. Reliability Standard BAL–002–2 consolidates six requirements in currently-effective Reliability Standard BAL–002–1 into three requirements and is applicable to balancing authorities and reserve sharing groups. NERC stated that Reliability Standard BAL–002–2 improves upon existing Reliability Standard BAL–002–1 because ‘‘it clarifies obligations associated with achieving the objective of BAL–002 by streamlining and organizing the responsibilities required therein, enhancing the obligation to maintain reserves, and further defining events that predicate action under the standard.’’ 14 NERC also stated that Reliability Standard BAL–002–2 ‘‘address[es] and supersede[s]’’ the proposed interpretation previously submitted by NERC (i.e., of Reliability Standard BAL–002–1a) and pending in Docket No. RM13–6–000.15 7. Requirement R1 of BAL–002–2 requires a balancing authority or reserve sharing group experiencing a Reportable Balancing Contingency Event to deploy its contingency reserves to recover its ACE to certain prescribed values within the Contingency Event Recovery Period Balancing Contingency Event, Contingency Event Recovery Period, Contingency Reserve Restoration Period, Pre-Reporting Contingency Event ACE Value, Reserve Sharing Group Reporting ACE, and Contingency Reserve. NERC Petition at 28–34. 13 NERC Petition at 13 and Ex. F (Order No. 672 Criteria). 14 Id. at 13. 15 Id. at 1. On February 12, 2013, NERC filed a proposed interpretation of Reliability Standard BAL–002–1 that construed the Reliability Standard so that the 15-minute ACE recovery period would not apply to events of a magnitude exceeding an entity’s most severe single contingency. In a NOPR issued on May 16, 2013, the Commission proposed to remand the proposed interpretation on procedural grounds. Electric Reliability Organization Interpretation of Specific Requirements of the Disturbance Control Performance Standard, 143 FERC ¶ 61,138 (2013). The rulemaking on the proposed interpretation is pending. In the petition in the immediate proceeding, NERC states that, upon approval of Reliability Standard BAL–002–2, NERC will file a notice of withdrawal of the proposed interpretation. NERC Petition at 1. PO 00000 Frm 00011 Fmt 4700 Sfmt 4700 8995 of 15 minutes.16 However, under certain circumstances, Reliability Standard BAL–002–2 relieves responsible entities from strict compliance with the existing time periods for ACE recovery and contingency reserve restoration ‘‘to ensure responsible entities retain flexibility to maintain service to Demand, while managing reliability, and to avoid duplication with other Reliability Standards.’’ 17 8. Specifically, Requirement R1, Part 1.3.1 provides that a balancing authority or reserve sharing group is not subject to Requirement R1, Part 1.1 if it: (1) Is experiencing a Reliability Coordinator declared Energy Emergency Alert Level; (2) is utilizing its contingency reserve to mitigate an operating emergency in accordance with its emergency Operating Plan, and (3) has depleted its contingency reserve to a level below its most severe single contingency. 9. In addition, under Requirement R1, Part 1.3.2, a balancing authority or reserve sharing group is not subject to Requirement R1, Part 1.1 if the balancing authority or reserve sharing group experiences: (1) Multiple Contingencies where the combined megawatt (MW) loss exceeds its most severe single contingency and that are defined as a single Balancing Contingency Event or (2) multiple Balancing Contingency Events within the sum of the time periods defined by the Contingency Event Recovery Period and Contingency Reserve Restoration Period whose combined magnitude exceeds the Responsible Entity’s most severe single contingency. 10. Requirement R2 provides that each responsible entity: shall develop, review and maintain annually, and implement an Operating Process as part of its Operating Plan to determine its Most Severe Single Contingency and to make preparations to have Contingency Reserve equal to, or greater than the Responsible Entity’s Most Severe Single Contingency available for maintaining system reliability. 16 NERC proposes to define Reportable Balancing Contingency Event as: ‘‘Any Balancing Contingency Event occurring within a one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results in a loss of MW output less than or equal to the Most Severe Single Contingency, and greater than or equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount listed below for the applicable Interconnection. Prior to any given calendar quarter, the 80% threshold may be reduced by the responsible entity upon written notification to the Regional Entity.’’ NERC Petition at 30. Contingency Event Recovery Period, as proposed by NERC, means: ‘‘A period that begins at the time that the resource output begins to decline within the first one-minute interval of a Reportable Balancing Contingency Event, and extends for fifteen minutes thereafter.’’ Id. at 32. 17 Id. at 4. E:\FR\FM\02FER1.SGM 02FER1 8996 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations mstockstill on DSK3G9T082PROD with RULES NERC explained that Requirement R2 requires responsible entities to demonstrate that their process for calculating their most severe single contingency ‘‘surveys all contingencies, including single points of failure, to identify the event that would cause the greatest loss of resource output used by the [reserve sharing group or balancing authority] to meet Firm Demand.’’ 18 NERC further stated that Requirement R2 supports Requirements R1 and R3 in Reliability Standard BAL–002–2 ‘‘as these requirements rely on proper calculation of [most severe single contingency].’’ 19 11. Requirement R3 provides that ‘‘each Responsible Entity, following a Reportable Balancing Contingency Event, shall restore its Contingency Reserve to at least its Most Severe Single Contingency, before the end of the Contingency Reserve Restoration Period [90 minutes], but any Balancing Contingency Event that occurs before the end of a Contingency Reserve Restoration Period resets the beginning of the Contingency Event Recovery Period.’’ 12. NERC explained that the revised language in the consolidated requirements in Reliability Standard BAL–002–2 will improve efficiency and clarity by removing ‘‘unnecessary entities from compliance to capture only those entities that are vital for reliability.’’ 20 NERC stated that the new definitions for Balancing Contingency Event and Reportable Balancing Contingency Event more clearly identify the types of events that cause frequency deviations necessitating action under Reliability Standard BAL–002–2 and provide additional detail regarding the types of resources that may be identified as contingency reserves. Furthermore, NERC stated that Reliability Standard BAL–002–2 ‘‘ensures objectivity of the reserve measurement process by guaranteeing a Commission-sanctioned continent-wide reserve policy,’’ and therefore satisfies an outstanding Order No. 693 directive for uniform elements, definitions and requirements for a continent-wide contingency reserve policy.21 Finally, NERC asserted that the revised definition of Contingency Reserves ‘‘improves the existing definition by addressing a Commission directive in Order No. 693 to allow demand side management to be used as at 25. NERC provides examples of how responsible entities may calculate the most severe single contingency in the petition. See NERC Petition, Ex. B (Calculating Most Severe Single Contingency). 20 NERC Petition at 14. 21 Id. a resource for contingency reserve when necessary.’’ 22 13. NERC submitted proposed violation risk factors and violation severity levels for each requirement of Reliability Standard BAL–002–2 and an implementation plan and effective dates. NERC stated that these proposals were developed and reviewed for consistency with NERC and Commission guidelines. NERC proposed an effective date for Reliability Standard BAL–002–2 that is the first day of the first calendar quarter that is six months after the date of Commission approval. NERC explained that this implementation date will allow entities to make necessary modifications to existing software programs to ensure compliance.23 14. On February 12, 2016, NERC submitted a supplemental filing to clarify a statement in the petition that Reliability Standard BAL–002–2 would operate in conjunction with Reliability Standard TOP–007–0 to control system frequency by addressing transmission line loading in the event of a transmission overload. NERC explained that, while Reliability Standard TOP– 007–0 will be retired on April 1, 2017, ‘‘the obligations related to [transmission line loading] under TOP–007–0 will be covered by Commission-approved TOP– 001–3, EOP–003–2, IRO–009–2, and IRO–008–2 . . . by requiring relevant functional entities to communicate [Interconnection Reliability Operating Limits (IROL)] and [System Operating Limits (SOL)] exceedances so that the [reliability coordinator] can direct appropriate corrective action to mitigate or prevent those events.’’ 24 15. On March 31, 2016, NERC submitted a second supplemental filing to ‘‘further clarify the extent to which BAL–002–2 interacts with other Commission-approved Reliability Standards to promote Bulk Power System reliability . . . [and support] the overarching policy objective reflected in the stated purpose of Reliability Standard BAL–002–2.’’ 25 In its filing, NERC expanded upon the explanation in the petition regarding how an ‘‘integrated’’ and ‘‘coordinated suite of Reliability Standards’’ (BAL–001–2, BAL–003–1, TOP–007–0, EOP–002–3, EOP–011–1, IRO–008–2, and IRO–009– 2) will apply to events causing MW losses above a responsible entity’s most severe single contingency, and how 18 Id. 22 Id. 19 Id. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 at 33. Petition, Ex. D (Implementation Plan) at 23 NERC 3. those other Reliability Standards are better designed to manage the greater risks created by such events.26 III. Notice of Proposed Rulemaking 16. On May 19, 2016, the Commission issued a NOPR proposing to approve Reliability Standard BAL–002–2 as just, reasonable, not unduly discriminatory or preferential and in the public interest.27 The Commission also proposed to approve NERC’s eight proposed new and revised definitions and the retirement of currently-effective Reliability Standard BAL–002–1. Further, the Commission proposed to direct NERC to change the proposed violation risk factor from ‘‘medium’’ to ‘‘high’’ for Reliability Standard BAL– 002–2, Requirements R1 and R2. 17. In the NOPR, the Commission recognized that it is essential for grid reliability that responsible entities balance resources and demand and restore system frequency to recover from a system event, and that they maintain reserves necessary to replace capacity and energy lost due to generation or transmission outages. The Commission also stated that Reliability Standard BAL–002–2 improves upon currentlyeffective Reliability Standard BAL–002– 1 by consolidating requirements to streamline and clarify the obligations related to achieving these goals. However, the Commission raised concerns regarding possible extensions of the 15-minute ACE recovery period and the 90-minute Contingency Reserve Restoration Period, as well as NERC’s proposal to limit the scope of Reliability Standard BAL–002–2 to a responsible entity’s most severe single contingency. 18. In the NOPR, the Commission sought comment on the following issues: (1) Reliability coordinator authorization of extensions of the 15minute ACE recovery period; (2) resets or credits during the 90-minute Contingency Reserve Restoration Period; (3) the exclusion of megawatt losses above the most severe single contingency in the proposed definition of Reportable Balancing Contingency Event; and (4) NERC’s proposal to reduce from ‘‘high’’ to ‘‘medium’’ the violation risk factor for proposed Requirements R1 and R2. The Commission also sought comment on whether NERC’s proposed definition of contingency reserve should include the NERC-defined term Demand-side Management. 26 Id. at 2–5. 27 Disturbance 24 NERC February 12, 2016 Supplemental Filing at 2–3. 25 NERC March 31, 2016 Supplemental Filing at 1, 5. PO 00000 Frm 00012 Fmt 4700 Sfmt 4700 Control Standard—Contingency Reserve for Recovery from a Balancing Contingency Event Reliability Standard, Notice of Proposed Rulemaking, 81 FR 33,441 (May 26, 2016), 155 FERC ¶ 61,180 (2016) (NOPR). E:\FR\FM\02FER1.SGM 02FER1 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations 19. In response to the NOPR, the Commission received 11 sets of comments. We address below the issues raised in the NOPR and comments. The Appendix to this final rule lists the entities that filed comments in response to the NOPR. IV. Discussion 20. Pursuant to FPA section 215(d)(2), we approve Reliability Standard BAL– 002–2 as just, reasonable, not unduly discriminatory or preferential, and in the public interest. We also approve NERC’s eight new and revised proposed definitions and, with one exception, the proposed violation risk factor and violation severity level assignments. In addition, we approve NERC’s implementation plan establishing an effective date of the first day of the first calendar quarter, six months after the date of Commission approval, and the retirement of currently-effective BAL– 002–1 immediately before that date.28 21. The purpose of Reliability Standard BAL–002–2 is to ensure that balancing authorities and reserve sharing groups balance resources and demand and return their ACE to defined values following a Reportable Balancing Contingency Event. We determine that Reliability Standard BAL–002–2 improves upon currently-effective Reliability Standard BAL–002–1 by consolidating the number of requirements to streamline and clarify the obligations for responsible entities to deploy contingency reserves to stabilize system frequency in response to system contingencies. 22. We conclude that BAL–002–2 satisfies the Order No. 693 directive that NERC develop a continent-wide contingency reserve policy.29 Also, we accept NERC’s explanation in response to the NOPR that demand side resources that are technically capable can be included as contingency reserves, and therefore determine that Reliability Standard BAL–002–2 satisfies the Order No. 693 directive that demand side management may be used as a resource for contingency reserves.30 23. In addition, pursuant to section 215(d)(5) of the FPA, we direct NERC to develop modifications to Reliability 28 NERC Petition, Ex. D (Implementation Plan) at mstockstill on DSK3G9T082PROD with RULES 3. 29 Order No. 693, FERC Stats. & Regs ¶ 31,242 at PP 340, 341 and 356. 30 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 330, 335 and 356. In its comments NERC explained that ‘‘[t]he proposed definition balances the need for flexibility to include a variety of demand side resources in measurements of Contingency Reserve with the need to define the types of demand side resources that are ‘technically capable’ to serve as contingency reserve.’’ NERC Comments at 30. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 Standard BAL–002–2 to address our concerns, discussed below, regarding the 15-minute ACE recovery period set forth in Requirement R1. We also direct NERC to collect and report on data pertaining to the occurrence of Balancing Contingency Events that trigger resets of the 90-minute Contingency Reserve Restoration Period under Requirement R3. We further direct NERC to study and submit a report to the Commission with findings regarding reliability risks associated with most severe single contingency exceedances that do not result in energy emergencies. 24. We discuss below the following issues raised in the NOPR and addressed in the comments: (A) Whether a reliability coordinator must expressly authorize extensions of the 15-minute ACE recovery period; (B) whether BAL–002–2 should be modified to require all contingency reserves to be restored within the 90-minute Contingency Reserve Restoration Period; (C) whether a reasonable obligation should be imposed for balancing authorities and reserve sharing groups to address scenarios involving megawatt losses above the most severe single contingency that do not cause energy emergencies; and (D) NERC’s proposal to reduce from ‘‘high’’ to ‘‘medium’’ the violation risk factor for Requirements R1 and R2. A. The 15-Minute ACE Recovery Period NERC Petition 25. In its petition, NERC stated that the ‘‘exemption’’ from the 15-minute ACE recovery period in Requirement R1, Part 1.3.1 ‘‘eliminates the existing conflict with EOP–011–1, as it removes undefined auditor discretion when assessing compliance and allows the responsible entity flexibility to maintain service to load while managing reliability.’’ 31 NERC explained that this exemption does not eliminate an entity’s obligation to respond to a Reportable Balancing Contingency Event, but rather it will ‘‘simply allow more time to return the Reporting ACE to the defined limits than would otherwise be allowed.’’ 32 NOPR 26. In the NOPR, the Commission noted that Reliability Standard BAL– 002–2, Requirement R1 obligates a responsible entity that experiences a Reportable Balancing Contingency Event to return its Reporting ACE to predefined values within the 15-minute Contingency Event Recovery Period. PO 00000 Petition at 22. at 24. Further, the Reliability Standard does not expressly provide a definitive and enforceable deadline for ACE recovery during a reliability coordinator-declared Energy Emergency Alert accompanied by the depletion of the entity’s contingency reserves to below its most severe single contingency. 27. The Commission stated that NERC’s explanation for relief from the 15-minute ACE recovery period in Reliability Standard BAL–002–2 raises concerns, because it is unclear how or when an entity will prepare for a second contingency during the indeterminate extension of the 15-minute ACE recovery period that Requirement R1, Part 1.3 permits. The Commission observed that a balancing authority that is operating out-of-balance for an extended period of time is ‘‘leaning on the system’’ by relying on external resources to meet its obligations. That could affect other entities within an Interconnection, particularly if another entity is reacting to a grid event while unaware that the first entity has not restored its ACE.33 While an extension of the 15-minute ACE recovery period may be appropriate under certain emergency conditions, the NOPR explained that, with a wide-area view and superior information and objectivity, the reliability coordinator is in a better position to decide whether to extend the ACE recovery period after an entity has met the criteria described in Requirement R1, Part 1.3.1. 28. Further, while Reliability Standard EOP–011–1, Requirement R3, requires the reliability coordinator to review balancing authority Operating Plans and notify a balancing authority of any ‘‘reliability risks’’ the reliability coordinator may identify with a time frame for the resubmittal of revised Operating Plans, the NOPR explained that the Reliability Standard does not require reliability coordinator approval of Operating Plans. 29. Therefore, the NOPR proposed to direct NERC to develop modifications to Reliability Standard BAL–002–2 that would require Reporting ACE recovery within the 15-minute Contingency Event Recovery Period unless the relevant reliability coordinator expressly authorizes an extension of the 15-minute ACE recovery period after the balancing authority has met the criteria described in Requirement R1, Part 1.3.1. The Commission’s proposal included modifying Reliability Standard BAL– 002–2 to identify the reliability coordinator as an Applicable Entity. 31 NERC 32 Id. Frm 00013 Fmt 4700 33 NOPR, Sfmt 4700 8997 E:\FR\FM\02FER1.SGM 155 FERC ¶ 61,180 at P 22. 02FER1 8998 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations Comments 30. NERC, EEI, NRECA, TVA, CEA, Joint Commenters, IESO and APS oppose the proposed directive. NERC asserts that the proposed directive is unnecessary because the Balancing Authority ACE Limit (BAAL) and a balancing authority’s resource obligations under Reliability Standard BAL–001–2 discourage balancing authorities from leaning on the system during extensions of the Contingency Event Recovery Period. NERC explains that the BAAL: is a unique limit on a [balancing authority’s] Reporting ACE based on Real-time interconnection frequency levels . . . since the loss of a resource would influence the Interconnection’s frequency, the BAAL would adjust (or ‘tighten’) to assure that the Interconnection frequency remains in a safe range. The [balancing authority] must return its operations to within the ‘tightened’ BAAL within 30 minutes and thus would not be able to ‘lean’ on the Interconnection for any prolonged period.34 mstockstill on DSK3G9T082PROD with RULES 31. Further, NERC contends that the proposed role for reliability coordinators is unnecessary—in both emergency and non-emergency situations—because the reliability coordinator ‘‘must maintain constant oversight of reliability within its [reliability coordinator] area and direct other responsible entities to take actions necessary to maintain reliability.’’ 35 32. EEI and Joint Commenters assert that the NOPR proposal ‘‘would result in unnecessary duplication of requirements adding no tangible benefit to reliability while needlessly increasing the compliance burden.’’ 36 Joint Commenters also note the infrequent nature of multiple-contingency events and Energy Emergency Alerts (EEAs), describing them as ‘‘exceptional circumstances appropriate for an exemption from the typical measured requirements.’’ 37 Joint Commenters state that in 2015 there were ten EEA Level 2 and Level 3 events, and that ‘‘most [balancing authorities] experience no EEA events in a given year . . . allowing recovery exceptions during these exceptional circumstances would not create significant risk with respect to ACE recovery responsibilities.’’ 38 Joint Commenters also contend that in a ‘‘multiple-contingency event or during an EEA, there are likely scores of 34 NERC Comments at 10. at 11 (citing Reliability Standards EOP– 0011–1, EOP–003–2, IRO–001–4, IRO–002–4, IRO– 008–2, and IRO–009–2). 36 EEI Comments at 7; see also Joint Commenters Comments at 2–4. 37 Joint Commenters Comments at 4. 38 Id. (citing NERC’s 2016 State of Reliability Report at 38). 35 Id. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 activities occupying the [reliability coordinator’s] attention. Requiring the [balancing authority] and [reliability coordinator] to conduct a conference call during an EEA to discuss the merits of requests for additional ACE recovery time only complicates these alreadychallenging conditions.’’ 39 33. While supporting the notification and involvement of reliability coordinators, APS shares Joint Commenters’ concern that requiring reliability coordinators to expressly authorize extensions of the 15-minute ACE recovery period could distract responsible entities from focusing on ‘‘maintaining and recovering the reliability of the [bulk electric system].’’ 40 Therefore, as an alternative to the NOPR proposal, APS proposes that balancing authorities obtain extensions of the 15-minute ACE recovery period under the extenuating circumstances described in Requirement R1, Part 1.3.1 by notifying the reliability coordinator of the conditions within its area and providing the reliability coordinator with an ACE recovery plan and target time period, but without obtaining express approval from the reliability coordinator.41 34. Idaho Power and BPA support the Commission’s proposal to expressly require reliability coordinator authorization for extensions of the 15minute Reporting ACE recovery period. Idaho power agrees with ‘‘shifting more oversight to the Reliability Coordinator’’ as the entity with the system-wide view.42 Commission Determination 35. We are persuaded by the commenters not to adopt the NOPR proposal that would require reliability coordinator authorization to extend the 15-minute ACE recovery period. As commenters explain, seeking the proposed reliability coordinator authorization while recovering from a disturbance has the potential to complicate an already-challenging situation. However, we continue to see a need to address the underlying concern expressed in the NOPR that a balancing authority that is operating out-of-balance for an extended period of time is ‘‘leaning on the system’’ by relying on external resources to meet its obligations. That scenario could affect other entities within an Interconnection, particularly if another entity is reacting to a grid event while unaware that the 39 Id. at 3. Comments at 4–5. 41 Id. at 5. 42 Idaho Power Comments at 2; see also BPA Comments at 3. 40 APS PO 00000 Frm 00014 Fmt 4700 Sfmt 4700 first entity has not restored its ACE. Accordingly, to address our concern without requiring reliability coordinator authorization, we adopt APS’s proposed alternative that would require a balancing authority or reserve sharing group experiencing a depletion of contingency reserves below its most severe single contingency level during an Energy Emergency Alert to obtain an extension of the 15-minute ACE recovery period by informing the reliability coordinator of the circumstances and providing it with an ACE recovery plan and target time period. 36. We are persuaded that APS’s approach is reasonable and adequately addresses concerns with extensions of the 15-minute ACE recovery period. By requiring notification of reliability coordinators and providing the reliability coordinator with an ACE recovery plan and target time period, we agree that the APS proposal ‘‘would allow appropriate flexibility to [balancing authorities] when extenuating circumstances are present while providing [reliability coordinators] with the necessary data, communication, and coordination to fulfill their oversight responsibilities to the Interconnection.’’ 43 37. Accordingly, we direct NERC to develop modifications to Reliability Standard BAL–002–2, Requirement R1 to require balancing authorities or reserve sharing groups: (1) To notify the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1 preventing it from complying with the 15-minute ACE recovery period; and (2) to provide the reliability coordinator with its ACE recovery plan, including a target recovery time. NERC may also propose an equally efficient and effective alternative. B. The 90-Minute Contingency Reserve Restoration Period NERC Petition 38. Reliability Standard BAL–002–2, Requirement R3 requires a balancing authority or reserve sharing group to restore its contingency reserves to at least its most severe single contingency before the end of the 90-minute Contingency Reserve Restoration Period.44 Requirement R3 also provides for an automatic ‘‘reset’’ of the 9043 APS Comments at 8. Petition, Ex. D (Implementation Plan). The 90-minute contingency reserve restoration period begins after the end of the 15-minute ACE restoration period under Requirement R1. Accordingly, responsible entities must restore contingency reserves within 105 minutes of the occurrence of a Reportable Balancing Contingency Event to comply with Requirement R3. 44 NERC E:\FR\FM\02FER1.SGM 02FER1 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations minute restoration period based upon any Balancing Contingency Event that occurs during the restoration period.45 NOPR 39. In the NOPR, the Commission proposed to direct NERC to modify Reliability Standard BAL–002–2 to ‘‘eliminate the potential for unlimited resets and ensure that contingency reserves must be restored within the 90minute Contingency Reserve Restoration Period.’’ 46 The Commission sought comment on a possible alternative that would give a balancing authority or reserve sharing group ‘‘credits’’ for megawatt losses resulting from Balancing Contingency Events during the 90-minute restoration period, and allow an additional 90 minutes to restore reserves related to those megawatt losses.47 mstockstill on DSK3G9T082PROD with RULES Comments 40. NERC, EEI, NRECA, CEA, Joint Commenters, IESO and APS support approval of Requirement R3 as filed. NERC asserts that, because of resource limitations and the potential compliance exposure to other Reliability Standards, including the Reporting ACE recovery requirements in Reliability Standard BAL–001–2, entities will not experience unlimited resets of the 90minute restoration period.48 NERC explains that ‘‘[i]f an entity continues to trip units before full recovery of other units, the responsible entity would eventually fail to meet obligations under other Reliability Standards (including the requirement to recover ACE within 15 minutes under proposed BAL–002–2) and may eventually enter into an Emergency situation under [reliability coordinator] oversight . . .’’ 49 NERC states that balancing authorities and 45 Balancing Contingency Event means: ‘‘Any single event described in Subsections (A), (B), or (C) below, or any series of such otherwise single events, with each separated from the next by one minute or less. A. Sudden loss of generation: a. Due to i. unit tripping, ii. loss of generator Facility resulting in isolation of the generator from the Bulk Electric System or from the responsible entity’s System, or iii. sudden unplanned outage of transmission Facility; b. And, that causes an unexpected change to the responsible entity’s ACE; B. Sudden loss of an import, due to unplanned outage of transmission equipment that causes an unexpected imbalance between generation and Demand on the Interconnection. C. Sudden restoration of a Demand that was used as a resource that causes an unexpected change to the responsible entity’s ACE.’’ NERC Petition Ex. D. 46 NOPR, 155 FERC ¶ 61,180 at P 29. 47 Id. PP 27–29. 48 NERC Comments at 17–18. 49 Id. at 17. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 reserve sharing groups would still be required to actively restore contingency reserves even after experiencing a Balancing Contingency Event during the 90-minute restoration period. Such events, according to NERC, ‘‘would merely extend the Contingency Reserve Restoration Period to ensure that the responsible entity has adequate time to recover from consecutive losses.’’ 50 NERC asserts that the Commission’s proposed credit approach ‘‘would be confusing and burdensome, and it may attract attention away from full and final restoration of the Contingency Reserve.’’ 51 EEI agrees, adding that, ‘‘in light of existing standards, this concern does not pose a sufficient risk to system reliability to merit NERC developing modifications to the standard.’’ 52 41. IESO and CEA claim that modifications to Reliability Standard BAL–002–2, Requirement R1 to eliminate the potential for unlimited resets are unnecessary. IESO questions the concern about unlimited resets of the Contingency Reserve Restoration Period, stating that it ‘‘would suggest that multiple resource loss events could somehow benefit or unburden a [balancing authority’s] obligation to restore the reserve level . . . [rather] the infrequent event of a reset occurrence is more appropriately viewed as simply not applying double jeopardy to a [balancing authority] that is already in a troubled situation.’’ 53 IESO further states that a reset of the contingency reserve restoration period ‘‘will simply provide the opportunity for the involved balancing authority to reassess the situation and act accordingly to replenish the contingency reserve’’ to comply with BAL–002–2.54 Both IESO and CEA assert that balancing authorities ‘‘have a strong track record of acting in good faith.’’ 55 CEA also notes that ‘‘since a [balancing authority] does not own any resources, it cannot trigger or otherwise intentionally cause an additional loss of resource during the 90-minute period in order to reset the recovery period.’’ 56 42. Joint Commenters also oppose the Commission’s proposal, explaining that ‘‘following a unit trip that results in a [Balancing Contingency Event], the generator’s telemetry is often invalid or suspect for some time, and if the [balancing authority] is unable to 50 Id. at 16. at 18–19. 52 EEI Comments at 8. 53 IESO Comments at 4–5. 54 Id. at 5; see also CEA Comments at 5. 55 CEA Comments at 5; see also IESO Comments at 5. 56 CEA Comments at 4; see also IESO Comments at 5. 8999 accurately quantify the actual MW loss, it may be required to take extreme actions, including shedding firm load, simply to meet the 90-minute contingency recovery requirement.’’ 57 Joint Commenters claim that the ‘‘likelihood of such an occurrence of multiple independent generation losses absent a catastrophic transmission failure is also very low.’’ 58 Joint Commenters state that on average, one generator is lost in the Eastern Interconnection every 7 to 8 days, and ‘‘the probability of four random large generator trips in the Eastern Interconnection in a two hour period was one in 350 years.’’ 59 43. BPA and Idaho Power support the Commission’s proposal to require balancing authorities to restore contingency reserves within the 90minute Contingency Event Recovery Period and receive ‘‘credits’’ for megawatt losses during the Contingency Event Recovery Period. TVA believes the potential for unlimited resets of the 90-minute restoration period is ‘‘extremely remote,’’ but TVA supports the credit proposal as a ‘‘reasonable approach’’ for managing multiple events during a contingency restoration period. Commission Determination 44. The Commission determines not to adopt the NOPR proposal that NERC modify Reliability Standard BAL–002–2 to establish a firm requirement that responsible entities must restore contingency reserves within the 90minute Contingency Reserve Restoration Period. Based on the comments, we are satisfied that occurrences of multiple Balancing Contingency Events during the 90-minute restoration period are rare and would be temporally bounded by the Reporting ACE recovery requirements in Reliability Standard BAL–001–2. We also acknowledge NERC’s comment that intervening Balancing Contingency Events do not relieve balancing authorities and reserve sharing groups of their obligation to restore contingency reserves by the end of the reset period. Further, we acknowledge Joint Commenters’ concern that determining the amount of megawatt losses to ‘‘credit’’ could be a distraction from the contingency reserve restoration effort, and the benefits from the proposed ‘‘credit’’ approach could be offset by unnecessary load shedding caused by potential confusion and 51 Id. PO 00000 Frm 00015 Fmt 4700 Sfmt 4700 57 Joint Commenters Comments at 5. 58 Id. 59 Joint Commenters Comments at 6 (citing a probability analysis performed during the Reliability Standard BAL–003–1 development process using frequency event data for January 2006 to September 2012). E:\FR\FM\02FER1.SGM 02FER1 9000 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations uncertainties associated with its implementation. 45. While, as stated in the NOPR, under some circumstances, extensions of the 90-minute Contingency Reserve Restoration Period may be appropriate, the comments do not fully address the concern expressed in the NOPR with resets resulting from additional megawatt losses following a Reportable Balancing Contingency Event. Therefore, although we determine not to direct modifications to the Reliability Standard, we conclude that the automatic reset provision of Reliability Standard BAL–002–2, Requirement R3 should be monitored for potential problems. 46. Accordingly, the Commission directs NERC to collect and report data pertaining to: (1) Additional megawatt losses following Reportable Balancing Contingency Events during the Contingency Reserve Restoration Period; and (2) the time periods for contingency reserve restoration under Requirement R3 and the number of resets of the 90minute restoration period, and submit a report to the Commission two years following the first day of implementation of Requirement R3. After NERC reports on the data in a compliance filing, the Commission will consider what further action, if any, to take. C. Exclusion of Megawatt Losses Above the Most Severe Single Contingency mstockstill on DSK3G9T082PROD with RULES NERC Petition 47. NERC’s definition of Reportable Balancing Contingency Event limits balancing authority and reserve sharing group responsibility to megawatt losses between 80 percent and 100 percent of their most severe single contingency that occur within a one minute interval.60 In its petition, NERC asserted that an ‘‘integrated and coordinated’’ suite of set of Reliability Standards (BAL–001–2, BAL–003–1, TOP–007–0, EOP–002–3, EOP–011–1, IRO–008–2, and IRO–009–2) will address the ‘‘complex issues’’ resulting from exceedances of the most severe single contingency.61 NOPR 48. In the NOPR, the Commission expressed concern about the exclusion of megawatt losses above a responsible entity’s most severe single contingency from the scope of Reliability Standard BAL–002–2. The Commission questioned the assumption that all such megawatt losses, however small, 60 See NERC Petition, Ex. D (Implementation Plan) at 2. 61 NERC Petition at 15. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 warrant the proposed limitation on Reliability Standard BAL–002–2.62 Further, while recognizing the protections that the related set of Reliability Standards may provide in extreme circumstances, the Commission noted that megawatt exceedances of the most severe single contingency that do not cause energy emergencies or otherwise implicate the set of Reliability Standards cited by NERC could result in a reliability gap; they also could create the potential for balancing authorities to lean on the Interconnection by indefinitely relying on neighboring balancing authorities’ resources.63 49. In the NOPR, the Commission did not propose a specific approach but, rather, sought comment on how to address this possible reliability gap and whether to impose a reasonable obligation for balancing authorities and reserve sharing groups to address scenarios involving megawatt losses above the most severe single contingency that do not cause energy emergencies. The NOPR stated that, based on the comments, the Commission may direct that NERC develop a new or modified Reliability Standard to address that reliability gap.64 Comments 50. NERC, EEI, NRECA, TVA, BPA, CEA, Joint Commenters, IESO, and APS assert that concerns about a possible reliability gap are unfounded and urge the Commission to approve Reliability Standard BAL–002–2 as filed. NERC maintains that the limitation on the scope of Reliability Standard BAL–002– 2 will not create a reliability gap and reasserts its view that an integrated, coordinated suite of Reliability Standards ‘‘will address important reliability issues and prohibit entities from being able to ‘lean’ on the Interconnection when contingency events cause MW losses greater than an entity’s MSSC.’’ 65 NERC states that in situations involving megawatt losses above the most severe single contingency, reliability issues associated with ACE recovery and contingency reserve restoration become less important and other reliability issues ‘‘such as transmission lineloading issues or frequency deviations’’ create more immediate reliability threats and warrant priority status.66 62 NOPR, 155 FERC ¶ 61,180 at P 33. 63 Id. 64 Id. at 34. Comments at 20 (citing Reliability Standards BAL–001–2, BAL–003–1, EOP–002–3, EOP–011–1, IRO–001–4, TOP–001–3, IRO–008–2, and IRO–009–2). 66 Id. 51. EEI agrees with NERC, and also notes that exceedances of the most severe single contingency that do not create energy emergencies generally raise commercial, not reliability, issues. Further, EEI asserts that tightening Reliability Standard BAL–002–2 by requiring balancing authorities to address megawatt losses above the most severe single contingency ‘‘could have unintended consequences that limit the flexibility of the [reliability coordinators] and [balancing authorities] to work together under the existing suite of standards to address such complex situations . . .’’ 67 52. Joint Commenters consider requiring balancing authorities and reserve sharing groups to address megawatt losses above the most severe single contingency as tantamount to requiring entities to operate to ‘‘N–2’’ or greater conditions. Joint Commenters assert that this would not only be expensive, estimating that doubling current contingency reserves across North America could cost $150–200 million/year based on average monthly cost of spinning reserves, it could adversely impact reliability. Joint Commenters state that N–2 events typically result from severe transmission events involving weather, major equipment or protection system failures. According to Joint Commenters, ‘‘[i]n these situations, transmission security takes priority over maintaining ACE to zero. Excessive generation dispatch by [balancing authorities] could interfere with actions taken simultaneously by Transmission Operators and remote [balancing authorities] to resolve problems on the transmission system.’’ 68 53. Joint Commenters explain that the available data reflecting experience with megawatt losses subject to currentlyeffective Reliability Standard BAL–002– 1 indicates that concerns about a reliability gap are overstated. According to Joint Commenters, of the 95 events involving most severe single contingency exceedances from 2012 to 2015, 91 were recovered in less than 15 minutes, and there were no Interconnected Reliability Operating Limit (IROL) exceedances of over 30 minutes in 2015, ‘‘which demonstrates that the grid was secure even while zero ACE was not achieved within 15 minutes.’’ 69 54. CEA and IESO also oppose requiring balancing authorities or reserve sharing groups to address 65 NERC PO 00000 Frm 00016 Fmt 4700 Sfmt 4700 67 EEI Comments at 11–12. Commenters Comments at 9. 69 Id. at 8 (citing NERC’s 2016 State of Reliability Report). 68 Joint E:\FR\FM\02FER1.SGM 02FER1 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations mstockstill on DSK3G9T082PROD with RULES megawatt losses exceeding the most severe single contingency, which they describe as an ‘‘open-ended requirement.’’ 70 CEA explains that it ‘‘can severely affect a [balancing authority’s] ability to suitably plan for potential contingency events. At an increased cost and at the expense of reduced market efficiency (more capacity is put aside for reserve as opposed to bidding into the energy market), a [balancing authority] could, in theory, design and operate to N–2, N–3 or greater events. However, this is simply not feasible.’’ 71 Commission Determination 55. The Commission remains concerned with relying on a ‘‘coordinated suite of standards,’’ as NERC maintains, to address reliability issues associated with megawatt losses above the most severe single contingency, considering that these other Reliability Standards do not specifically address restoration of ACE and Contingency Reserves. Further, the requirements for emergency Operating Plans in Reliability Standard EOP–011– 1 do not specify any obligation for a balancing authority, transmission system operator, and/or reliability coordinator to take action to return ACE to zero for all operating conditions. 56. Additionally, Reliability Standards TOP–001–3, EOP–003–2, IRO–008–2, and IRO–009–2 pertain to actions needed to prevent or mitigate SOLs/IROLs caused by transmission line loading and other responsibilities of the transmission system operator and reliability coordinator. These Reliability Standards do not specifically address the balancing authority’s responsibility to recover ACE by balancing load and generation, the purpose of Reliability Standard BAL–002–2. 57. The Commission finds the arguments and historical data provided by commenters to be helpful regarding whether there is a need to expand the requirements of Reliability Standard BAL–002–2 to address most severe single contingency exceedances that do not cause energy emergencies, as contemplated in the NOPR. Nonetheless, we believe the comments do not fully resolve open questions regarding the potential reliability impact of suspending the focus on the balancing of demand and load and ACE recovery—the purpose of Reliability Standard BAL–002–2—in exceedance scenarios. 58. The Commission determines that it is important to better understand the 70 CEA 71 CEA Comments at 5; IESO Comments at 7. Comments at 5–6. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 potential impacts of the approach taken in Reliability Standard BAL–002–2 when megawatt losses exceed the most severe single contingency without causing an energy emergency. Accordingly, we direct NERC to study the reliability risks associated with most severe single contingency exceedances that do not cause energy emergencies and submit a report with findings to the Commission two years from Reliability Standard BAL–002–2 implementation. D. Violation Risk Factor for Requirements R1 and R2 NERC Petition 59. NERC proposed a ‘‘medium’’ violation risk factor for each requirement of Reliability Standard BAL–002–2. NOPR 60. In the NOPR, the Commission expressed concern that NERC did not adequately justify lowering the assignment of the violation risk factor for Requirements R1 and R2 and proposed to direct that NERC assign a ‘‘high’’ violation risk factor to Reliability Standard BAL–002–2, Requirements R1 and R2. 61. Requirement R1 requires a balancing authority or reserve sharing group to deploy contingency reserves in response to all Reportable Balancing Contingency Events as the means for recovering Reporting ACE. Requirement R2 requires a balancing authority or reserve sharing group to develop, review and maintain a process within its Operating Plans for determining its most severe single contingency and to prepare to have contingency reserves equal to, or greater than, its most severe single contingency. Currently-effective Reliability Standard BAL–002–1 assigns a ‘‘high’’ violation risk factor for its Requirements R3 and R3.1, which NERC explained are analogous to proposed Requirements R1 and R2 in Reliability Standard BAL–002–2.72 62. In the NOPR, the Commission stated that NERC provided insufficient support for the proposed violation risk factor for Requirements R1 and R2. In justifying the assignment of a ‘‘medium’’ violation risk factor NERC asserted, without explanation, that a ‘‘medium’’ violation risk factor is ‘‘consistent with other reliability standards (i.e., BAL– 001–2, BAL–003–1).’’ 73 NERC also contended, without explanation, that Requirement R3 is similar in concept to the current enforceable BAL–001–0.1a standard Requirements R1 and R2, which have an approved medium violation risk factor, and approved reliability standards BAL–001–1 and BAL–003–1.74 The conclusory statements in NERC’s petition regarding the alleged similarities between Requirements R1 and R2 and other Reliability Standards, the NOPR stated, do not adequately explain the alleged bases for reducing the violation risk factor for Requirements R1 and R2 from the analogous Requirement R3 in the currently-effective Reliability Standard. Comments 63. NERC, EEI and APS oppose raising the violation risk factor for Reliability Standard BAL–002–2 to ‘‘high’’ as proposed in the NOPR. NERC asserts that a failure to perform Requirements R1 and R2 ‘‘in real time would produce results consistent with the Commission approved guidelines for a ‘Medium’ [violation risk factor] VRF . . . [that is] unlikely to lead to Bulk Electric System instability, separation, or cascading failures.’’ 75 With regard to Requirement R1, NERC states that Reporting ACE ‘‘is not an immediate measure of reliability, and the risk resulting from failure to meet Requirement R1’’ is not likely to lead to instability, separation or cascading failures, the criteria for a high violation risk factor.76 Likewise, NERC asserts that a ‘‘medium’’ violation risk factor is appropriate for Requirement R2, because the process responsible entities use for developing and reviewing their most severe single contingency ‘‘does not directly contribute to reliability.’’ 77 EEI agrees, adding that it ‘‘also believes the medium VRF is justified because in most instances ACE is more reflective of commercial issues, particularly if frequency remains normal.’’ 78 64. APS also disagrees with the NOPR proposal because the Commission ‘‘utilizes previous versions of reliability standards as a benchmark for the acceptability of VRFs [violation risk factors].’’ 79 APS states that it is ‘‘concerned that the assignment of a VRF based solely on the previous VRF assignments may contravene the current NERC Rules of Procedure and associated processes.’’ 80 APS recommends that the Commission direct NERC to reevaluate 74 Id. 75 NERC Comments at 28. at 29. 77 Id. at 30. 78 EEI at 13. 79 APS Comments at 11. 80 Id. 76 Id. 72 NERC Petition, Ex. I (Mapping Document for BAL–002–2). 73 NERC Petition, Ex. G (Analysis of Violation Risk Factors and Violation Severity Levels) at 4. PO 00000 Frm 00017 Fmt 4700 Sfmt 4700 9001 E:\FR\FM\02FER1.SGM 02FER1 9002 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations the VRFs for Reliability Standard BAL– 002–2 ‘‘against existing guidance.’’ 81 Commission Determination 65. We adopt the NOPR proposal regarding the violation risk factor for Reliability Standard BAL–002–2, Requirements R1 and R2. According to the Commission-approved criteria, a ‘‘high’’ violation risk factor should be assigned to a Reliability Standard requirement if violating the requirement could ‘‘directly cause or contribute to the Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation or cascading failures.’’ Reliability Standard BAL– 002–2, Requirement R1 requires responsible entities to recover Reporting ACE following the occurrence of a Reportable Balancing Contingency Event, which supports Interconnection frequency in real-time. 66. We disagree with NERC that significant real-time differences between actual and scheduled interchange, the imbalance that Requirement R1 is intended to address, do not fall within the scope of the criterion for a ‘‘high’’ violation risk factor. The need for the bulk electric system to stabilize after changes in system frequency is critical for real-time system operations. NERC asserts that the status of Reporting ACE ‘‘is not indicative of an immediate vulnerability.’’ 82 We disagree. A violation of Requirement R1 jeopardizes system frequency, because it places the bulk electric system in a weakened operating condition with heightened risks of instability, separation, or cascading failures that could result from a second contingency. 67. With regard to Requirement R2, NERC acknowledges that actions under Requirement R2 ‘‘support Requirement R1 by requiring responsible entities to develop, review, and maintain a process to determine the MSSC and to maintain, for deployment under Requirement R1, at least enough Contingency Reserve to cover the MSSC . . . [Requirement R2] is critical to the implementation of proposed Reliability Standard BAL– 002–2.’’ 83 Nonetheless, NERC asserts that Requirement R2 ‘‘does not directly contribute to reliability.’’ 84 We disagree, and conclude that the fundamental connection between Requirements R1 and R2 creates a significant role in maintaining reliability. 68. Accordingly, we direct NERC to assign a ‘‘high’’ violation risk factor to Reliability Standard BAL–002–2, Requirements R1 and R2. V. Information Collection Statement 69. The Office of Management and Budget (OMB) regulations require that OMB approve certain reporting and recordkeeping (collections of information) imposed by an agency.85 Upon approval of a collection(s) of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. 70. The Commission is submitting these reporting and recordkeeping requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act of 1995, 44 U.S.C. 3507(d) (2012). The NOPR solicited comments on the Commission’s need for this information, whether the information will have practical utility, the accuracy of the provided burden estimate, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent’s burden, including the use of automated information techniques. No comments were received. 71. This final rule approves revisions to Reliability Standard BAL–002–1. NERC states in its petition that the Reliability Standard applies to balancing authorities and reserve sharing groups, and is designed to ensure that these entities are able to recover from system contingencies by deploying adequate reserves to return their ACE to defined values and by replacing the capacity and energy lost due to generation or transmission equipment outages. The Commission also approves NERC’s seven new definitions and one proposed revised definition, and the retirement of currently-effective Reliability Standard BAL–002–1 immediately prior to the effective date of BAL–002–2. 72. Public Reporting Burden: Our estimate below regarding the number of respondents is based on the NERC Compliance Registry as of April 15, 2016. According to the NERC Compliance Registry, there are 70 balancing authorities in the Eastern Interconnection, 34 balancing authorities in the Western Interconnection and one balancing authority in the Electric Reliability Council of Texas (ERCOT). The Commission bases individual burden estimates on the time needed for balancing authorities and reserve sharing groups to maintain, annually, the operating process and operating plan that are required in the Reliability Standard. These burden estimates are consistent with estimates for similar tasks in other Commission-approved Reliability Standards. The following estimates relate to the requirements for this final rule in Docket No. RM16–7– 000. RM16–7–000 [BAL–002–2: Disturbance Control Standard—Contingency Reserve for recovery from a Balancing Contingency Event] 86 Number of respondents Annual number of responses per respondent Total number of responses Average burden hours and cost per response 87 Total annual burden hours and total annual cost Cost per respondent ($) (1) (2) (1)*(2) = (3) (4) (3)*(4) = (5) (5)÷(1) mstockstill on DSK3G9T082PROD with RULES BA/RSG: 88 Develop and Maintain annually, Operating Process and Operating Plans ... 81 Id. Comments at 29. 83 Id. at 29. 84 Id. at 30. 85 5 CFR 1320.11. 19:35 Feb 01, 2017 1 105 86 Reliability Standard BAL–002–2 applies to balancing authorities and reserve sharing groups. However, the burden associated with the balancing authorities complying with Requirements R1and R3 is not included within this table because the Commission accounted for it under Commissionapproved Reliability Standard BAL–002–1. 82 NERC VerDate Sep<11>2014 105 Jkt 241001 PO 00000 Frm 00018 Fmt 4700 Sfmt 4700 8 $774 840 $81,262 $774 87 The estimated hourly cost (salary plus benefits) of $96.71 is an average based on Bureau of Labor Statistics (BLS) information (http://www.bls.gov/ oes/current/naics2_22.htm) for an electrical engineer ($64.29/hour) and a lawyer ($129.12). 88 BA = Balancing Authority; RSG = Reserve Sharing Group. E:\FR\FM\02FER1.SGM 02FER1 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations 9003 RM16–7–000—Continued [BAL–002–2: Disturbance Control Standard—Contingency Reserve for recovery from a Balancing Contingency Event] 86 Number of respondents Annual number of responses per respondent Total number of responses Average burden hours and cost per response 87 Total annual burden hours and total annual cost Cost per respondent ($) (1) (2) (1)*(2) = (3) (4) (3)*(4) = (5) (5)÷(1) 105 1 105 4 $112 420 $11,760 112 Total ........................................................ mstockstill on DSK3G9T082PROD with RULES BA/RSG: Record Retention 89 ....................... ........................ ........................ 210 ........................ 1,260 $93,022 886 Title: FERC–725R, Mandatory Reliability Standard BAL–002–2. Action: Collection of Information. OMB Control No.: 1902–0268. Respondents: Businesses or other forprofit institutions; not-for-profit institutions. Frequency of Responses: On Occasion. Necessity of the Information: This final rule approves Reliability Standard BAL–002–2, which is designed to ensure that a responsible entity, either a balancing authority or reserve sharing group, is able to recover from system contingencies by deploying adequate reserves to return its ACE to defined values and replacing the capacity and energy lost due to generation or transmission equipment outages. Reliability Standard BAL–002–2, Requirement R1 requires a responsible entity, either a balancing authority or reserve sharing group, experiencing a Reportable Balancing Contingency Event to deploy its contingency reserves to recover its ACE to certain prescribed values within the Contingency Event Recovery Period of 15 minutes. Requirement R2 requires a balancing authority or reserve sharing group to develop, review and maintain a process within its Operating Plans for determining its most severe single contingency and prepare to have contingency reserves equal to, or greater than, its most severe single contingency. Requirement R3 provides that, following a Reportable Balancing Contingency Event, the responsible entity shall restore its Contingency Reserve to at least its most severe single contingency, before the end of the Contingency Reserve Restoration Period of 90 minutes. Internal Review: The Commission reviewed the Reliability Standard and has determined that it is necessary to implement section 215 of the FPA. The requirements of Reliability Standard BAL–002–2 should conform to the 89 $28/hour, based on a Commission staff study of record retention burden cost. VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 Commission’s expectation for generation and demand balance throughout the Eastern and Western Interconnections as well as within the ERCOT Region. 73. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: (202) 502–8663, fax: (202) 273–0873]. VI. Environmental Analysis 74. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.90 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended.91 The actions proposed here fall within this categorical exclusion in the Commission’s regulations. VII. Regulatory Flexibility Act 75. The Regulatory Flexibility Act of 1980 (RFA) 92 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. As shown in the information collection section, the Reliability Standard applies to 105 entities. Comparison of the applicable entities with the Commission’s small business data indicates that approximately 23 93 90 Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987). 91 18 CFR 380.4(a)(2)(ii). 92 5 U.S.C. 601–612. 93 21.73 percent of the total number of affected entities. PO 00000 Frm 00019 Fmt 4700 Sfmt 4700 are small business entities.94 Of these, the Commission estimates that approximately five percent, or one of these 23 small entities, will be affected by the new requirements of the Reliability Standard. 76. The Commission estimates that the small entities affected by Reliability Standard BAL–002–2 will incur an annual compliance cost of up to $20,355 (i.e., the cost of developing, and maintaining annually operating process and operating plans), resulting in a cost of approximately $885 per balancing authority and/or reserve sharing group. These costs represent an estimate of the costs a small entity could incur if the entity is identified as an applicable entity. The Commission does not consider the estimated cost per small entity to have a significant economic impact on a substantial number of small entities. Accordingly, the Commission certifies that this final rule will not have a significant economic impact on a substantial number of small entities. VIII. Document Availability 77. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission’s Home Page (http:// www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 78. From the Commission’s Home Page on the Internet, this information is available on eLibrary. The full text of 94 The Small Business Administration sets the threshold for what constitutes a small business. Public utilities may fall under one of several different categories, each with a size threshold based on the company’s number of employees, including affiliates, the parent company, and subsidiaries. For the analysis in this final rule, we are using a 500 employee threshold for each affected entity. Each entity is classified as Electric Bulk Power Transmission and Control (NAICS code 221121). E:\FR\FM\02FER1.SGM 02FER1 9004 Federal Register / Vol. 82, No. 21 / Thursday, February 2, 2017 / Rules and Regulations this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number of this document, excluding the last three digits, in the docket number field. 79. User assistance is available for eLibrary and the Commission’s Web site during normal business hours from the Commission’s Online Support at (202) 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202) 502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. IX. Effective Date and Congressional Notification 80. These regulations are effective April 3, 2017. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a ‘‘major rule’’ as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. By the Commission. Issued: January 19, 2017. Nathaniel J. Davis, Sr., Deputy Secretary. Note: The following appendix will not appear in the Code of Federal Regulations. Appendix—Commenters Abbreviation Commenter APS ...................................... BPA ...................................... CEA ...................................... EEI ........................................ Idaho Power ......................... IESO ..................................... Joint Commenters ................ Arizona Public Service Company. Bonneville Power Administration. Canadian Electricity Association. Edison Electric Institute. Idaho Power. Independent Electricity System Operator. Alberta Electric System Operator, California Independent System Operator, Electric Reliability Council of Texas, Inc., Midcontinent Independent System Operator, Inc., PJM Interconnection, L.L.C., Southwest Power Pool, Inc., and IESO. Naturener USA, LLC. North American Electric Reliability Corporation. National Rural Electric Cooperative Association. Tennessee Valley Authority. Naturener ............................. NERC ................................... NRECA ................................. TVA ...................................... [FR Doc. 2017–02175 Filed 2–1–17; 8:45 am] BILLING CODE 6717–01–P LIBRARY OF CONGRESS Copyright Office 37 CFR Parts 201 and 204 [Docket No. 2016–7] Removal of Personally Identifiable Information From Registration Records U.S. Copyright Office, Library of Congress. ACTION: Final rule. AGENCY: The U.S. Copyright Office is issuing a final rule to allow authors and claimants to replace or remove personally identifiable information (‘‘PII’’) from the Office’s online registration catalog. This rule allows authors and claimants, or their authorized representatives, to request the replacement or removal of certain PII that is requested by the Office and collected on a registration application, such as a home addresses or personal phone numbers, from the Office’s internet-accessible public catalog, while retaining that information in the Office’s offline records as required by law. The rule also codifies an existing practice that removes extraneous PII, such as driver’s license numbers, social security numbers, banking information, and credit card information, on the Office’s mstockstill on DSK3G9T082PROD with RULES SUMMARY: VerDate Sep<11>2014 19:35 Feb 01, 2017 Jkt 241001 own volition or upon request by authors, claimants, or their authorized representatives. DATES: Effective March 6, 2017. FOR FURTHER INFORMATION CONTACT: Cindy Abramson, Assistant General Counsel, by email at ciab@loc.gov, or Abioye Mosheim, Attorney Advisor, by email at abmo@loc.gov. Each can be reached by telephone by calling 202– 707–8350. SUPPLEMENTARY INFORMATION: I. Background On September 15, 2016, the Copyright Office published a notice of proposed rulemaking (‘‘NPRM’’) to create procedures to request removal of certain ‘‘personally identifiable information’’ (‘‘PII’’) from the Office’s registration records.1 PII is generally considered to be any information that has the potential to identify a specific individual. The NPRM concerned two distinct categories of PII. First, the Office requests and receives certain types of PII during the registration process (e.g., dates of birth, addresses, telephone numbers, fax numbers, and email addresses). The collection of some of that information is mandated by statute or regulation; other information is optional.2 This 1 81 FR 63440 (Sept. 15, 2006). Copyright Act requires the Office to gather the name and address of the copyright claimant; the name of the author(s), for works that are not anonymous or pseudonymous; the nationality or 2 The PO 00000 Frm 00020 Fmt 4700 Sfmt 4700 information is referred to herein as ‘‘requested PII.’’ Second, the Office does not request, but sometimes receives, additional PII that applicants include in their registration applications, such as driver’s license numbers, social security numbers, banking information, and credit card information on their registration applications. Such information is extraneous and unnecessary for the processing and maintenance of copyright registration records. This information is referred to herein as ‘‘extraneous PII.’’ With respect to requested PII— information that the Copyright Office purposely collects as part of registration—the Copyright Act imposes certain obligations on the Office to preserve that information as part of the public record. The Act requires the Register to ensure that ‘‘records of . . . registrations . . . are maintained, and that indexes of such records are prepared,’’ and that ‘‘[s]uch records and indexes . . . be open to public inspection,’’ thus creating a public record. 17 U.S.C. 705(a), 705(b). The public record of copyright registrations serves several important functions. Chief among these is that the record domicile of the author(s); and date(s) of death for deceased author(s). See 17 U.S.C. 409. The Act also gives the Register of Copyrights the authority to require applicants to supply any other information ‘‘bearing upon the preparation or identification of the work or the existence, ownership, or duration of copyright.’’ Id. E:\FR\FM\02FER1.SGM 02FER1

Agencies

[Federal Register Volume 82, Number 21 (Thursday, February 2, 2017)]
[Rules and Regulations]
[Pages 8994-9004]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-02175]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM16-7-000; Order No. 835]


Disturbance Control Standard--Contingency Reserve for Recovery 
From a Balancing Contingency Event Reliability Standard

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final rule.

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SUMMARY: The Commission approves Reliability Standard BAL-002-2 
(Disturbance Control Standard--Contingency Reserve for Recovery from a 
Balancing Contingency Event) submitted by the North American Electric 
Reliability Corporation (NERC). Reliability Standard BAL-002-2 is 
designed to ensure that balancing authorities and reserve sharing 
groups balance resources and demand and return their Area Control Error 
to defined values following a Reportable Balancing Contingency Event. 
In addition, the Commission directs NERC to develop modifications to 
Reliability Standard BAL-002-2 to address concerns regarding extensions 
of the 15-minute period for Area Control Error recovery and contingency 
reserve restoration. The Commission also directs NERC to collect and 
report on data regarding additional megawatt losses following 
Reportable Balancing Contingency Events during the Contingency Reserve 
Restoration Period and to study and report on the reliability risks 
associated with megawatt losses above the most severe single 
contingency that do not cause energy emergencies.

DATES: This rule is effective April 3, 2017.

FOR FURTHER INFORMATION CONTACT: Enakpodia Agbedia (Technical 
Information), Office of Electric Reliability, Division of Reliability 
Standards, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, Telephone: (202) 502-6750, 
Enakpodia.Agbedia@ferc.gov.
    Mark Bennett (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, Telephone: (202) 502-8524, Mark.Bennett@ferc.gov.

SUPPLEMENTARY INFORMATION: 

ORDER NO. 835

FINAL RULE

(Issued January 19, 2017)

    1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the 
Commission approves Reliability Standard BAL-002-2 (Disturbance Control 
Standard--Contingency Reserve for Recovery from a Balancing Contingency 
Event). The North American Electric Reliability Corporation (NERC), the 
Commission-certified Electric Reliability Organization (ERO), developed 
and submitted Reliability Standard BAL-002-2 for Commission approval. 
Reliability Standard BAL-002-2 is intended to ensure that balancing 
authorities and reserve sharing groups are able to recover from system 
contingencies by deploying adequate reserves to return their Area 
Control Error (ACE) to defined values and by replacing the capacity and 
energy lost due to generation or transmission equipment outages.\2\ In 
addition, the Commission approves eight new and revised definitions 
proposed by NERC for inclusion in the NERC Glossary and the retirement 
of currently-effective Reliability Standard BAL-002-1 immediately prior 
to the effective date of Reliability Standard BAL-002-2. The Commission 
also approves, with one modification, Reliability Standard BAL-002-2's 
associated violation risk factors and violation severity levels, and 
implementation plan.
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    \1\ 16 U.S.C. 824(o).
    \2\ ACE is the instantaneous difference between a balancing 
authority's Net Actual and Scheduled Interchange, taking into 
account the effects of Frequency Bias, correction for meter error, 
and Automatic Time Error Correction (ATEC), if operating in ATEC 
mode. ATEC is only applicable to balancing authorities in the 
Western Interconnection. NERC Glossary of Terms Used in NERC 
Reliability Standards (NERC Glossary) at 7 (updated September 29, 
2016).
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    2. Pursuant to section 215(d)(5) of the FPA,\3\ the Commission 
directs NERC to develop modifications to Reliability Standard BAL-002-
2, Requirement R1 to address concerns related to the potential 
reliability impact of repeated extensions of the period for ACE 
recovery. To address the concerns, the Notice of Proposed Rulemaking 
(NOPR) proposed directing that NERC modify the Reliability Standard to 
require reliability coordinator approval of extensions of the ACE 
recovery period. Numerous commenters opposed the proposal, arguing that 
the proposal has the potential to complicate an already challenging 
situation. Thus, to address the underlying concern while cognizant of 
the NOPR comments, the final rule adopts a different approach of 
directing NERC to develop modifications to Reliability Standard BAL-
002-2 that would require an entity to provide certain information to 
the reliability coordinator when the entity does not timely recover ACE 
due to an intervening disturbance. As discussed below, the Commission 
also directs NERC: (1) To collect and report on data related to resets 
of the contingency reserve restoration period; and (2) to study and 
report on the reliability risks associated with megawatt losses above 
an applicable entity's most severe single contingency (MSSC) that do 
not cause energy emergencies.
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    \3\ 16 U.S.C. 824o(d)(5).
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I. Background

    3. Section 215 of the FPA requires a Commission-certified ERO to 
develop mandatory and enforceable Reliability Standards that are 
subject to Commission review and approval. The Commission may approve, 
by rule or order, a proposed Reliability Standard or modification to a 
Reliability Standard

[[Page 8995]]

if it determines that the Reliability Standard is just, reasonable, not 
unduly discriminatory or preferential and in the public interest.\4\ 
Once approved, the Reliability Standards may be enforced by NERC, 
subject to Commission oversight, or by the Commission independently.\5\ 
Pursuant to section 215 of the FPA, the Commission established a 
process to select and certify an ERO,\6\ and subsequently certified 
NERC.\7\
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    \4\ Id. 824o(d)(2).
    \5\ Id. 824o(e).
    \6\ Rules Concerning Certification of the Electric Reliability 
Organization; and Procedures for the Establishment, Approval, and 
Enforcement of Electric Reliability Standards, Order No. 672, FERC 
Stats. & Regs. ] 31,204, order on reh'g, Order No. 672-A, FERC 
Stats. & Regs. ] 31,212 (2006).
    \7\ North American Electric Reliability Corp., 116 FERC ] 
61,062, order on reh'g and compliance, 117 FERC ] 61,126 (2006), 
aff'd sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
---------------------------------------------------------------------------

    4. On March 16, 2007, the Commission issued Order No. 693, 
approving 83 of the 107 Reliability Standards filed by NERC, including 
Reliability Standard BAL-002-0.\8\ In addition, pursuant to section 
215(d)(5) of the FPA, the Commission directed the ERO to develop 
modifications to Reliability Standard BAL-002-0: (1) To include a 
requirement that explicitly provides that demand side management may be 
used as a resource for contingency reserves; (2) to develop a 
continent-wide contingency reserve policy; and (3) to refer to the ERO 
rather than the NERC Operating Committee in Requirements R4.2 and 
R6.2.\9\ On January 10, 2011, the Commission approved Reliability 
Standard BAL-002-1, which addressed the third directive described 
above.\10\
---------------------------------------------------------------------------

    \8\ Mandatory Reliability Standards for the Bulk-Power System, 
Order No. 693, FERC Stats. & Regs. ] 31,242, order on reh'g, Order 
No. 693-A, 120 FERC ] 61,053 (2007).
    \9\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 356.
    \10\ North American Electric Reliability Corp., 134 FERC ] 
61,015 (2011).
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II. NERC Petition and Reliability Standard BAL-002-2

    5. On January 29, 2016, NERC filed a petition seeking approval of 
Reliability Standard BAL-002-2; \11\ eight new or revised definitions 
to be added to the NERC Glossary; and Reliability Standard BAL-002-2's 
associated violation risk factors and violation severity levels, 
effective date, and implementation plan.\12\ NERC stated that 
Reliability Standard BAL-002-2 is just, reasonable, not unduly 
discriminatory or preferential, and in the public interest because it 
satisfies the factors set forth in Order No. 672, which the Commission 
applies when reviewing a proposed Reliability Standard.\13\ NERC also 
asserted that Reliability Standard BAL-002-2 addresses the outstanding 
directives from Order No. 693 regarding the use of demand side 
management as a resource for contingency reserve and the development of 
a continent-wide contingency reserve policy.
---------------------------------------------------------------------------

    \11\ Reliability Standard BAL-002-2 is available on the 
Commission's eLibrary document retrieval system in Docket No. RM16-
7-000 and on the NERC Web site, www.nerc.com.
    \12\ The eight proposed new and revised definitions for 
inclusion in the NERC Glossary are for the following terms: 
Balancing Contingency Event, Most Severe Single Contingency, 
Reportable Balancing Contingency Event, Contingency Event Recovery 
Period, Contingency Reserve Restoration Period, Pre-Reporting 
Contingency Event ACE Value, Reserve Sharing Group Reporting ACE, 
and Contingency Reserve. NERC Petition at 28-34.
    \13\ NERC Petition at 13 and Ex. F (Order No. 672 Criteria).
---------------------------------------------------------------------------

    6. Reliability Standard BAL-002-2 consolidates six requirements in 
currently-effective Reliability Standard BAL-002-1 into three 
requirements and is applicable to balancing authorities and reserve 
sharing groups. NERC stated that Reliability Standard BAL-002-2 
improves upon existing Reliability Standard BAL-002-1 because ``it 
clarifies obligations associated with achieving the objective of BAL-
002 by streamlining and organizing the responsibilities required 
therein, enhancing the obligation to maintain reserves, and further 
defining events that predicate action under the standard.'' \14\ NERC 
also stated that Reliability Standard BAL-002-2 ``address[es] and 
supersede[s]'' the proposed interpretation previously submitted by NERC 
(i.e., of Reliability Standard BAL-002-1a) and pending in Docket No. 
RM13-6-000.\15\
---------------------------------------------------------------------------

    \14\ Id. at 13.
    \15\ Id. at 1. On February 12, 2013, NERC filed a proposed 
interpretation of Reliability Standard BAL-002-1 that construed the 
Reliability Standard so that the 15-minute ACE recovery period would 
not apply to events of a magnitude exceeding an entity's most severe 
single contingency. In a NOPR issued on May 16, 2013, the Commission 
proposed to remand the proposed interpretation on procedural 
grounds. Electric Reliability Organization Interpretation of 
Specific Requirements of the Disturbance Control Performance 
Standard, 143 FERC ] 61,138 (2013). The rulemaking on the proposed 
interpretation is pending. In the petition in the immediate 
proceeding, NERC states that, upon approval of Reliability Standard 
BAL-002-2, NERC will file a notice of withdrawal of the proposed 
interpretation. NERC Petition at 1.
---------------------------------------------------------------------------

    7. Requirement R1 of BAL-002-2 requires a balancing authority or 
reserve sharing group experiencing a Reportable Balancing Contingency 
Event to deploy its contingency reserves to recover its ACE to certain 
prescribed values within the Contingency Event Recovery Period of 15 
minutes.\16\ However, under certain circumstances, Reliability Standard 
BAL-002-2 relieves responsible entities from strict compliance with the 
existing time periods for ACE recovery and contingency reserve 
restoration ``to ensure responsible entities retain flexibility to 
maintain service to Demand, while managing reliability, and to avoid 
duplication with other Reliability Standards.'' \17\
---------------------------------------------------------------------------

    \16\ NERC proposes to define Reportable Balancing Contingency 
Event as: ``Any Balancing Contingency Event occurring within a one-
minute interval of an initial sudden decline in ACE based on EMS 
scan rate data that results in a loss of MW output less than or 
equal to the Most Severe Single Contingency, and greater than or 
equal to the lesser amount of: (i) 80% of the Most Severe Single 
Contingency, or (ii) the amount listed below for the applicable 
Interconnection. Prior to any given calendar quarter, the 80% 
threshold may be reduced by the responsible entity upon written 
notification to the Regional Entity.'' NERC Petition at 30. 
Contingency Event Recovery Period, as proposed by NERC, means: ``A 
period that begins at the time that the resource output begins to 
decline within the first one-minute interval of a Reportable 
Balancing Contingency Event, and extends for fifteen minutes 
thereafter.'' Id. at 32.
    \17\ Id. at 4.
---------------------------------------------------------------------------

    8. Specifically, Requirement R1, Part 1.3.1 provides that a 
balancing authority or reserve sharing group is not subject to 
Requirement R1, Part 1.1 if it: (1) Is experiencing a Reliability 
Coordinator declared Energy Emergency Alert Level; (2) is utilizing its 
contingency reserve to mitigate an operating emergency in accordance 
with its emergency Operating Plan, and (3) has depleted its contingency 
reserve to a level below its most severe single contingency.
    9. In addition, under Requirement R1, Part 1.3.2, a balancing 
authority or reserve sharing group is not subject to Requirement R1, 
Part 1.1 if the balancing authority or reserve sharing group 
experiences: (1) Multiple Contingencies where the combined megawatt 
(MW) loss exceeds its most severe single contingency and that are 
defined as a single Balancing Contingency Event or (2) multiple 
Balancing Contingency Events within the sum of the time periods defined 
by the Contingency Event Recovery Period and Contingency Reserve 
Restoration Period whose combined magnitude exceeds the Responsible 
Entity's most severe single contingency.
    10. Requirement R2 provides that each responsible entity:

shall develop, review and maintain annually, and implement an 
Operating Process as part of its Operating Plan to determine its 
Most Severe Single Contingency and to make preparations to have 
Contingency Reserve equal to, or greater than the Responsible 
Entity's Most Severe Single Contingency available for maintaining 
system reliability.


[[Page 8996]]


NERC explained that Requirement R2 requires responsible entities to 
demonstrate that their process for calculating their most severe single 
contingency ``surveys all contingencies, including single points of 
failure, to identify the event that would cause the greatest loss of 
resource output used by the [reserve sharing group or balancing 
authority] to meet Firm Demand.'' \18\ NERC further stated that 
Requirement R2 supports Requirements R1 and R3 in Reliability Standard 
BAL-002-2 ``as these requirements rely on proper calculation of [most 
severe single contingency].'' \19\
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    \18\ Id. at 25.
    \19\ Id. NERC provides examples of how responsible entities may 
calculate the most severe single contingency in the petition. See 
NERC Petition, Ex. B (Calculating Most Severe Single Contingency).
---------------------------------------------------------------------------

    11. Requirement R3 provides that ``each Responsible Entity, 
following a Reportable Balancing Contingency Event, shall restore its 
Contingency Reserve to at least its Most Severe Single Contingency, 
before the end of the Contingency Reserve Restoration Period [90 
minutes], but any Balancing Contingency Event that occurs before the 
end of a Contingency Reserve Restoration Period resets the beginning of 
the Contingency Event Recovery Period.''
    12. NERC explained that the revised language in the consolidated 
requirements in Reliability Standard BAL-002-2 will improve efficiency 
and clarity by removing ``unnecessary entities from compliance to 
capture only those entities that are vital for reliability.'' \20\ NERC 
stated that the new definitions for Balancing Contingency Event and 
Reportable Balancing Contingency Event more clearly identify the types 
of events that cause frequency deviations necessitating action under 
Reliability Standard BAL-002-2 and provide additional detail regarding 
the types of resources that may be identified as contingency reserves. 
Furthermore, NERC stated that Reliability Standard BAL-002-2 ``ensures 
objectivity of the reserve measurement process by guaranteeing a 
Commission-sanctioned continent-wide reserve policy,'' and therefore 
satisfies an outstanding Order No. 693 directive for uniform elements, 
definitions and requirements for a continent-wide contingency reserve 
policy.\21\ Finally, NERC asserted that the revised definition of 
Contingency Reserves ``improves the existing definition by addressing a 
Commission directive in Order No. 693 to allow demand side management 
to be used as a resource for contingency reserve when necessary.'' \22\
---------------------------------------------------------------------------

    \20\ NERC Petition at 14.
    \21\ Id.
    \22\ Id. at 33.
---------------------------------------------------------------------------

    13. NERC submitted proposed violation risk factors and violation 
severity levels for each requirement of Reliability Standard BAL-002-2 
and an implementation plan and effective dates. NERC stated that these 
proposals were developed and reviewed for consistency with NERC and 
Commission guidelines. NERC proposed an effective date for Reliability 
Standard BAL-002-2 that is the first day of the first calendar quarter 
that is six months after the date of Commission approval. NERC 
explained that this implementation date will allow entities to make 
necessary modifications to existing software programs to ensure 
compliance.\23\
---------------------------------------------------------------------------

    \23\ NERC Petition, Ex. D (Implementation Plan) at 3.
---------------------------------------------------------------------------

    14. On February 12, 2016, NERC submitted a supplemental filing to 
clarify a statement in the petition that Reliability Standard BAL-002-2 
would operate in conjunction with Reliability Standard TOP-007-0 to 
control system frequency by addressing transmission line loading in the 
event of a transmission overload. NERC explained that, while 
Reliability Standard TOP-007-0 will be retired on April 1, 2017, ``the 
obligations related to [transmission line loading] under TOP-007-0 will 
be covered by Commission-approved TOP-001-3, EOP-003-2, IRO-009-2, and 
IRO-008-2 . . . by requiring relevant functional entities to 
communicate [Interconnection Reliability Operating Limits (IROL)] and 
[System Operating Limits (SOL)] exceedances so that the [reliability 
coordinator] can direct appropriate corrective action to mitigate or 
prevent those events.'' \24\
---------------------------------------------------------------------------

    \24\ NERC February 12, 2016 Supplemental Filing at 2-3.
---------------------------------------------------------------------------

    15. On March 31, 2016, NERC submitted a second supplemental filing 
to ``further clarify the extent to which BAL-002-2 interacts with other 
Commission-approved Reliability Standards to promote Bulk Power System 
reliability . . . [and support] the overarching policy objective 
reflected in the stated purpose of Reliability Standard BAL-002-2.'' 
\25\ In its filing, NERC expanded upon the explanation in the petition 
regarding how an ``integrated'' and ``coordinated suite of Reliability 
Standards'' (BAL-001-2, BAL-003-1, TOP-007-0, EOP-002-3, EOP-011-1, 
IRO-008-2, and IRO-009-2) will apply to events causing MW losses above 
a responsible entity's most severe single contingency, and how those 
other Reliability Standards are better designed to manage the greater 
risks created by such events.\26\
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    \25\ NERC March 31, 2016 Supplemental Filing at 1, 5.
    \26\ Id. at 2-5.
---------------------------------------------------------------------------

III. Notice of Proposed Rulemaking

    16. On May 19, 2016, the Commission issued a NOPR proposing to 
approve Reliability Standard BAL-002-2 as just, reasonable, not unduly 
discriminatory or preferential and in the public interest.\27\ The 
Commission also proposed to approve NERC's eight proposed new and 
revised definitions and the retirement of currently-effective 
Reliability Standard BAL-002-1. Further, the Commission proposed to 
direct NERC to change the proposed violation risk factor from 
``medium'' to ``high'' for Reliability Standard BAL-002-2, Requirements 
R1 and R2.
---------------------------------------------------------------------------

    \27\ Disturbance Control Standard--Contingency Reserve for 
Recovery from a Balancing Contingency Event Reliability Standard, 
Notice of Proposed Rulemaking, 81 FR 33,441 (May 26, 2016), 155 FERC 
] 61,180 (2016) (NOPR).
---------------------------------------------------------------------------

    17. In the NOPR, the Commission recognized that it is essential for 
grid reliability that responsible entities balance resources and demand 
and restore system frequency to recover from a system event, and that 
they maintain reserves necessary to replace capacity and energy lost 
due to generation or transmission outages. The Commission also stated 
that Reliability Standard BAL-002-2 improves upon currently-effective 
Reliability Standard BAL-002-1 by consolidating requirements to 
streamline and clarify the obligations related to achieving these 
goals. However, the Commission raised concerns regarding possible 
extensions of the 15-minute ACE recovery period and the 90-minute 
Contingency Reserve Restoration Period, as well as NERC's proposal to 
limit the scope of Reliability Standard BAL-002-2 to a responsible 
entity's most severe single contingency.
    18. In the NOPR, the Commission sought comment on the following 
issues: (1) Reliability coordinator authorization of extensions of the 
15-minute ACE recovery period; (2) resets or credits during the 90-
minute Contingency Reserve Restoration Period; (3) the exclusion of 
megawatt losses above the most severe single contingency in the 
proposed definition of Reportable Balancing Contingency Event; and (4) 
NERC's proposal to reduce from ``high'' to ``medium'' the violation 
risk factor for proposed Requirements R1 and R2. The Commission also 
sought comment on whether NERC's proposed definition of contingency 
reserve should include the NERC-defined term Demand-side Management.

[[Page 8997]]

    19. In response to the NOPR, the Commission received 11 sets of 
comments. We address below the issues raised in the NOPR and comments. 
The Appendix to this final rule lists the entities that filed comments 
in response to the NOPR.

IV. Discussion

    20. Pursuant to FPA section 215(d)(2), we approve Reliability 
Standard BAL-002-2 as just, reasonable, not unduly discriminatory or 
preferential, and in the public interest. We also approve NERC's eight 
new and revised proposed definitions and, with one exception, the 
proposed violation risk factor and violation severity level 
assignments. In addition, we approve NERC's implementation plan 
establishing an effective date of the first day of the first calendar 
quarter, six months after the date of Commission approval, and the 
retirement of currently-effective BAL-002-1 immediately before that 
date.\28\
---------------------------------------------------------------------------

    \28\ NERC Petition, Ex. D (Implementation Plan) at 3.
---------------------------------------------------------------------------

    21. The purpose of Reliability Standard BAL-002-2 is to ensure that 
balancing authorities and reserve sharing groups balance resources and 
demand and return their ACE to defined values following a Reportable 
Balancing Contingency Event. We determine that Reliability Standard 
BAL-002-2 improves upon currently-effective Reliability Standard BAL-
002-1 by consolidating the number of requirements to streamline and 
clarify the obligations for responsible entities to deploy contingency 
reserves to stabilize system frequency in response to system 
contingencies.
    22. We conclude that BAL-002-2 satisfies the Order No. 693 
directive that NERC develop a continent-wide contingency reserve 
policy.\29\ Also, we accept NERC's explanation in response to the NOPR 
that demand side resources that are technically capable can be included 
as contingency reserves, and therefore determine that Reliability 
Standard BAL-002-2 satisfies the Order No. 693 directive that demand 
side management may be used as a resource for contingency reserves.\30\
---------------------------------------------------------------------------

    \29\ Order No. 693, FERC Stats. & Regs ] 31,242 at PP 340, 341 
and 356.
    \30\ Order No. 693, FERC Stats. & Regs. ] 31,242 at PP 330, 335 
and 356. In its comments NERC explained that ``[t]he proposed 
definition balances the need for flexibility to include a variety of 
demand side resources in measurements of Contingency Reserve with 
the need to define the types of demand side resources that are 
`technically capable' to serve as contingency reserve.'' NERC 
Comments at 30.
---------------------------------------------------------------------------

    23. In addition, pursuant to section 215(d)(5) of the FPA, we 
direct NERC to develop modifications to Reliability Standard BAL-002-2 
to address our concerns, discussed below, regarding the 15-minute ACE 
recovery period set forth in Requirement R1. We also direct NERC to 
collect and report on data pertaining to the occurrence of Balancing 
Contingency Events that trigger resets of the 90-minute Contingency 
Reserve Restoration Period under Requirement R3. We further direct NERC 
to study and submit a report to the Commission with findings regarding 
reliability risks associated with most severe single contingency 
exceedances that do not result in energy emergencies.
    24. We discuss below the following issues raised in the NOPR and 
addressed in the comments: (A) Whether a reliability coordinator must 
expressly authorize extensions of the 15-minute ACE recovery period; 
(B) whether BAL-002-2 should be modified to require all contingency 
reserves to be restored within the 90-minute Contingency Reserve 
Restoration Period; (C) whether a reasonable obligation should be 
imposed for balancing authorities and reserve sharing groups to address 
scenarios involving megawatt losses above the most severe single 
contingency that do not cause energy emergencies; and (D) NERC's 
proposal to reduce from ``high'' to ``medium'' the violation risk 
factor for Requirements R1 and R2.

A. The 15-Minute ACE Recovery Period

NERC Petition
    25. In its petition, NERC stated that the ``exemption'' from the 
15-minute ACE recovery period in Requirement R1, Part 1.3.1 
``eliminates the existing conflict with EOP-011-1, as it removes 
undefined auditor discretion when assessing compliance and allows the 
responsible entity flexibility to maintain service to load while 
managing reliability.'' \31\ NERC explained that this exemption does 
not eliminate an entity's obligation to respond to a Reportable 
Balancing Contingency Event, but rather it will ``simply allow more 
time to return the Reporting ACE to the defined limits than would 
otherwise be allowed.'' \32\
---------------------------------------------------------------------------

    \31\ NERC Petition at 22.
    \32\ Id. at 24.
---------------------------------------------------------------------------

NOPR
    26. In the NOPR, the Commission noted that Reliability Standard 
BAL-002-2, Requirement R1 obligates a responsible entity that 
experiences a Reportable Balancing Contingency Event to return its 
Reporting ACE to pre-defined values within the 15-minute Contingency 
Event Recovery Period. Further, the Reliability Standard does not 
expressly provide a definitive and enforceable deadline for ACE 
recovery during a reliability coordinator-declared Energy Emergency 
Alert accompanied by the depletion of the entity's contingency reserves 
to below its most severe single contingency.
    27. The Commission stated that NERC's explanation for relief from 
the 15-minute ACE recovery period in Reliability Standard BAL-002-2 
raises concerns, because it is unclear how or when an entity will 
prepare for a second contingency during the indeterminate extension of 
the 15-minute ACE recovery period that Requirement R1, Part 1.3 
permits. The Commission observed that a balancing authority that is 
operating out-of-balance for an extended period of time is ``leaning on 
the system'' by relying on external resources to meet its obligations. 
That could affect other entities within an Interconnection, 
particularly if another entity is reacting to a grid event while 
unaware that the first entity has not restored its ACE.\33\ While an 
extension of the 15-minute ACE recovery period may be appropriate under 
certain emergency conditions, the NOPR explained that, with a wide-area 
view and superior information and objectivity, the reliability 
coordinator is in a better position to decide whether to extend the ACE 
recovery period after an entity has met the criteria described in 
Requirement R1, Part 1.3.1.
---------------------------------------------------------------------------

    \33\ NOPR, 155 FERC ] 61,180 at P 22.
---------------------------------------------------------------------------

    28. Further, while Reliability Standard EOP-011-1, Requirement R3, 
requires the reliability coordinator to review balancing authority 
Operating Plans and notify a balancing authority of any ``reliability 
risks'' the reliability coordinator may identify with a time frame for 
the resubmittal of revised Operating Plans, the NOPR explained that the 
Reliability Standard does not require reliability coordinator approval 
of Operating Plans.
    29. Therefore, the NOPR proposed to direct NERC to develop 
modifications to Reliability Standard BAL-002-2 that would require 
Reporting ACE recovery within the 15-minute Contingency Event Recovery 
Period unless the relevant reliability coordinator expressly authorizes 
an extension of the 15-minute ACE recovery period after the balancing 
authority has met the criteria described in Requirement R1, Part 1.3.1. 
The Commission's proposal included modifying Reliability Standard BAL-
002-2 to identify the reliability coordinator as an Applicable Entity.

[[Page 8998]]

Comments
    30. NERC, EEI, NRECA, TVA, CEA, Joint Commenters, IESO and APS 
oppose the proposed directive. NERC asserts that the proposed directive 
is unnecessary because the Balancing Authority ACE Limit (BAAL) and a 
balancing authority's resource obligations under Reliability Standard 
BAL-001-2 discourage balancing authorities from leaning on the system 
during extensions of the Contingency Event Recovery Period. NERC 
explains that the BAAL:

is a unique limit on a [balancing authority's] Reporting ACE based 
on Real-time interconnection frequency levels . . . since the loss 
of a resource would influence the Interconnection's frequency, the 
BAAL would adjust (or `tighten') to assure that the Interconnection 
frequency remains in a safe range. The [balancing authority] must 
return its operations to within the `tightened' BAAL within 30 
minutes and thus would not be able to `lean' on the Interconnection 
for any prolonged period.\34\
---------------------------------------------------------------------------

    \34\ NERC Comments at 10.

    31. Further, NERC contends that the proposed role for reliability 
coordinators is unnecessary--in both emergency and non-emergency 
situations--because the reliability coordinator ``must maintain 
constant oversight of reliability within its [reliability coordinator] 
area and direct other responsible entities to take actions necessary to 
maintain reliability.'' \35\
---------------------------------------------------------------------------

    \35\ Id. at 11 (citing Reliability Standards EOP-0011-1, EOP-
003-2, IRO-001-4, IRO-002-4, IRO-008-2, and IRO-009-2).
---------------------------------------------------------------------------

    32. EEI and Joint Commenters assert that the NOPR proposal ``would 
result in unnecessary duplication of requirements adding no tangible 
benefit to reliability while needlessly increasing the compliance 
burden.'' \36\ Joint Commenters also note the infrequent nature of 
multiple-contingency events and Energy Emergency Alerts (EEAs), 
describing them as ``exceptional circumstances appropriate for an 
exemption from the typical measured requirements.'' \37\ Joint 
Commenters state that in 2015 there were ten EEA Level 2 and Level 3 
events, and that ``most [balancing authorities] experience no EEA 
events in a given year . . . allowing recovery exceptions during these 
exceptional circumstances would not create significant risk with 
respect to ACE recovery responsibilities.'' \38\ Joint Commenters also 
contend that in a ``multiple-contingency event or during an EEA, there 
are likely scores of activities occupying the [reliability 
coordinator's] attention. Requiring the [balancing authority] and 
[reliability coordinator] to conduct a conference call during an EEA to 
discuss the merits of requests for additional ACE recovery time only 
complicates these already-challenging conditions.'' \39\
---------------------------------------------------------------------------

    \36\ EEI Comments at 7; see also Joint Commenters Comments at 2-
4.
    \37\ Joint Commenters Comments at 4.
    \38\ Id. (citing NERC's 2016 State of Reliability Report at 38).
    \39\ Id. at 3.
---------------------------------------------------------------------------

    33. While supporting the notification and involvement of 
reliability coordinators, APS shares Joint Commenters' concern that 
requiring reliability coordinators to expressly authorize extensions of 
the 15-minute ACE recovery period could distract responsible entities 
from focusing on ``maintaining and recovering the reliability of the 
[bulk electric system].'' \40\ Therefore, as an alternative to the NOPR 
proposal, APS proposes that balancing authorities obtain extensions of 
the 15-minute ACE recovery period under the extenuating circumstances 
described in Requirement R1, Part 1.3.1 by notifying the reliability 
coordinator of the conditions within its area and providing the 
reliability coordinator with an ACE recovery plan and target time 
period, but without obtaining express approval from the reliability 
coordinator.\41\
---------------------------------------------------------------------------

    \40\ APS Comments at 4-5.
    \41\ Id. at 5.
---------------------------------------------------------------------------

    34. Idaho Power and BPA support the Commission's proposal to 
expressly require reliability coordinator authorization for extensions 
of the 15-minute Reporting ACE recovery period. Idaho power agrees with 
``shifting more oversight to the Reliability Coordinator'' as the 
entity with the system-wide view.\42\
---------------------------------------------------------------------------

    \42\ Idaho Power Comments at 2; see also BPA Comments at 3.
---------------------------------------------------------------------------

Commission Determination
    35. We are persuaded by the commenters not to adopt the NOPR 
proposal that would require reliability coordinator authorization to 
extend the 15-minute ACE recovery period. As commenters explain, 
seeking the proposed reliability coordinator authorization while 
recovering from a disturbance has the potential to complicate an 
already-challenging situation. However, we continue to see a need to 
address the underlying concern expressed in the NOPR that a balancing 
authority that is operating out-of-balance for an extended period of 
time is ``leaning on the system'' by relying on external resources to 
meet its obligations. That scenario could affect other entities within 
an Interconnection, particularly if another entity is reacting to a 
grid event while unaware that the first entity has not restored its 
ACE. Accordingly, to address our concern without requiring reliability 
coordinator authorization, we adopt APS's proposed alternative that 
would require a balancing authority or reserve sharing group 
experiencing a depletion of contingency reserves below its most severe 
single contingency level during an Energy Emergency Alert to obtain an 
extension of the 15-minute ACE recovery period by informing the 
reliability coordinator of the circumstances and providing it with an 
ACE recovery plan and target time period.
    36. We are persuaded that APS's approach is reasonable and 
adequately addresses concerns with extensions of the 15-minute ACE 
recovery period. By requiring notification of reliability coordinators 
and providing the reliability coordinator with an ACE recovery plan and 
target time period, we agree that the APS proposal ``would allow 
appropriate flexibility to [balancing authorities] when extenuating 
circumstances are present while providing [reliability coordinators] 
with the necessary data, communication, and coordination to fulfill 
their oversight responsibilities to the Interconnection.'' \43\
---------------------------------------------------------------------------

    \43\ APS Comments at 8.
---------------------------------------------------------------------------

    37. Accordingly, we direct NERC to develop modifications to 
Reliability Standard BAL-002-2, Requirement R1 to require balancing 
authorities or reserve sharing groups: (1) To notify the reliability 
coordinator of the conditions set forth in Requirement R1, Part 1.3.1 
preventing it from complying with the 15-minute ACE recovery period; 
and (2) to provide the reliability coordinator with its ACE recovery 
plan, including a target recovery time. NERC may also propose an 
equally efficient and effective alternative.

B. The 90-Minute Contingency Reserve Restoration Period

NERC Petition
    38. Reliability Standard BAL-002-2, Requirement R3 requires a 
balancing authority or reserve sharing group to restore its contingency 
reserves to at least its most severe single contingency before the end 
of the 90-minute Contingency Reserve Restoration Period.\44\ 
Requirement R3 also provides for an automatic ``reset'' of the 90-

[[Page 8999]]

minute restoration period based upon any Balancing Contingency Event 
that occurs during the restoration period.\45\
---------------------------------------------------------------------------

    \44\ NERC Petition, Ex. D (Implementation Plan). The 90-minute 
contingency reserve restoration period begins after the end of the 
15-minute ACE restoration period under Requirement R1. Accordingly, 
responsible entities must restore contingency reserves within 105 
minutes of the occurrence of a Reportable Balancing Contingency 
Event to comply with Requirement R3.
    \45\ Balancing Contingency Event means: ``Any single event 
described in Subsections (A), (B), or (C) below, or any series of 
such otherwise single events, with each separated from the next by 
one minute or less.
    A. Sudden loss of generation:
    a. Due to
    i. unit tripping,
    ii. loss of generator Facility resulting in isolation of the 
generator from the Bulk Electric System or from the responsible 
entity's System, or
    iii. sudden unplanned outage of transmission Facility;
    b. And, that causes an unexpected change to the responsible 
entity's ACE;
    B. Sudden loss of an import, due to unplanned outage of 
transmission equipment that causes an unexpected imbalance between 
generation and Demand on the Interconnection.
    C. Sudden restoration of a Demand that was used as a resource 
that causes an unexpected change to the responsible entity's ACE.'' 
NERC Petition Ex. D.
---------------------------------------------------------------------------

NOPR
    39. In the NOPR, the Commission proposed to direct NERC to modify 
Reliability Standard BAL-002-2 to ``eliminate the potential for 
unlimited resets and ensure that contingency reserves must be restored 
within the 90-minute Contingency Reserve Restoration Period.'' \46\ The 
Commission sought comment on a possible alternative that would give a 
balancing authority or reserve sharing group ``credits'' for megawatt 
losses resulting from Balancing Contingency Events during the 90-minute 
restoration period, and allow an additional 90 minutes to restore 
reserves related to those megawatt losses.\47\
---------------------------------------------------------------------------

    \46\ NOPR, 155 FERC ] 61,180 at P 29.
    \47\ Id. PP 27-29.
---------------------------------------------------------------------------

Comments
    40. NERC, EEI, NRECA, CEA, Joint Commenters, IESO and APS support 
approval of Requirement R3 as filed. NERC asserts that, because of 
resource limitations and the potential compliance exposure to other 
Reliability Standards, including the Reporting ACE recovery 
requirements in Reliability Standard BAL-001-2, entities will not 
experience unlimited resets of the 90-minute restoration period.\48\ 
NERC explains that ``[i]f an entity continues to trip units before full 
recovery of other units, the responsible entity would eventually fail 
to meet obligations under other Reliability Standards (including the 
requirement to recover ACE within 15 minutes under proposed BAL-002-2) 
and may eventually enter into an Emergency situation under [reliability 
coordinator] oversight . . .'' \49\ NERC states that balancing 
authorities and reserve sharing groups would still be required to 
actively restore contingency reserves even after experiencing a 
Balancing Contingency Event during the 90-minute restoration period. 
Such events, according to NERC, ``would merely extend the Contingency 
Reserve Restoration Period to ensure that the responsible entity has 
adequate time to recover from consecutive losses.'' \50\ NERC asserts 
that the Commission's proposed credit approach ``would be confusing and 
burdensome, and it may attract attention away from full and final 
restoration of the Contingency Reserve.'' \51\ EEI agrees, adding that, 
``in light of existing standards, this concern does not pose a 
sufficient risk to system reliability to merit NERC developing 
modifications to the standard.'' \52\
---------------------------------------------------------------------------

    \48\ NERC Comments at 17-18.
    \49\ Id. at 17.
    \50\ Id. at 16.
    \51\ Id. at 18-19.
    \52\ EEI Comments at 8.
---------------------------------------------------------------------------

    41. IESO and CEA claim that modifications to Reliability Standard 
BAL-002-2, Requirement R1 to eliminate the potential for unlimited 
resets are unnecessary. IESO questions the concern about unlimited 
resets of the Contingency Reserve Restoration Period, stating that it 
``would suggest that multiple resource loss events could somehow 
benefit or unburden a [balancing authority's] obligation to restore the 
reserve level . . . [rather] the infrequent event of a reset occurrence 
is more appropriately viewed as simply not applying double jeopardy to 
a [balancing authority] that is already in a troubled situation.'' \53\ 
IESO further states that a reset of the contingency reserve restoration 
period ``will simply provide the opportunity for the involved balancing 
authority to reassess the situation and act accordingly to replenish 
the contingency reserve'' to comply with BAL-002-2.\54\ Both IESO and 
CEA assert that balancing authorities ``have a strong track record of 
acting in good faith.'' \55\ CEA also notes that ``since a [balancing 
authority] does not own any resources, it cannot trigger or otherwise 
intentionally cause an additional loss of resource during the 90-minute 
period in order to reset the recovery period.'' \56\
---------------------------------------------------------------------------

    \53\ IESO Comments at 4-5.
    \54\ Id. at 5; see also CEA Comments at 5.
    \55\ CEA Comments at 5; see also IESO Comments at 5.
    \56\ CEA Comments at 4; see also IESO Comments at 5.
---------------------------------------------------------------------------

    42. Joint Commenters also oppose the Commission's proposal, 
explaining that ``following a unit trip that results in a [Balancing 
Contingency Event], the generator's telemetry is often invalid or 
suspect for some time, and if the [balancing authority] is unable to 
accurately quantify the actual MW loss, it may be required to take 
extreme actions, including shedding firm load, simply to meet the 90-
minute contingency recovery requirement.'' \57\ Joint Commenters claim 
that the ``likelihood of such an occurrence of multiple independent 
generation losses absent a catastrophic transmission failure is also 
very low.'' \58\ Joint Commenters state that on average, one generator 
is lost in the Eastern Interconnection every 7 to 8 days, and ``the 
probability of four random large generator trips in the Eastern 
Interconnection in a two hour period was one in 350 years.'' \59\
---------------------------------------------------------------------------

    \57\ Joint Commenters Comments at 5.
    \58\ Id.
    \59\ Joint Commenters Comments at 6 (citing a probability 
analysis performed during the Reliability Standard BAL-003-1 
development process using frequency event data for January 2006 to 
September 2012).
---------------------------------------------------------------------------

    43. BPA and Idaho Power support the Commission's proposal to 
require balancing authorities to restore contingency reserves within 
the 90-minute Contingency Event Recovery Period and receive ``credits'' 
for megawatt losses during the Contingency Event Recovery Period. TVA 
believes the potential for unlimited resets of the 90-minute 
restoration period is ``extremely remote,'' but TVA supports the credit 
proposal as a ``reasonable approach'' for managing multiple events 
during a contingency restoration period.
Commission Determination
    44. The Commission determines not to adopt the NOPR proposal that 
NERC modify Reliability Standard BAL-002-2 to establish a firm 
requirement that responsible entities must restore contingency reserves 
within the 90-minute Contingency Reserve Restoration Period. Based on 
the comments, we are satisfied that occurrences of multiple Balancing 
Contingency Events during the 90-minute restoration period are rare and 
would be temporally bounded by the Reporting ACE recovery requirements 
in Reliability Standard BAL-001-2. We also acknowledge NERC's comment 
that intervening Balancing Contingency Events do not relieve balancing 
authorities and reserve sharing groups of their obligation to restore 
contingency reserves by the end of the reset period. Further, we 
acknowledge Joint Commenters' concern that determining the amount of 
megawatt losses to ``credit'' could be a distraction from the 
contingency reserve restoration effort, and the benefits from the 
proposed ``credit'' approach could be offset by unnecessary load 
shedding caused by potential confusion and

[[Page 9000]]

uncertainties associated with its implementation.
    45. While, as stated in the NOPR, under some circumstances, 
extensions of the 90-minute Contingency Reserve Restoration Period may 
be appropriate, the comments do not fully address the concern expressed 
in the NOPR with resets resulting from additional megawatt losses 
following a Reportable Balancing Contingency Event. Therefore, although 
we determine not to direct modifications to the Reliability Standard, 
we conclude that the automatic reset provision of Reliability Standard 
BAL-002-2, Requirement R3 should be monitored for potential problems.
    46. Accordingly, the Commission directs NERC to collect and report 
data pertaining to: (1) Additional megawatt losses following Reportable 
Balancing Contingency Events during the Contingency Reserve Restoration 
Period; and (2) the time periods for contingency reserve restoration 
under Requirement R3 and the number of resets of the 90-minute 
restoration period, and submit a report to the Commission two years 
following the first day of implementation of Requirement R3. After NERC 
reports on the data in a compliance filing, the Commission will 
consider what further action, if any, to take.

C. Exclusion of Megawatt Losses Above the Most Severe Single 
Contingency

NERC Petition
    47. NERC's definition of Reportable Balancing Contingency Event 
limits balancing authority and reserve sharing group responsibility to 
megawatt losses between 80 percent and 100 percent of their most severe 
single contingency that occur within a one minute interval.\60\ In its 
petition, NERC asserted that an ``integrated and coordinated'' suite of 
set of Reliability Standards (BAL-001-2, BAL-003-1, TOP-007-0, EOP-002-
3, EOP-011-1, IRO-008-2, and IRO-009-2) will address the ``complex 
issues'' resulting from exceedances of the most severe single 
contingency.\61\
---------------------------------------------------------------------------

    \60\ See NERC Petition, Ex. D (Implementation Plan) at 2.
    \61\ NERC Petition at 15.
---------------------------------------------------------------------------

NOPR
    48. In the NOPR, the Commission expressed concern about the 
exclusion of megawatt losses above a responsible entity's most severe 
single contingency from the scope of Reliability Standard BAL-002-2. 
The Commission questioned the assumption that all such megawatt losses, 
however small, warrant the proposed limitation on Reliability Standard 
BAL-002-2.\62\ Further, while recognizing the protections that the 
related set of Reliability Standards may provide in extreme 
circumstances, the Commission noted that megawatt exceedances of the 
most severe single contingency that do not cause energy emergencies or 
otherwise implicate the set of Reliability Standards cited by NERC 
could result in a reliability gap; they also could create the potential 
for balancing authorities to lean on the Interconnection by 
indefinitely relying on neighboring balancing authorities' 
resources.\63\
---------------------------------------------------------------------------

    \62\ NOPR, 155 FERC ] 61,180 at P 33.
    \63\ Id.
---------------------------------------------------------------------------

    49. In the NOPR, the Commission did not propose a specific approach 
but, rather, sought comment on how to address this possible reliability 
gap and whether to impose a reasonable obligation for balancing 
authorities and reserve sharing groups to address scenarios involving 
megawatt losses above the most severe single contingency that do not 
cause energy emergencies. The NOPR stated that, based on the comments, 
the Commission may direct that NERC develop a new or modified 
Reliability Standard to address that reliability gap.\64\
---------------------------------------------------------------------------

    \64\ Id. at 34.
---------------------------------------------------------------------------

Comments
    50. NERC, EEI, NRECA, TVA, BPA, CEA, Joint Commenters, IESO, and 
APS assert that concerns about a possible reliability gap are unfounded 
and urge the Commission to approve Reliability Standard BAL-002-2 as 
filed. NERC maintains that the limitation on the scope of Reliability 
Standard BAL-002-2 will not create a reliability gap and reasserts its 
view that an integrated, coordinated suite of Reliability Standards 
``will address important reliability issues and prohibit entities from 
being able to `lean' on the Interconnection when contingency events 
cause MW losses greater than an entity's MSSC.'' \65\ NERC states that 
in situations involving megawatt losses above the most severe single 
contingency, reliability issues associated with ACE recovery and 
contingency reserve restoration become less important and other 
reliability issues ``such as transmission line-loading issues or 
frequency deviations'' create more immediate reliability threats and 
warrant priority status.\66\
---------------------------------------------------------------------------

    \65\ NERC Comments at 20 (citing Reliability Standards BAL-001-
2, BAL-003-1, EOP-002-3, EOP-011-1, IRO-001-4, TOP-001-3, IRO-008-2, 
and IRO-009-2).
    \66\ Id.
---------------------------------------------------------------------------

    51. EEI agrees with NERC, and also notes that exceedances of the 
most severe single contingency that do not create energy emergencies 
generally raise commercial, not reliability, issues. Further, EEI 
asserts that tightening Reliability Standard BAL-002-2 by requiring 
balancing authorities to address megawatt losses above the most severe 
single contingency ``could have unintended consequences that limit the 
flexibility of the [reliability coordinators] and [balancing 
authorities] to work together under the existing suite of standards to 
address such complex situations . . .'' \67\
---------------------------------------------------------------------------

    \67\ EEI Comments at 11-12.
---------------------------------------------------------------------------

    52. Joint Commenters consider requiring balancing authorities and 
reserve sharing groups to address megawatt losses above the most severe 
single contingency as tantamount to requiring entities to operate to 
``N-2'' or greater conditions. Joint Commenters assert that this would 
not only be expensive, estimating that doubling current contingency 
reserves across North America could cost $150-200 million/year based on 
average monthly cost of spinning reserves, it could adversely impact 
reliability. Joint Commenters state that N-2 events typically result 
from severe transmission events involving weather, major equipment or 
protection system failures. According to Joint Commenters, ``[i]n these 
situations, transmission security takes priority over maintaining ACE 
to zero. Excessive generation dispatch by [balancing authorities] could 
interfere with actions taken simultaneously by Transmission Operators 
and remote [balancing authorities] to resolve problems on the 
transmission system.'' \68\
---------------------------------------------------------------------------

    \68\ Joint Commenters Comments at 9.
---------------------------------------------------------------------------

    53. Joint Commenters explain that the available data reflecting 
experience with megawatt losses subject to currently-effective 
Reliability Standard BAL-002-1 indicates that concerns about a 
reliability gap are overstated. According to Joint Commenters, of the 
95 events involving most severe single contingency exceedances from 
2012 to 2015, 91 were recovered in less than 15 minutes, and there were 
no Interconnected Reliability Operating Limit (IROL) exceedances of 
over 30 minutes in 2015, ``which demonstrates that the grid was secure 
even while zero ACE was not achieved within 15 minutes.'' \69\
---------------------------------------------------------------------------

    \69\ Id. at 8 (citing NERC's 2016 State of Reliability Report).
---------------------------------------------------------------------------

    54. CEA and IESO also oppose requiring balancing authorities or 
reserve sharing groups to address

[[Page 9001]]

megawatt losses exceeding the most severe single contingency, which 
they describe as an ``open-ended requirement.'' \70\ CEA explains that 
it ``can severely affect a [balancing authority's] ability to suitably 
plan for potential contingency events. At an increased cost and at the 
expense of reduced market efficiency (more capacity is put aside for 
reserve as opposed to bidding into the energy market), a [balancing 
authority] could, in theory, design and operate to N-2, N-3 or greater 
events. However, this is simply not feasible.'' \71\
---------------------------------------------------------------------------

    \70\ CEA Comments at 5; IESO Comments at 7.
    \71\ CEA Comments at 5-6.
---------------------------------------------------------------------------

Commission Determination
    55. The Commission remains concerned with relying on a 
``coordinated suite of standards,'' as NERC maintains, to address 
reliability issues associated with megawatt losses above the most 
severe single contingency, considering that these other Reliability 
Standards do not specifically address restoration of ACE and 
Contingency Reserves. Further, the requirements for emergency Operating 
Plans in Reliability Standard EOP-011-1 do not specify any obligation 
for a balancing authority, transmission system operator, and/or 
reliability coordinator to take action to return ACE to zero for all 
operating conditions.
    56. Additionally, Reliability Standards TOP-001-3, EOP-003-2, IRO-
008-2, and IRO-009-2 pertain to actions needed to prevent or mitigate 
SOLs/IROLs caused by transmission line loading and other 
responsibilities of the transmission system operator and reliability 
coordinator. These Reliability Standards do not specifically address 
the balancing authority's responsibility to recover ACE by balancing 
load and generation, the purpose of Reliability Standard BAL-002-2.
    57. The Commission finds the arguments and historical data provided 
by commenters to be helpful regarding whether there is a need to expand 
the requirements of Reliability Standard BAL-002-2 to address most 
severe single contingency exceedances that do not cause energy 
emergencies, as contemplated in the NOPR. Nonetheless, we believe the 
comments do not fully resolve open questions regarding the potential 
reliability impact of suspending the focus on the balancing of demand 
and load and ACE recovery--the purpose of Reliability Standard BAL-002-
2--in exceedance scenarios.
    58. The Commission determines that it is important to better 
understand the potential impacts of the approach taken in Reliability 
Standard BAL-002-2 when megawatt losses exceed the most severe single 
contingency without causing an energy emergency. Accordingly, we direct 
NERC to study the reliability risks associated with most severe single 
contingency exceedances that do not cause energy emergencies and submit 
a report with findings to the Commission two years from Reliability 
Standard BAL-002-2 implementation.

D. Violation Risk Factor for Requirements R1 and R2

NERC Petition
    59. NERC proposed a ``medium'' violation risk factor for each 
requirement of Reliability Standard BAL-002-2.
NOPR
    60. In the NOPR, the Commission expressed concern that NERC did not 
adequately justify lowering the assignment of the violation risk factor 
for Requirements R1 and R2 and proposed to direct that NERC assign a 
``high'' violation risk factor to Reliability Standard BAL-002-2, 
Requirements R1 and R2.
    61. Requirement R1 requires a balancing authority or reserve 
sharing group to deploy contingency reserves in response to all 
Reportable Balancing Contingency Events as the means for recovering 
Reporting ACE. Requirement R2 requires a balancing authority or reserve 
sharing group to develop, review and maintain a process within its 
Operating Plans for determining its most severe single contingency and 
to prepare to have contingency reserves equal to, or greater than, its 
most severe single contingency. Currently-effective Reliability 
Standard BAL-002-1 assigns a ``high'' violation risk factor for its 
Requirements R3 and R3.1, which NERC explained are analogous to 
proposed Requirements R1 and R2 in Reliability Standard BAL-002-2.\72\
---------------------------------------------------------------------------

    \72\ NERC Petition, Ex. I (Mapping Document for BAL-002-2).
---------------------------------------------------------------------------

    62. In the NOPR, the Commission stated that NERC provided 
insufficient support for the proposed violation risk factor for 
Requirements R1 and R2. In justifying the assignment of a ``medium'' 
violation risk factor NERC asserted, without explanation, that a 
``medium'' violation risk factor is ``consistent with other reliability 
standards (i.e., BAL-001-2, BAL-003-1).'' \73\ NERC also contended, 
without explanation, that Requirement R3 is similar in concept to the 
current enforceable BAL-001-0.1a standard Requirements R1 and R2, which 
have an approved medium violation risk factor, and approved reliability 
standards BAL-001-1 and BAL-003-1.\74\ The conclusory statements in 
NERC's petition regarding the alleged similarities between Requirements 
R1 and R2 and other Reliability Standards, the NOPR stated, do not 
adequately explain the alleged bases for reducing the violation risk 
factor for Requirements R1 and R2 from the analogous Requirement R3 in 
the currently-effective Reliability Standard.
---------------------------------------------------------------------------

    \73\ NERC Petition, Ex. G (Analysis of Violation Risk Factors 
and Violation Severity Levels) at 4.
    \74\ Id.
---------------------------------------------------------------------------

Comments
    63. NERC, EEI and APS oppose raising the violation risk factor for 
Reliability Standard BAL-002-2 to ``high'' as proposed in the NOPR. 
NERC asserts that a failure to perform Requirements R1 and R2 ``in real 
time would produce results consistent with the Commission approved 
guidelines for a `Medium' [violation risk factor] VRF . . . [that is] 
unlikely to lead to Bulk Electric System instability, separation, or 
cascading failures.'' \75\ With regard to Requirement R1, NERC states 
that Reporting ACE ``is not an immediate measure of reliability, and 
the risk resulting from failure to meet Requirement R1'' is not likely 
to lead to instability, separation or cascading failures, the criteria 
for a high violation risk factor.\76\ Likewise, NERC asserts that a 
``medium'' violation risk factor is appropriate for Requirement R2, 
because the process responsible entities use for developing and 
reviewing their most severe single contingency ``does not directly 
contribute to reliability.'' \77\ EEI agrees, adding that it ``also 
believes the medium VRF is justified because in most instances ACE is 
more reflective of commercial issues, particularly if frequency remains 
normal.'' \78\
---------------------------------------------------------------------------

    \75\ NERC Comments at 28.
    \76\ Id. at 29.
    \77\ Id. at 30.
    \78\ EEI at 13.
---------------------------------------------------------------------------

    64. APS also disagrees with the NOPR proposal because the 
Commission ``utilizes previous versions of reliability standards as a 
benchmark for the acceptability of VRFs [violation risk factors].'' 
\79\ APS states that it is ``concerned that the assignment of a VRF 
based solely on the previous VRF assignments may contravene the current 
NERC Rules of Procedure and associated processes.'' \80\ APS recommends 
that the Commission direct NERC to reevaluate

[[Page 9002]]

the VRFs for Reliability Standard BAL-002-2 ``against existing 
guidance.'' \81\
---------------------------------------------------------------------------

    \79\ APS Comments at 11.
    \80\ Id.
    \81\ Id.
---------------------------------------------------------------------------

Commission Determination
    65. We adopt the NOPR proposal regarding the violation risk factor 
for Reliability Standard BAL-002-2, Requirements R1 and R2. According 
to the Commission-approved criteria, a ``high'' violation risk factor 
should be assigned to a Reliability Standard requirement if violating 
the requirement could ``directly cause or contribute to the Bulk 
Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable 
risk of instability, separation or cascading failures.'' Reliability 
Standard BAL-002-2, Requirement R1 requires responsible entities to 
recover Reporting ACE following the occurrence of a Reportable 
Balancing Contingency Event, which supports Interconnection frequency 
in real-time.
    66. We disagree with NERC that significant real-time differences 
between actual and scheduled interchange, the imbalance that 
Requirement R1 is intended to address, do not fall within the scope of 
the criterion for a ``high'' violation risk factor. The need for the 
bulk electric system to stabilize after changes in system frequency is 
critical for real-time system operations. NERC asserts that the status 
of Reporting ACE ``is not indicative of an immediate vulnerability.'' 
\82\ We disagree. A violation of Requirement R1 jeopardizes system 
frequency, because it places the bulk electric system in a weakened 
operating condition with heightened risks of instability, separation, 
or cascading failures that could result from a second contingency.
---------------------------------------------------------------------------

    \82\ NERC Comments at 29.
---------------------------------------------------------------------------

    67. With regard to Requirement R2, NERC acknowledges that actions 
under Requirement R2 ``support Requirement R1 by requiring responsible 
entities to develop, review, and maintain a process to determine the 
MSSC and to maintain, for deployment under Requirement R1, at least 
enough Contingency Reserve to cover the MSSC . . . [Requirement R2] is 
critical to the implementation of proposed Reliability Standard BAL-
002-2.'' \83\ Nonetheless, NERC asserts that Requirement R2 ``does not 
directly contribute to reliability.'' \84\ We disagree, and conclude 
that the fundamental connection between Requirements R1 and R2 creates 
a significant role in maintaining reliability.
---------------------------------------------------------------------------

    \83\ Id. at 29.
    \84\ Id. at 30.
---------------------------------------------------------------------------

    68. Accordingly, we direct NERC to assign a ``high'' violation risk 
factor to Reliability Standard BAL-002-2, Requirements R1 and R2.

V. Information Collection Statement

    69. The Office of Management and Budget (OMB) regulations require 
that OMB approve certain reporting and recordkeeping (collections of 
information) imposed by an agency.\85\ Upon approval of a collection(s) 
of information, OMB will assign an OMB control number and expiration 
date. Respondents subject to the filing requirements of this rule will 
not be penalized for failing to respond to these collections of 
information unless the collections of information display a valid OMB 
control number.
---------------------------------------------------------------------------

    \85\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    70. The Commission is submitting these reporting and recordkeeping 
requirements to OMB for its review and approval under section 3507(d) 
of the Paperwork Reduction Act of 1995, 44 U.S.C. 3507(d) (2012). The 
NOPR solicited comments on the Commission's need for this information, 
whether the information will have practical utility, the accuracy of 
the provided burden estimate, ways to enhance the quality, utility, and 
clarity of the information to be collected, and any suggested methods 
for minimizing the respondent's burden, including the use of automated 
information techniques. No comments were received.
    71. This final rule approves revisions to Reliability Standard BAL-
002-1. NERC states in its petition that the Reliability Standard 
applies to balancing authorities and reserve sharing groups, and is 
designed to ensure that these entities are able to recover from system 
contingencies by deploying adequate reserves to return their ACE to 
defined values and by replacing the capacity and energy lost due to 
generation or transmission equipment outages. The Commission also 
approves NERC's seven new definitions and one proposed revised 
definition, and the retirement of currently-effective Reliability 
Standard BAL-002-1 immediately prior to the effective date of BAL-002-
2.
    72. Public Reporting Burden: Our estimate below regarding the 
number of respondents is based on the NERC Compliance Registry as of 
April 15, 2016. According to the NERC Compliance Registry, there are 70 
balancing authorities in the Eastern Interconnection, 34 balancing 
authorities in the Western Interconnection and one balancing authority 
in the Electric Reliability Council of Texas (ERCOT). The Commission 
bases individual burden estimates on the time needed for balancing 
authorities and reserve sharing groups to maintain, annually, the 
operating process and operating plan that are required in the 
Reliability Standard. These burden estimates are consistent with 
estimates for similar tasks in other Commission-approved Reliability 
Standards. The following estimates relate to the requirements for this 
final rule in Docket No. RM16-7-000.
---------------------------------------------------------------------------

    \86\ Reliability Standard BAL-002-2 applies to balancing 
authorities and reserve sharing groups. However, the burden 
associated with the balancing authorities complying with 
Requirements R1and R3 is not included within this table because the 
Commission accounted for it under Commission-approved Reliability 
Standard BAL-002-1.
    \87\ The estimated hourly cost (salary plus benefits) of $96.71 
is an average based on Bureau of Labor Statistics (BLS) information 
(http://www.bls.gov/oes/current/naics2_22.htm) for an electrical 
engineer ($64.29/hour) and a lawyer ($129.12).
    \88\ BA = Balancing Authority; RSG = Reserve Sharing Group.

                                                                       RM16-7-000
                   [BAL-002-2: Disturbance Control Standard--Contingency Reserve for recovery from a Balancing Contingency Event] \86\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Annual  number                      Average      Total annual
                                                                 Number of     of  responses   Total number    burden hours    burden hours    Cost per
                                                                respondents         per        of responses    and cost per      and total    respondent
                                                                                respondent                     response \87\    annual cost       ($)
                                                                         (1)             (2)   (1)*(2) = (3)             (4)   (3)*(4) = (5)     (5)/(1)
                                                             -------------------------------------------------------------------------------------------
BA/RSG: \88\ Develop and Maintain annually, Operating                    105               1             105               8             840        $774
 Process and Operating Plans................................                                                            $774         $81,262

[[Page 9003]]

 
BA/RSG: Record Retention \89\...............................             105               1             105               4             420         112
                                                                                                                        $112         $11,760
                                                             -------------------------------------------------------------------------------------------
    Total...................................................  ..............  ..............             210  ..............           1,260         886
                                                                                                                                     $93,022
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Title: FERC-725R, Mandatory Reliability Standard BAL-002-2.
---------------------------------------------------------------------------

    \89\ $28/hour, based on a Commission staff study of record 
retention burden cost.
---------------------------------------------------------------------------

    Action: Collection of Information.
    OMB Control No.: 1902-0268.
    Respondents: Businesses or other for-profit institutions; not-for-
profit institutions.
    Frequency of Responses: On Occasion.
    Necessity of the Information: This final rule approves Reliability 
Standard BAL-002-2, which is designed to ensure that a responsible 
entity, either a balancing authority or reserve sharing group, is able 
to recover from system contingencies by deploying adequate reserves to 
return its ACE to defined values and replacing the capacity and energy 
lost due to generation or transmission equipment outages. Reliability 
Standard BAL-002-2, Requirement R1 requires a responsible entity, 
either a balancing authority or reserve sharing group, experiencing a 
Reportable Balancing Contingency Event to deploy its contingency 
reserves to recover its ACE to certain prescribed values within the 
Contingency Event Recovery Period of 15 minutes. Requirement R2 
requires a balancing authority or reserve sharing group to develop, 
review and maintain a process within its Operating Plans for 
determining its most severe single contingency and prepare to have 
contingency reserves equal to, or greater than, its most severe single 
contingency. Requirement R3 provides that, following a Reportable 
Balancing Contingency Event, the responsible entity shall restore its 
Contingency Reserve to at least its most severe single contingency, 
before the end of the Contingency Reserve Restoration Period of 90 
minutes.
    Internal Review: The Commission reviewed the Reliability Standard 
and has determined that it is necessary to implement section 215 of the 
FPA. The requirements of Reliability Standard BAL-002-2 should conform 
to the Commission's expectation for generation and demand balance 
throughout the Eastern and Western Interconnections as well as within 
the ERCOT Region.
    73. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director, email: 
DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].

VI. Environmental Analysis

    74. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\90\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment. Included in the exclusion are rules that are clarifying, 
corrective, or procedural or that do not substantially change the 
effect of the regulations being amended.\91\ The actions proposed here 
fall within this categorical exclusion in the Commission's regulations.
---------------------------------------------------------------------------

    \90\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \91\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    75. The Regulatory Flexibility Act of 1980 (RFA) \92\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small entities. 
As shown in the information collection section, the Reliability 
Standard applies to 105 entities. Comparison of the applicable entities 
with the Commission's small business data indicates that approximately 
23 \93\ are small business entities.\94\ Of these, the Commission 
estimates that approximately five percent, or one of these 23 small 
entities, will be affected by the new requirements of the Reliability 
Standard.
---------------------------------------------------------------------------

    \92\ 5 U.S.C. 601-612.
    \93\ 21.73 percent of the total number of affected entities.
    \94\ The Small Business Administration sets the threshold for 
what constitutes a small business. Public utilities may fall under 
one of several different categories, each with a size threshold 
based on the company's number of employees, including affiliates, 
the parent company, and subsidiaries. For the analysis in this final 
rule, we are using a 500 employee threshold for each affected 
entity. Each entity is classified as Electric Bulk Power 
Transmission and Control (NAICS code 221121).
---------------------------------------------------------------------------

    76. The Commission estimates that the small entities affected by 
Reliability Standard BAL-002-2 will incur an annual compliance cost of 
up to $20,355 (i.e., the cost of developing, and maintaining annually 
operating process and operating plans), resulting in a cost of 
approximately $885 per balancing authority and/or reserve sharing 
group. These costs represent an estimate of the costs a small entity 
could incur if the entity is identified as an applicable entity. The 
Commission does not consider the estimated cost per small entity to 
have a significant economic impact on a substantial number of small 
entities. Accordingly, the Commission certifies that this final rule 
will not have a significant economic impact on a substantial number of 
small entities.

VIII. Document Availability

    77. In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    78. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of

[[Page 9004]]

this document is available on eLibrary in PDF and Microsoft Word format 
for viewing, printing, and/or downloading. To access this document in 
eLibrary, type the docket number of this document, excluding the last 
three digits, in the docket number field.
    79. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

IX. Effective Date and Congressional Notification

    80. These regulations are effective April 3, 2017. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

    By the Commission.

    Issued: January 19, 2017.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    Note:  The following appendix will not appear in the Code of 
Federal Regulations.

Appendix--Commenters

------------------------------------------------------------------------
         Abbreviation                          Commenter
------------------------------------------------------------------------
APS..........................  Arizona Public Service Company.
BPA..........................  Bonneville Power Administration.
CEA..........................  Canadian Electricity Association.
EEI..........................  Edison Electric Institute.
Idaho Power..................  Idaho Power.
IESO.........................  Independent Electricity System Operator.
Joint Commenters.............  Alberta Electric System Operator,
                                California Independent System Operator,
                                Electric Reliability Council of Texas,
                                Inc., Midcontinent Independent System
                                Operator, Inc., PJM Interconnection,
                                L.L.C., Southwest Power Pool, Inc., and
                                IESO.
Naturener....................  Naturener USA, LLC.
NERC.........................  North American Electric Reliability
                                Corporation.
NRECA........................  National Rural Electric Cooperative
                                Association.
TVA..........................  Tennessee Valley Authority.
------------------------------------------------------------------------

[FR Doc. 2017-02175 Filed 2-1-17; 8:45 am]
BILLING CODE 6717-01-P