80 FR 73977 - Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission Federal Register Volume 80, Issue 228 (November 27, 2015)
Federal Energy Regulatory Commission
Federal Register Volume 80, Issue 228 (November 27, 2015)
| Page Range | 73977-73991 | |
| FR Document | 2015-30110 |
[Federal Register Volume 80, Number 228 (Friday, November 27, 2015)] [Rules and Regulations] [Pages 73977-73991] From the Federal Register Online [www.thefederalregister.org] [FR Doc No: 2015-30110] ----------------------------------------------------------------------- DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 40 [Docket No. RM15-16-000, Order No. 817] Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards AGENCY: Federal Energy Regulatory Commission, Energy. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: The Commission approves revisions to the Transmission Operations and Interconnection Reliability Operations and Coordination Reliability Standards, developed by the North American Electric Reliability Corporation, which the Commission has certified as the Electric Reliability Organization responsible for developing and enforcing mandatory Reliability Standards. The Commission also directs NERC to make three modifications to the standards within 18 months of the effective date of the final rule. DATES: This rule will become effective January 26, 2016. FOR FURTHER INFORMATION CONTACT: Robert T. Stroh (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC [[Page 73978]] 20426, Telephone: (202) 502-8473, Robert.Stroh@ferc.gov. Eugene Blick (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (301) 665-1759, Eugene.Blick@ferc.gov. Darrell G. Piatt, PE (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (205) 332-3792, Darrell.Piatt@ferc.gov. SUPPLEMENTARY INFORMATION: Order No. 817 Final Rule (Issued November 19, 2015) 1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the Commission approves revisions to the Transmission Operations (TOP) and Interconnection Reliability Operations and Coordination (IRO) Reliability Standards, developed by the North American Electric Reliability Corporation (NERC), the Commission-certified Electric Reliability Organization (ERO). The TOP and IRO Reliability Standards improve on the currently-effective standards by providing a more precise set of Reliability Standards addressing operating responsibilities and improving the delineation of responsibilities between applicable entities. The revised TOP Reliability Standards eliminate gaps and ambiguities in the currently-effective TOP requirements and improve efficiency by incorporating the necessary requirements from the eight currently-effective TOP Reliability Standards into three comprehensive Reliability Standards. Further, the standards clarify and improve upon the currently-effective TOP and IRO Reliability Standards by designating requirements in the proposed standards that apply to transmission operators for the TOP standards and reliability coordinators for the IRO standards. Thus, we conclude that there are benefits to clarifying and bringing efficiencies to the TOP and IRO Reliability Standards, consistent with the Commission's policy promoting increased efficiencies in Reliability Standards and reducing requirements that are either redundant with other currently- effective requirements or have little reliability benefit.\2\ --------------------------------------------------------------------------- \1\ 16 U.S.C. 824o (2012). \2\ Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, Order No. 788, 145 FERC ] 61,147 (2013). --------------------------------------------------------------------------- 2. The Commission also finds that NERC has adequately addressed the concerns raised by the Commission in the Notice of Proposed Rulemaking issued in November 2013 concerning the proposed treatment of system operating limits (SOLs) and interconnection reliability operating limits (IROLs) and concerns about outage coordination.\3\ Further, the Commission approves the definitions for operational planning analysis and real-time assessment, the implementation plans and the violation severity level and violation risk factor assignments. However, the Commission directs NERC to make three modifications to the standards as discussed below within 18 months of the effective date of this Final Rule. --------------------------------------------------------------------------- \3\ Monitoring System Conditions--Transmission Operations Reliability Standard, Transmission Operations Reliability Standards, Interconnection Reliability Operations and Coordination Reliability Standards, Notice of Proposed Rulemaking, 145 FERC ] 61,158 (2013) (Remand NOPR). Concurrent with filing the proposed TOP/IRO standards in the immediate proceeding, NERC submitted a motion to withdraw the earlier petition that was the subject of the Remand NOPR. No protests to the motion were filed and the petition was withdrawn pursuant to 18 CFR 385.216(b). --------------------------------------------------------------------------- 3. We also address below the four issues for which we sought clarifying comments in the June 18, 2015, Notice of Proposed Rulemaking (NOPR) proposing to approve the TOP and IRO Reliability Standards: (A) Possible inconsistencies in identifying IROLs; (B) monitoring of non- bulk electric system facilities; (C) removal of the load-serving entity as an applicable entity for proposed Reliability Standard TOP-001-3; and (D) data exchange capabilities. In addition we address other issues raised by commenters. I. Background A. Regulatory Background 4. Section 215 of the FPA requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards, subject to Commission review and approval.\4\ Once approved, the Reliability Standards may be enforced by the ERO subject to Commission oversight, or by the Commission independently.\5\ In 2006, the Commission certified NERC as the ERO pursuant to FPA section 215.\6\ --------------------------------------------------------------------------- \4\ 16 U.S.C. 824o(c) and (d). \5\ See id. 16 U.S.C. 824o(e). \6\ 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). --------------------------------------------------------------------------- 5. The Commission approved the initial TOP and IRO Reliability Standards in Order No. 693.\7\ On April 16, 2013, in Docket No. RM13- 14-000, NERC submitted for Commission approval three revised TOP Reliability Standards to replace the eight currently-effective TOP standards.\8\ Additionally, on April 16, 2013, in Docket No. RM13-15- 000, NERC submitted for Commission approval four revised IRO Reliability Standards to replace six currently-effective IRO Reliability Standards. On November 21, 2013, the Commission issued the Remand NOPR in which the Commission expressed concern that NERC had ``removed critical reliability aspects that are included in the currently-effective standards without adequately addressing these aspects in the proposed standards.'' \9\ The Commission identified two main concerns and asked for clarification and comment on a number of other issues. Among other things, the Commission expressed concern that the proposed TOP Reliability Standards did not require transmission operators to plan and operate within all SOLs, which is a requirement in the currently-effective standards. In addition, the Commission expressed concern that the proposed IRO Reliability Standards did not require outage coordination. --------------------------------------------------------------------------- \7\ See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ] 31,242, at P 508, order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007). In addition, in Order No. 748, the Commission approved revisions to the IRO Reliability Standards. Mandatory Reliability Standards for Interconnection Reliability Operating Limits, Order No. 748, 134 FERC ] 61,213 (2011). \8\ On April 5, 2013, in Docket No. RM13-12-000, NERC proposed revisions to Reliability Standard TOP-006-3 to clarify that transmission operators are responsible for monitoring and reporting available transmission resources and that balancing authorities are responsible for monitoring and reporting available generation resources. \9\ Remand NOPR, 145 FERC ] 61,158 at P 4. --------------------------------------------------------------------------- B. NERC Petition 6. On March 18, 2015, NERC filed a petition with the Commission for approval of the proposed TOP and IRO Reliability Standards.\10\ As explained in the Petition, the proposed Reliability Standards consolidate many of the currently-effective TOP and IRO Reliability Standards and also replace the TOP and IRO Reliability Standards that were the subject of the Remand NOPR. NERC stated that the proposed Reliability Standards include [[Page 73979]] improvements over the currently-effective TOP and IRO Reliability Standards in (1) operating within SOLs and IROLs; (2) outage coordination; (3) situational awareness; (4) improved clarity and content in foundational definitions; and (5) requirements for operational reliability data. NERC stated that the proposed TOP and IRO Reliability Standards address outstanding Commission directives relevant to the proposed TOP and IRO Reliability Standards. NERC stated that the proposed Reliability Standards provide a comprehensive framework for reliable operations, with important improvements to ensure the bulk electric system is operated within pre-established limits while enhancing situational awareness and strengthening operations planning. NERC explained that the proposed Reliability Standards establish or revise requirements for operations planning, system monitoring, real-time actions, coordination between applicable entities, and operational reliability data. NERC contended that the proposed Reliability Standards help to ensure that reliability coordinators and transmission operators work together, and with other functional entities, to operate the bulk electric system within SOLs and IROLs.\11\ NERC also provided explanations of how the proposed Reliability Standards address the reliability issues identified in the report on the Arizona-Southern California Outages on September 8, 2011, Causes and Recommendations (``2011 Southwest Outage Blackout Report''). --------------------------------------------------------------------------- \10\ The TOP and IRO Reliability Standards are not attached to the Final Rule. The complete text of the Reliability Standards is available on the Commission's eLibrary document retrieval system in Docket No. RM15-16 and is posted on the ERO's Web site, available at: http://www.nerc.com. \11\ The NERC Glossary of Terms defines IROL as ``[a] System Operating Limit that, if violated, could lead to instability, uncontrolled separation, or Cascading outages that adversely impact the reliability of the Bulk Electric System.'' In turn, NERC defines SOL as ``[t]he value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria. . . .'' --------------------------------------------------------------------------- 7. NERC proposed three TOP Reliability Standards to replace the existing suite of TOP standards. The proposed TOP Reliability Standards generally address real-time operations and planning for next-day operations, and apply primarily to the responsibilities and authorities of transmission operators, with certain requirements applying to the roles and responsibilities of the balancing authority. Among other things, NERC stated that the proposed revisions to the TOP Reliability Standards help ensure that transmission operators plan and operate within all SOLs. The proposed IRO Reliability Standards, which complement the proposed TOP Standards, are designed to ensure that the bulk electric system is planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions. The proposed IRO Reliability Standards set forth the responsibility and authority of reliability coordinators to provide for reliable operations. NERC stated that, in the proposed IRO Reliability Standards, reliability coordinators must continue to monitor SOLs in addition to their obligation in the currently effective Reliability Standards to monitor and analyze IROLs. These obligations require reliability coordinators to have the wide-area view necessary for situational awareness and provide them the ability to respond to system conditions that have the potential to negatively affect reliable operations. 8. NERC also proposed revised definitions for ``operational planning analysis'' and ``real-time assessment.'' For all standards except proposed Reliability Standards TOP-003-3 and IRO-010-2, NERC proposed the effective date to be the first day of the first calendar quarter twelve months after Commission approval. According to NERC's implementation plan, for proposed TOP-003-3, all requirements except Requirement R5 will become effective on the first day of the first calendar quarter nine months after the date that the standard is approved. For proposed IRO-010-2, Requirements R1 and R2 would become effective on the first day of the first calendar quarter that is nine months after the date that the standard is approved. Proposed TOP-003- 3, Requirement R5 and IRO-010-2, Requirement R3 would become effective on the first day of the first calendar quarter twelve months after the date that the standard is approved. The reason for the difference in effective dates for proposed TOP-003-3 and IRO-010-2 is to allow applicable entities to have time to properly respond to the data specification requests from their reliability coordinators, transmission operators, and/or balancing authorities. C. Notice of Proposed Rulemaking 9. On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking proposing to approve the TOP and IRO Reliability Standards pursuant to FPA section 215(d)(2), along with the two new definitions referenced in the proposed standards, the assigned violation risk factors and violation severity levels, and the proposed implementation plan for each standard.\12\ --------------------------------------------------------------------------- \12\ Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards, 151 FERC ] 61,236 (2015) (NOPR). --------------------------------------------------------------------------- 10. In the NOPR, the Commission explained that the proposed TOP and IRO Reliability Standards improve on the currently-effective standards by providing a more precise set of Reliability Standards addressing operating responsibilities and improving the delineation of responsibilities between applicable entities. The Commission also proposed to find that NERC has adequately addressed the concerns raised by the Remand NOPR issued in November 2013. 11. In the NOPR, the Commission also discussed the following specific matters and asked for further comment: (A) Possible inconsistencies in identifying IROLs; (B) monitoring of non-bulk electric system facilities; (C) removal of the load-serving entity as an applicable entity for proposed Reliability Standard TOP-001-3; and (D) data exchange capabilities. 12. Timely comments on the NOPR were filed by: NERC; Arizona Public Service Company (APS), Bonneville Power Administration (BPA), Dominion Resources Services, Inc. (Dominion), the Edison Electric Institute (EEI); Electric Reliability Council of Texas, Inc. (ERCOT), Independent Electricity System Operator (IESO), ISO/RTOs,\13\ International Transmission Company (ITC); Midcontinent Independent System Operator, Inc., Northern Indiana Public Service Company (NIPSCO), Occidental Energy Ventures, LLC (Occidental), Peak Reliability (Peak), and Transmission Access Policy Study Group (TAPS). --------------------------------------------------------------------------- \13\ ISO/RTOs include Independent Electricity System Operator, ISO New England Inc., Midcontinent Independent System Operator, New York Independent System Operator, Inc., PJM Interconnection LLC, and Southwest Power Pool, Inc. --------------------------------------------------------------------------- II. Discussion 13. Pursuant to section 215(d) of the FPA, we adopt our NOPR proposal and approve NERC's revisions to the TOP and IRO Reliability Standards, including the associated definitions, violation risk factors, violation severity levels, and implementation plans, as just, reasonable, not unduly discriminatory or preferential and in the public interest. We note that all of the commenters that address the matter support, or do not oppose, approval of the revised suite of TOP and IRO Reliability Standards. We determine that NERC's approach of consolidating requirements and removing redundancies generally has merit and is consistent with Commission policy [[Page 73980]] promoting increased efficiencies in Reliability Standards and reducing requirements that are either redundant with other currently-effective requirements or have little reliability benefit.\14\ --------------------------------------------------------------------------- \14\ See Order No. 788, 145 FERC ] 61,147. --------------------------------------------------------------------------- 14. We also determine that the proposed TOP and IRO Reliability Standards should improve reliability by defining an appropriate division of responsibilities between reliability coordinators and transmission operators.\15\ The proposed TOP Reliability Standards will eliminate multiple TOP standards, resulting in a more concise set of standards, reducing redundancy and more clearly delineating responsibilities between applicable entities. In addition, we find that the proposed Reliability Standards provide a comprehensive framework as well as important improvements to ensure that the bulk electric system is operated within pre-established limits while enhancing situational awareness and strengthening operations planning. The TOP and IRO Reliability Standards address the coordinated efforts to plan and reliably operate the bulk electric system under both normal and abnormal conditions. --------------------------------------------------------------------------- \15\ See, e.g., Order No. 748, 134 FERC ] 61,213, at PP 39-40. --------------------------------------------------------------------------- 15. In the NOPR, the Commission proposed to find that NERC adequately addressed the concerns raised by the Commission in the Remand NOPR with respect to (1) the treatment of SOLs in the proposed TOP Reliability Standards, and (2) the IRO standards regarding planned outage coordination, both of which we address below. Operational Responsibilities and Actions of SOLs and IROLs 16. In the Remand NOPR, the Commission expressed concern that the initially proposed (now withdrawn) TOP standards did not have a requirement for transmission operators to plan and operate within all SOLs. The Commission finds that the TOP Reliability Standards that NERC subsequently proposed address the Commission's Remand NOPR concerns by requiring transmission operators to plan and operate within all SOLs, and to monitor and assess SOL conditions within and outside a transmission operator's area. Further, the TOP/IRO Standards approved herein address the possibility that additional SOLs could develop or occur in the same-day or real-time operational time horizon and, therefore, would pose an operational risk to the interconnected transmission network if not addressed. Likewise, the Reliability Standards give reliability coordinators the authority to direct actions to prevent or mitigate instances of exceeding IROLs because the primary decision-making authority for mitigating IROL exceedances is assigned to reliability coordinators while transmission operators have the primary responsibility for mitigating SOL exceedances.\16\ --------------------------------------------------------------------------- \16\ See Remand NOPR, 145 FERC ] 61,158 at P 85. Further, currently-effective Reliability Standard IRO-009-1, Requirement R4 states that ``[w]hen actual system conditions show that there is an instance of exceeding an IROL in its Reliability Coordinator Area, the Reliability Coordinator shall, without delay, act or direct others to act to mitigate the magnitude and duration of the instance of exceeding that IROL within the IROL's Tv.'' --------------------------------------------------------------------------- 17. Furthermore, the revised definitions of operational planning analysis and real-time assessment are critical components of the proposed TOP and IRO Reliability Standards and, together with the definitions of SOLs, IROLs and operating plans, work to ensure that reliability coordinators, transmission operators and balancing authorities plan and operate the bulk electric system within all SOLs and IROLs to prevent instability, uncontrolled separation, or cascading. In addition, the revised definitions of operational planning analysis and real-time assessment address other concerns raised in the Remand NOPR as well as multiple recommendations in the 2011 Southwest Outage Blackout Report.\17\ --------------------------------------------------------------------------- \17\ NERC Petition at 17-18. --------------------------------------------------------------------------- Outage Coordination 18. In the NOPR, the Commission explained that NERC had addressed concerns raised in the Remand NOPR with respect to the IRO standards regarding planned outage coordination. In the Remand NOPR, the Commission expressed concern with NERC's proposal because Reliability Standards IRO-008-1, Requirement R3 and IRO-010-1a (subjects of the proposed remand and now withdrawn by NERC) did not require the coordination of outages, noting that outage coordination is a critical reliability function that should be performed by the reliability coordinator.\18\ --------------------------------------------------------------------------- \18\ Remand NOPR, 145 FERC ] 61,158 at P 90. --------------------------------------------------------------------------- 19. In the NOPR, the Commission noted that Reliability Standard IRO-017-1, Requirement R1 requires each reliability coordinator to develop, implement and maintain an outage coordination process for generation and transmission outages within its reliability coordinator area. Additionally, Reliability Standard IRO-014-3, Requirement R1, Part 1.4 requires reliability coordinators to include the exchange of planned and unplanned outage information to support operational planning analyses and real-time assessments in the operating procedures, processes, and plans for activities that require coordination with adjacent reliability coordinators. We believe that these proposed standards adequately address our concerns with respect to outage coordination as outlined in the Remand NOPR. However, as we discuss below we direct NERC to modify the standards to include transmission operator monitoring of non-BES facilities, and to specify that data exchange capabilities include redundancy and diverse routing; as well as testing of the alternate or less frequently used data exchange capability, within 18 months of the effective date of this Final Rule. 20. Below we discuss the following matters: (A) Possible inconsistencies of identifying IROLs; (B) monitoring of non-bulk electric system facilities; (C) removal of the load-serving entity function from proposed Reliability Standard TOP-001-3; (D) data exchange capabilities, and (E) other issues raised by commenters. A. Possible Inconsistences in IROLs Across Regions NOPR 21. In the NOPR, the Commission noted that in Exhibit E (SOL White Paper) of NERC's petition, NERC stated that, with regard to the SOL concept, the SOL White Paper brings ``clarity and consistency to the notion of establishing SOLs, exceeding SOLs, and implementing Operating Plans to mitigate SOL exceedances.'' \19\ The Commission further noted that IROLs, as defined by NERC, are a subset of SOLs that, if violated, could lead to instability, uncontrolled separation, or cascading outages that adversely impact the reliability of the bulk electric system. The Commission agreed with NERC that clarity and consistency are important with respect to establishing and implementing operating plans to mitigate SOL and IROL exceedances. However, the Commission noted that NERC, in its 2015 State of Reliability report, had stated that the Western Interconnection reliability coordinator definition of an IROL has additional criteria that may not exist in other reliability coordinator areas.\20\ The [[Page 73981]] Commission stated that it is unclear whether NERC regions apply a consistent approach to identifying IROLs. The Commission, therefore, sought comment on (1) identification of all regional differences or variances in the formulation of IROLs; (2) the potential reliability impacts of such differences or variations, and (3) the value of providing a uniform approach or methodology to defining and identifying IROLs. --------------------------------------------------------------------------- \19\ NERC Petition, Exhibit E, ``White Paper on System Operating Limit Definition and Exceedance Clarification'' at 1. \20\ NOPR, 151 FERC ] 61,236 at P 51, citing NERC 2015 State of Reliability report at 44, available at www.nerc.com. See also WECC Reliability Coordination System Operating Limits Methodology for the Operations Horizon, Rev. 7.0 (effective March 3, 2014) at 18 (stating that ``SOLs qualify as IROLs when . . . studies indicate that instability, Cascading, or uncontrolled separation may occur resulting in uncontrolled interruption of load equal to or greater than 1000 MW''), available at https://www.wecc.biz/Reliability/PhaseII%20WECC%20RC%20SOL%20Methodology%20FINAL.pdf. --------------------------------------------------------------------------- Comments 22. Commenters generally agree that there are variations in IROL formulation but maintain that the flexibility is needed due to different system topographies and configurations. EEI and other commenters, also suggest that, to the extent there are variations, such resolution should be addressed by NERC and the Regional Entities in a standard development process rather than by a Commission directive. NERC requests that the Commission refrain from addressing these issues in this proceeding. NERC contends that the TOP and IRO Reliability Standards do not address the methods for the development and identification of SOLs and IROLs and that requirements governing the development and identification of SOLs and IROLs are included in the Facilities Design, Connections and Maintenance (FAC) Reliability Standards. NERC states that the current FAC Reliability Standards provide reliability coordinators flexibility in the manner in which they identify IROLs.\21\ NERC adds that it recently initiated a standards development project (Project 2015-09 Establish and Communicate System Operating Limits) to evaluate and modify the FAC Reliability Standards that address the development and identification of SOLs and IROLs. NERC explains that the Project 2015-09 standard drafting team will address the clarity and consistency of the requirements for establishing both SOLs and IROLs. According to NERC, it would be premature for NERC or the Commission to address issues regarding the identification of IROLs in this proceeding without the benefit of the complete analysis of the Project 2015-09 standard drafting team. NERC commits to working with stakeholders and Commission staff during the Project 2015-09 standards development process to address the issues raised in the NOPR. --------------------------------------------------------------------------- \21\ See also Peak Comments at 4-5. Peak points to Reliability Standards FAC-011-2 and FAC-014-2 as support for regional variation in establishing IROLs. --------------------------------------------------------------------------- 23. ERCOT comments that the existing Reliability Standards provide a consistent but flexible structure for IROL identification that provides maximum benefit to interconnected transmission network. ERCOT believes that the Reliability Standards should continue to permit regional variations that will encourage flexibility for consideration of system-specific topology and characteristics as well as the application of operational experience and engineering judgment. ERCOT states that regional differences exist in terms of the specific processes and methodologies utilized to identify IROLs. However, according to ERCOT, appropriate consistency in IROL identification is driven by the definition of an IROL, the Reliability Standards associated with the identification of SOLs, and the communication and coordination among responsible entities. Further, ERCOT argues that allowing regional IROL differences benefits the bulk electric system by allowing the entities with the most operating experience to recognize the topology and operating characteristics of their areas, and to incorporate their experience and judgment into IROL identification. 24. Peak supports allowing regions to vary in their interpretation and identification of IROLs based on the level of risk determined by that region, as long as that interpretation is transparent and consistent within that region. Peak understands the definition of IROL to recognize regional differences and variances in the formulation of IROLs. Peak contends that such regional variation is necessary due to certain physical system differences. Thus, according to Peak, a consistent approach from region to region is not required, and may not enhance the overall reliability of the system. Peak explains that, in the Western United States, the evaluation of operating limits and stability must take into account the long transmission lines and greater distance between population centers, a situation quite different than the dense, interwoven systems found in much of the Eastern Interconnection. Peak adds that the Western Interconnection more frequently encounters localized instability because of the sparsity of the transmission system and the numerous small load centers supplied by few transmission lines, and these localized instances of instability have little to no impact on the overall reliability of the bulk electric system. Peak encourages the Commission to recognize that differences among the regions may require flexibility to determine, through its SOL methodology, the extent and severity of instability and cascading that warrant the establishment of an IROL. 25. While Peak supports retaining the flexibility of a region by region application of the IROL definition, Peak notes that the current definition is not without some confusing ambiguity in the application of IROL that should be addressed, including ambiguity and confusion around the term ``instability,'' the phrase ``that adversely impact the reliability of the Bulk Electric System'' and ``cascading.'' Peak suggests that one method to eliminate confusion on the definition and application of IROLs would be to expand NERC's whitepaper to address concerns more specific to IROLs. Peak contends that further guidance from NERC in the whitepaper may remedy the confusion on the limits on the application of IROLs for widespread versus localized instability. 26. Peak requests that, if the Commission or NERC determines that a one-size-fits all approach is necessary for the identification of IROLs and eliminates the current flexibility for regional differences, that the Commission recognizes the limitations this will place on reliability coordinators to evaluate the specific conditions within their reliability coordinator area. The Commission should require that any standardized application of the IROL definition would need to address specific thresholds and implementation triggers for IROLs based on the risk profile and challenges facing specific regions, to avoid the downfalls of inaccurate or overbroad application, as discussed above. Commission Determination 27. While it appears that regional discrepancies exist regarding the manner for calculating IROLs, we accept NERC's explanation that this issue is more appropriately addressed in NERC's Facilities Design, Connections and Maintenance or ``FAC'' Reliability Standards. NERC indicates that an ongoing FAC-related standards development project-- NERC Project 2015-09 (Establish and Communicate System Operating Limits)--will address the development and identification of SOLs and IROLs. We conclude that NERC's explanation, that the Project 2015-09 standard drafting team will address the clarity and consistency of the requirements for establishing both SOLs and IROLs, is reasonable. [[Page 73982]] Therefore, we will not direct further action on IROLs in the immediate TOP and IRO standard-related rulemaking. However, when this issue is considered in Project 2015-19, the specific regional difference of WECC's 1,000 MW threshold in IROLs should be evaluated in light of the Commission's directive in Order No. 802 (approving Reliability Standard CIP-014) to eliminate or clarify the ``widespread'' qualifier on ``instability'' as well as our statement in the Remand NOPR that ``operators do not always foresee the consequences of exceeding such SOLs and thus cannot be sure of preventing harm to reliability.'' \22\ --------------------------------------------------------------------------- \22\ Physical Security Reliability Standard, Order No. 802, 149 FERC ] 61,140 (2014) and Remand NOPR, 145 FERC ] 61,158 at P 52. See also FPA section 215(a)(4) defining Reliable Operation as ``operating the elements of the bulk-power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of system elements.'' --------------------------------------------------------------------------- B. Monitoring of Non-Bulk Electric System Facilities NOPR 28. In the NOPR the Commission proposed to find that the proposed Reliability Standards adequately address the 2011 Southwest Outage Blackout Report recommendation regarding monitoring sub-100 kV facilities, primarily because of the responsibility of the reliability coordinator under proposed Reliability Standard IRO-002-4, Requirement R3 to monitor non-bulk electric system facilities to the extent necessary. The Commission noted, however, that ``the transmission operator may have a more granular perspective than the reliability coordinator of its necessary non-bulk electric system facilities to monitor,'' and it is not clear whether or how the transmission operator would provide information to the reliability coordinator regarding which non-BES facilities should be monitored.\23\ The Commission sought comment on how NERC will ensure that the reliability coordinator will receive such information. --------------------------------------------------------------------------- \23\ NOPR, 151 FERC ] 61,236 at P 58. --------------------------------------------------------------------------- 29. The Commission stated that including such non-bulk electric system facilities in the definition of bulk electric system through the NERC Rules of Procedure exception process could be an option to address any potential gaps for monitoring facilities but notes that there may be potential efficiencies gained by using a more expedited method to include non-bulk electric system facilities that requires monitoring. The Commission sought comment on whether the BES exception process should be used exclusively in all cases. Alternatively, the Commission sought comment on whether this concern can be addressed through a review process of the transmission operators' systems to determine if there are important non-bulk electric system facilities that require monitoring. Comments 30. Nearly all commenters support the Reliability Standards as proposed as sufficient for identifying and monitoring non-bulk electric system facilities, and do not support the alternatives offered by the Commission in the NOPR.\24\ NERC submits that the proposed data specification and collection Reliability Standards IRO-010-2 and TOP- 003-3, in addition to the exceptions process will help ensure that the reliability coordinator can work with transmission operators, and other functional entities, to obtain sufficient information to identify the necessary non-bulk electric system facilities to monitor. In support, NERC points to Reliability Standard IRO-010-2, which provides a mechanism for the reliability coordinator to obtain the information and data it needs for reliable operations and to help prevent instability, uncontrolled separation, or cascading outages. Further, NERC cites Reliability Standard TOP-003-3, which allows transmission operators to obtain data on non-bulk electric system facilities, necessary to perform their operational planning analyses, real[hyphen]time monitoring, and real[hyphen]time assessments from applicable entities. NERC explains that any data that the transmission operator obtains regarding non-bulk electric system facilities under Reliability Standard TOP-003-3 can be passed on to the reliability coordinator pursuant to a request under proposed Reliability Standard IRO-010-2. Accordingly, NERC states that it would be premature to develop an alternative process before the data specification and bulk electric system exception process are allowed to work. --------------------------------------------------------------------------- \24\ E.g. NERC, EEI, TAPS, Occidental, and NIPSCO. --------------------------------------------------------------------------- 31. EEI states that this issue has been thoroughly studied by NERC through Project 2010-17 Phase 2 (Revisions to the Definition of Bulk Electric System) that led to modification of the definition of bulk electric system. EEI believes that the current process provides all of the necessary tools and processes to ensure that insights by TOPs are fully captured and integrated into existing monitoring systems that would ensure that all non-BES elements that might impact BES reliability are fully monitored. EEI does not support the alternative process proposed by the Commission. EEI warns that an alternative, parallel review process of the transmission operators' systems to determine if there are important non-bulk electric system facilities that require monitoring would either circumvent the revised bulk electric system definition process or arbitrarily impose NERC requirements (i.e., monitoring) onto non-bulk electric system elements. 32. APS agrees with the Commission that there would be a reliability benefit for the reliability coordinator to be able to identify facilities within the transmission operators' areas that may have a material impact on reliability. APS believes this benefit can be achieved using the method deployed in the Western Interconnection by the Western Electricity Coordinating Council (WECC). APS explains that the WECC planning coordination committee has published a bulk electric system inclusion guideline that categorizes non-bulk electric system facilities that are to be identified by each planning authority and transmission planner when performing their system planning and operations reliability assessments, and the identified facilities are then reported to NERC. APS proposes a similar exception process be used in all cases. According to APS, each reliability coordinator would publish a guideline on how to identify non-bulk electric system facilities critical to reliability appropriate for their reliability coordinator area, and each planning coordinator and transmission planner would run studies according to the reliability coordinator guideline at least once every three years. 33. ERCOT states that performance of sufficient studies and evaluations of reliability coordinator areas occurs in cooperation and coordination with associated transmission operators, rending an additional review process unnecessary. However, to avoid any potential gaps in monitoring non-bulk electric system facilities and ensure that existing agreements and monitoring processes are respected, ERCOT states that the Commission should direct NERC to modify the TOP and IRO Reliability Standards to refer not only to sub-100 kV facilities identified as part of the bulk electric system through the Rules of Procedure exception process, but also to other sub-100 kV facilities as requested or agreed by the responsible entities.\25\ ERCOT also states that [[Page 73983]] because ``non-bulk electric system facilities'' fall outside the scope of the NERC Reliability Standards, use of this terminology should be avoided. ERCOT advocates for the Commission to permit monitoring of other sub-100 kV facilities to be undertaken as agreed to between the reliability coordinator and the transmission operator. ERCOT and ISO/ RTOs suggest that the phrase ``non-BES facilities'' in Reliability Standard IRO-002-4, Requirement R3 should be replaced with ``sub-100 kV facilities identified as part of the BES through the BES exception process or as otherwise agreed to between the Reliability Coordinator and Transmission Operator'' and the phrase ``non-BES data'' in Reliability Standards IRO-010-2 (Requirement R1.1) and TOP-003-3 (Requirement R1.1) should be replaced with ``data from sub-100 kV facilities identified as part of the BES through the BES exception process, as otherwise requested by the Responsible Entity, or as agreed to between the Transmission Operator and the Responsible Entity.'' \26\ --------------------------------------------------------------------------- \25\ See also ISO/RTOs Comments at 3. \26\ See also ISO/RTOs Comments at 4-6. --------------------------------------------------------------------------- 34. ITC does not support the Commission's proposal. ITC states that transmission operators are required to incorporate any non-bulk electric system data into operational planning analysis and real-time assessments and monitoring, which therefore requires transmission operators to regularly review their models to identify impacting non- bulk electric system facilities. Conversely, ITC explains that conducting a one-time or periodic review and analysis of a transmission operator's model ignores the fact that changes in system conditions can cause the list of impacting non-bulk electric system facilities to change frequently. Commission Determination 35. We agree with NERC, TAPS, and EEI that the BES exception process can be a mechanism for identifying non-BES facilities to be included in the BES definition.\27\ Indeed, once a non-BES facility is included in the BES definition under the BES exception process, the ``non-BES facility'' becomes a BES ``Facility'' under TOP-001-3, Requirement R10, and real-time monitoring is required of ``Facilities.'' \28\ However, we are concerned that in some instances the absence of real-time monitoring of non-BES facilities by the transmission operator within and outside its TOP area as necessary for determining SOL exceedances in proposed TOP-001-3, Requirement R10 creates a reliability gap. As the 2011 Southwest Outage Report indicates, the Regional Entity ``should lead other entities, including TOPs and BAs, to ensure that all facilities that can adversely impact BPS reliability are either designated as part of the BES or otherwise incorporated into planning and operations studies and actively monitored and alarmed in [real-time contingency analysis] systems.'' \29\ Such monitoring of non-BES facilities could provide a ``stop gap'' during the period where a sub-100 kV facility undergoes analysis as a possible BES facility, allowing for monitoring in the interim until such time the non-bulk electric system facilities become ``BES Facilities'' or the transmission operator determines that a non-bulk electric system facility is no longer needed for monitoring to determine a system operating limit exceedance in its area.\30\ We believe that the operational planning analyses and real-time assessments performed by the transmission operators as well as the reliability coordinators will serve as the basis for determining which ``non-BES facilities'' require monitoring to determine system operating limit and interconnection reliability operating limit exceedances. In addition, we believe that monitoring of certain non-BES facilities that are occasional system operating limit exceedance performers may not qualify as a candidate for inclusion in the BES definition, yet should be monitored for reliability purposes.\31\ Accordingly, pursuant to section 215(d)(5) of the FPA, we direct NERC to revise Reliability Standard TOP-001-3, Requirement R10 to require real-time monitoring of non-BES facilities. We believe this is best accomplished by adopting language similar to Reliability Standard IRO-002-4, Requirement R3, which requires reliability coordinators to monitor non-bulk electric system facilities to the extent necessary. NERC can develop an equally efficient and effective alternative that addresses our concerns.\32\ --------------------------------------------------------------------------- \27\ NERC TOP/IRO Petition, Exh. G at 9 states in response to the 2011 Southwest Outage Recommendation17, ``If a non-BES facility impacts the BES, such as by contributing to an SOL or IROL, then the SDT expects that facility to be incorporated into the BES through the official BES Exception Process and it would be covered in proposed TOP-001-3, Requirement R10, Parts 10.1 and 10.2 by use of the defined term `Facilities.' '' \28\ NERC Glossary of Terms defines Facility as: ``A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)'' \29\ NOPR, 151 FERC ] 61,236 at P 55, citing Recommendation 17 of the 2011 Southwest Outage Blackout Report (emphasis added). \30\ NERC's BES Frequently Asked Questions, Version 1.6, February 25, 2015, Section 5.6. ``How long will the process take?'' at page 14 states: ``In general, assuming a complete application, no appeals, and taking the allotted time for each subtask, the process could take up to 11.5 months, but is anticipated to be shorter for less complicated Exception Requests. If the Exception Request is appealed to the NERC Board of Trustees Compliance Committee pursuant to Section 1703 of the NERC Rules of Procedure, the process could take an additional 8.5 months, totaling 20 months. This does not include timing related to an appeal to the applicable legal authority or Applicable Governmental Authority. A Regional Entity, upon consultation with NERC, may extend the time frame of the substantive review process. . . .'' http://www.nerc.com/pa/RAPA/BES%20DL/BES%20FAQs.pdf. \31\ See, e.g., NERC TOP/IRO Petition at 18 and 27-28. \32\ Reliability Standard IRO-002-4, Requirement R3 states: Each Reliability Coordinator shall monitor Facilities, the status of Special Protection Systems, and non-BES facilities identified as necessary by the Reliability Coordinator, within its Reliability Coordinator Area and neighboring Reliability Coordinator Areas to identify any System Operating Limit exceedances and to determine any Interconnection Reliability Operating Limit exceedances within its Reliability Coordinator Area. --------------------------------------------------------------------------- 36. To be clear, we are not directing that all current ``non-BES'' facilities that a transmission operator considers worthy of monitoring also be included in the bulk electric system. We believe that such monitoring may result in some facilities becoming part of the bulk electric system through the exception process; however it is conceivable that others may remain non-BES because they are occasional system operating limit exceedance performers that may not qualify as a candidate for inclusion in the BES definition. C. Removal of Load-Serving Entity Function From TOP-001-3 NOPR 37. NERC proposed the removal of the load-serving entity function from proposed Reliability Standard, TOP-001-3, Requirements R3 through R6, as a recipient of an operating instruction from a transmission operator or balancing authority. NERC supplemented its initial petition with additional explanation for the removal of the load-serving entity function from proposed Reliability Standard TOP-001-3.\33\ NERC explained that the proposed standard gives transmission operators and balancing authorities the authority to direct the actions of certain other functional entities by issuing an operating instruction to maintain reliability during real-time operations. --------------------------------------------------------------------------- \33\ The Commission also notes that Reliability Standards TOP- 003-3 and IRO-010-2 also include ``load-serving entity'' as an applicable entity. --------------------------------------------------------------------------- 38. In the NOPR, the Commission noted that NERC was required to make a compliance filing in Docket No. RR15-4-000, regarding NERC's Risk-Based Registration initiative, and that the Commission's decision on that filing [[Page 73984]] will guide any action in this proceeding. On March 19, 2015, the Commission approved, in part, NERC's Risk-Based Registration initiative, but denied, without prejudice, NERC's proposal to eliminate the load-serving entity function from the registry process, finding that NERC had not adequately justified its proposal.\34\ In doing so, the Commission directed NERC to provide additional information to support this aspect of its proposal to address the Commission's concerns. On July 17, 2015, NERC submitted a compliance filing in response to the March 19 Order. --------------------------------------------------------------------------- \34\ North American Electric Reliability Corp. 150 FERC ] 61,213 (2015) (March 19 Order). --------------------------------------------------------------------------- Comments 39. NERC states that while load-serving entities play a role in facilitating interruptible (or voluntary) load curtailments, that role is to simply communicate requests for voluntary load curtailments and does not necessitate requiring load-serving entities to comply with a transmission operator's or balancing authority's operating instructions issued pursuant to Reliability Standard TOP-001-3. In short, the load- serving entity's role in carrying out interruptible load curtailment is not the type of activity that rises to the level of requiring an operating instruction. EEI and TAPS contend it is appropriate to omit the load-serving entity function from TOP-001-3 applicability. TAPS explains that because the load-serving entity function does not own or operate equipment, the load-serving entity function cannot curtail load or perform other corrective actions subject to reliability standards. Dominion asserts that a load-serving entity does not own or operate bulk electric system facilities or equipment or the facilities or equipment used to serve end-use customers and is not aware of any entity, registered solely as a load-serving entity, which is responsible for operating one or more elements or facilities. Commission Determination 40. In an October 15, 2015 order in Docket No. RR15-4-001, the Commission accepted a NERC compliance filing, finding that NERC complied with the March 17 Order with respect to providing additional information justifying the removal of the load-serving entity function.\35\ The Commission also found that NERC addressed the concerns expressed regarding an accurate estimate of the load-serving entities to be deregistered and the reliability impact of doing so, and how load data will continue to be available and reliability activities will continue to be performed even after load-serving entities would no longer be registered.\36\ Because the load-serving entity category is no longer a NERC registration function, no further action is required in this proceeding.\37\ --------------------------------------------------------------------------- \35\ North American Electric Reliability Corp, 153 FERC ] 61,024 (2015). \36\ Id. \37\ In its response to comments in Docket No. RR15-4-000, NERC stated that, once the Commission approved the proposed deactivation of the load-serving entity registration function, it would make any needed changes to the Reliability Standards through the Reliability Standard Development Process. See January 26, 2016, NERC Motion to File Limited Answer at 6 in Docket No. RR15-4-000. --------------------------------------------------------------------------- D. Data Exchange Capabilities 41. The Commission approved Reliability Standards COM-001-2 (Communications) and COM-002-4 (Operating Personnel Communications Protocols) in Order No. 808, and noted that in the NOPR underlying that order (COM NOPR) it had raised concerns as to whether Reliability Standard COM-001-2 addresses facilities that directly exchange or transfer data.\38\ In response to that concern in the COM NOPR, NERC clarified that Reliability Standard COM-001-2 did not need to include requirements regarding data exchange capability because such capability is covered under other existing and proposed standards. Based on that explanation, the Commission decided not to make any determinations in Order No. 808 and stated that it would address the issue in this TOP and IRO rulemaking proceeding.\39\ --------------------------------------------------------------------------- \38\ See NOPR, 151 FERC ] 61,236 at P 67, citing Communications Reliability Standards, Order No. 808, 151 FERC ] 61,039 (2015). \39\ Id. citing Order No. 808, 151 FERC ] 61,039 at P 54. --------------------------------------------------------------------------- NOPR 42. In the NOPR, the Commission stated that facilities for data exchange capabilities appear to be addressed in NERC's TOP/IRO petition. However, the Commission sought additional explanation from NERC regarding how it addresses data exchange capabilities in the TOP and IRO Standards in the following areas: (a) Redundancy and diverse routing; and (b) testing of the alternate or less frequently used data exchange capability. 1. Redundancy and Diverse Routing of Data Exchange Capabilities NOPR 43. In the NOPR, the Commission agreed that proposed Reliability Standard TOP-001-3, Requirements R19 and R20 require some form of ``data exchange capabilities'' for the transmission operator and balancing authority and that proposed Reliability Standard TOP-003-3 addresses the operational data itself needed by the transmission operator and balancing authority. In addition, the Commission agreed that Reliability Standard IRO-002-4, Requirement R1 requires ``data exchange capabilities'' for the reliability coordinator and that proposed Reliability Standard IRO-010-2 addresses the operational data needed by the reliability coordinator and that proposed Reliability Standard IRO-002-4 Requirement R4 requires a redundant infrastructure for system monitoring. However, the Commission was concerned that it is not clear whether redundancy and diverse routing of data exchange capabilities were adequately addressed in proposed Reliability Standards TOP-001-3 and IRO-002-4 for the reliability coordinator, transmission operator, and balancing authority and sought explanation or clarification on how the standards address redundancy and diverse routing or an equally effective alternative. The Commission also stated that, if NERC or others believe that redundancy and diverse routing are not addressed, they should address whether there are associated reliability risks of the interconnected transmission network for any failure of data exchange capabilities that are not redundant and diversely routed. Comments 44. NERC and EEI state that the requirements in the TOP and IRO Reliability Standards covering data exchange are results-based, articulating a performance objective without dictating the manner in which it is met. NERC adds that, in connection with their compliance monitoring activities, NERC and the Regional Entities will review whether applicable entities have met that objective, and will consider whether the applicable entity has redundancy and diverse routing, and whether the applicable entity tests these capabilities. EEI also argues that Reliability Standard EOP-008-1, Requirements R1, R1.2, R1.2.2, R7, and EOP-001-2.1b, Requirements R6 and R6.1 provide specific requirements for maintaining or specifying reliable back-up data exchange capability necessary to ensure BES Reliability and the testing of those capabilities. 45. ERCOT asserts that the Reliability Standards already appropriately provide for redundancy and diversity of routing of data exchange capabilities, as both the existing and proposed standards [[Page 73985]] either explicitly or implicitly require responsible entities to ensure availability of data and data exchange capabilities. ERCOT states that, should the Commission seek to provide further clarification on this issue, such clarification should be consistent with existing explicit requirements regarding the redundancy of data exchange capabilities, such as Requirement R4 of Reliability Standard IRO-002-4. 46. ISOs/RTOs and ERCOT explain the suite of currently-effective standards and the proposed TOP and IRO standards establish performance- based requirements for reliability coordinators, balancing authorities, and transmission operators, that create the need for those entities to have diverse and redundantly routed data communication systems. In the event of a failure of data communications, ISOs/RTOs explain that the functional entity should be able to rely on the redundant and diversely routed voice capabilities required in the COM standards. Commission Determination 47. We agree with NERC and other commenters that there is a reliability need for the reliability coordinator, transmission operator and balancing authority to have data exchange capabilities that are redundant and diversely routed. However, we are concerned that the TOP and IRO Standards do not clearly address redundancy and diverse routing so that registered entities will unambiguously recognize that they have an obligation to address redundancy and diverse routing as part of their TOP and IRO compliance obligations. NERC's comprehensive approach to establishing communications capabilities necessary to maintain reliability in the COM standards is applicable to data exchange capabilities at issue here.\40\ Therefore, pursuant to section 215(d)(5) of the FPA, we direct NERC to modify Reliability Standards TOP-001-3, Requirements R19 and R20 to include the requirement that the data exchange capabilities of the transmission operators and balancing authorities require redundancy and diverse routing. In addition, we direct NERC to clarify that ``redundant infrastructure'' for system monitoring in Reliability Standards IRO-002-4, Requirement R4 is equivalent to redundant and diversely routed data exchange capabilities. --------------------------------------------------------------------------- \40\ See, e.g, Order No. 808, 151 FERC ] 61,039 at P 8: ``NERC stated in its [COM] petition that Reliability Standard COM-001-2 establishes requirements for Interpersonal Communication capabilities necessary to maintain reliability. NERC explained that proposed Reliability Standard COM-001-2 applies to reliability coordinators, balancing authorities, transmission operators, generator operators, and distribution providers. The proposed Reliability Standard includes eleven requirements and two new defined terms, ``Interpersonal Communication'' and ``Alternative Interpersonal Communication,'' that, according to NERC, collectively provide a comprehensive approach to establishing communications capabilities necessary to maintain reliability.'' --------------------------------------------------------------------------- 48. Further, we disagree with commenter arguments that Reliability Standard EOP-008-1 provides alternatives to data exchange redundancy and diverse routing. The NERC standard drafting team that developed the COM standards addressed this issue in the standards development process, responding to a commenter seeking clarification on the relationship between communication capabilities, alternative communication capabilities, primary control center functionality and backup control center functionality. The standard drafting team responded that ``Interpersonal Communication and Alternative Interpersonal Communication are not related to EOP-008,'' even though Reliability Standard EOP-008-1 Requirement R1 applies equally to data communications and voice communications.\41\ To the extent the standard drafting team asserted that Reliability Standard EOP-008 did not supplant the redundancy requirements of the COM Reliability Standards, we believe the same is true for data communications. Redundancy for data communications is no less important than the redundancy explicitly required in the COM standards for voice communications. --------------------------------------------------------------------------- \41\ See NERC COM Petition, Exh. M, (Consideration of Comments on Initial Ballot, February 25-March 7, 2011) at 30 (emphasis added). --------------------------------------------------------------------------- 2. Testing of the Alternate or Less Frequently Used Data Exchange Capability NOPR 49. In the NOPR, the Commission expressed concern that the proposed TOP and IRO Reliability Standards do not appear to address testing requirements for alternative or less frequently used mediums for data exchange to ensure they would properly function in the event that the primary or more frequently used data exchange capabilities failed. Accordingly, the Commission sought comment on whether and how the TOP and IRO Reliability Standards address the testing of alternative or less frequently used data exchange capabilities for the transmission operator, balancing authority and reliability coordinator. Comments 50. Commenters assert that the existing standards have sufficient testing requirements. NERC points to Reliability Standard EOP-008-1, Requirement R7, which requires that applicable entities conduct annual tests of their operating plan that demonstrates, among other things, backup functionality. Similarly, EEI cites EOP-008-1 Requirements R1, R1.2, R1.2.2, R7 and EOP-001-2.1b Requirements R6 and R6.1 as providing specific requirements for maintaining and testing of data exchange capabilities. ITC suggests that NERC's proposed Standard TOP-001-3 provides ample assurance that the data exchange capabilities are regularly tested and also points to Reliability Standards EOP-001-2.1b and EOP-008-1 which require entities, including those covered by TOP- 001-3, to maintain reliable back-up data exchange capability as necessary to ensure reliable BES operations, and require that such capabilities be thoroughly and regularly tested. Commission Determination 51. We agree with NERC and other commenters that there is a reliability need for the reliability coordinator, transmission operator and balancing authority to test alternate data exchange capabilities. However, we are not persuaded by the commenters' assertions that the need to test is implied in the TOP and IRO Standards. Rather, we determine that testing of alternative data exchange capabilities is important to reliability and should not be left to what may or may not be implied in the standards.\42\ Therefore, pursuant to section 215(d)(5) of the FPA, we direct NERC to develop a modification to the TOP and IRO standards that addresses a data exchange capability testing framework for the data exchange capabilities used in the primary control centers to test the alternate or less frequently used data exchange capabilities of the reliability coordinator, transmission operator and balancing authority. We believe that the structure of Reliability Standard COM-001-2, Requirement R9 could be a [[Page 73986]] model for use in the TOP and IRO Standards.\43\ --------------------------------------------------------------------------- \42\ In NERC's COM Petition, Exh. M, (Consideration of Comments, Index to Questions, Comments and Responses) at 35, the standard drafting team stated that the ``requirement [COM-001-2, Requirement R9 which addresses testing of alternative interpersonal communication] applies to the primary control center'' and ``EOP-008 applies to the back up control center.'' \43\ 43 COM-001-2, Requirement R9 states: ``Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall test its Alternative Interpersonal Communication capability at least once each calendar month. If the test is unsuccessful, the responsible entity shall initiate action to repair or designate a replacement Alternative Interpersonal Communication capability within 2 hours.'' --------------------------------------------------------------------------- E. Other Issues Raised by Commenters 1. Emergencies and Emergency Assistance Under Reliability Standard TOP- 001-3 52. Reliability Standard TOP-001-3, Requirement R7 requires each transmission operator to assist other transmission operators within its reliability coordinator area, if requested and able, provided that the requesting transmission operator has implemented its comparable emergency procedures. NIPSCO contends that this requirement limits the ability of an adjacent transmission operator that is located along the seam in another reliability coordinator area from rendering assistance in an emergency because Requirement R7 only requires each transmission operator to assist other transmission operators within its reliability coordinator area. NIPSCO points to Reliability Standard IRO-014-3, Requirement R7 which requires each reliability coordinator to assist other reliability coordinators and, according to NIPSCO, a similar requirement in Reliability Standard TOP-001-3 will make the two sets of requirements consistent with each other. 53. In addition, Reliability Standard TOP-001-3, Requirement R8 states: Each Transmission Operator shall inform its Reliability Coordinator, known impacted Balancing Authorities, and known impacted Transmission Operators of its actual or expected operations that result in, or could result in, an Emergency. BPA contends that the phrase ``could result in'' in Requirement R8 of TOP-001-3 is overly broad and suggests corrective language underscored below: Each Transmission Operator shall inform its Reliability Coordinator, known impacted Balancing Authorities, and known impacted Transmission Operators of its actual or expected operations that result in an Emergency, or could result in an Emergency if a credible Contingency were to occur. As an alternative to changing the language of the requirement, BPA asks the Commission to clarify that it is in the transmission operator's discretion to determine what ``could result'' in an emergency, based on the transmission operator's experience and judgment. Commission Determination 54. With regard to NIPSCO's concern, we do not believe that the requirements as written limit the ability of an adjacent transmission operator located along the seam in another reliability coordinator area from rendering assistance in an emergency. We agree with NIPSCO that proposed Reliability Standard TOP-001-3, Requirement R7 requires each transmission operator to assist other transmission operators within its reliability coordinator area and further agree with NIPSCO that proposed Reliability Standard IRO-014-3, Requirement R7 requires each reliability coordinator to assist other reliability coordinators.\44\ In addition, we understand that an adjacent transmission operator in another reliability coordinator area can render assistance when directed to do so by its own reliability coordinator.\45\ Having a similar requirement in Reliability Standard TOP-001-3 compared to Reliability Standard IRO-014-3, Requirement R7 is unnecessary and could complicate the clear decision-making authority NERC developed in the TOP and IRO Reliability Standards. Thus, we determine that no further action is required. --------------------------------------------------------------------------- \44\ See Reliability Standards TOP-001-3 and IRO-014-3. \45\ See Reliability Standard IRO-001-4, Requirement R2. --------------------------------------------------------------------------- 55. With regard to clarification of emergencies in Reliability Standard TOP-001-3, Requirement R8, we do not see a need to modify the language as suggested by BPA. The requirement as written implies that the transmission operator has discretion to determine what could result in an emergency, based on its experience and judgment. In addition, we note that the transmission operators' required next-day operational planning analysis, real-time assessments and real-time monitoring under the TOP Reliability Standards provide evaluation, assessment and input in determining what ``could result'' in an emergency. 2. Reliability Coordinator Authority in Next-Day Operating Plans 56. Reliability Standard TOP-002-4, Requirements R2 and R4 require transmission operators and balancing authorities to have operating plans. Reliability Standard TOP-002-4, Requirements R6 and R7 require transmission operators and balancing authorities to provide their operating plans to their reliability coordinators and Reliability Standard IRO-008-2, Requirement R2 requires reliability coordinators to develop a coordinated operating plan that considers the operating plans provided by the transmission operators and balancing authorities. 57. NIPSCO is concerned about the absence of any required direct coordination between transmission operators and balancing authorities as well as the absence of any guidance regarding the resolution of potential conflicts between the transmission operator and balancing authority operating plans. NIPSCO contends that the Reliability Standards provide only a limited coordination process in which reliability coordinators are required to notify those entities identified with its coordinated operating plan of their roles. NIPSCO argues that there is no provision for modifications to operating plans based on the reliability coordinator's coordinated operating plan or based on potential conflicts between the transmission operator and balancing authority operating plans. NIPSCO is concerned that a potential disconnect between operating plans could lead to confusion or a failure of coordination of reliable operations. Commission Determination 58. We believe that proposed Reliability Standards TOP-002-4 and IRO-008-2 along with NERC's definition of reliability coordinator address NIPSCO's concern.\46\ Although the transmission operator and balancing authority develop their own operating plans for next-day operations, both the transmission operator and balancing authority notify entities identified in the operating plans as to their role in those plans. Further, each transmission operator and balancing authority must provide its operating plan for next-day operations to its reliability coordinator.\47\ In Reliability Standard IRO-008-2, Requirement R2, the reliability coordinator must have a coordinated operating plan for next-day operations to address potential SOL and IROL exceedances while considering the operating plans for the next-day provided by its transmission operators [[Page 73987]] and balancing authorities. Also, Reliability Standard IRO-008-2, Requirement R3 requires that the reliability coordinator notify impacted entities identified in its operating plan as to their role in such plan. Based on the notification and coordination processes of Reliability Standards TOP-002-4 (for the transmission operator and balancing authority) and IRO-008-2 (for the reliability coordinator) for next-day operating plans, as well as the fact that the reliability coordinator is the entity that is the highest level of authority who is responsible for the reliable operation of the bulk electric system, we believe that the reliability coordinator has the authority and necessary next-day operational information to resolve any next-day operational issues within its reliability coordinator area. Accordingly, we deny NIPSCO's request. --------------------------------------------------------------------------- \46\ NERC Glossary of Terms defines the Reliability Coordinator as ``The entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next- day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator's vision.'' \47\ Reliability Standard TOP-002-4 (Operations Planning). --------------------------------------------------------------------------- 3. Reliability Coordinator Authority in Next-Day Operations and the Issuance of Operating Instructions 59. NIPSCO is concerned with the elimination of the explicit requirement in currently-effective Reliability Standard IRO-004-2 that each transmission operator, balancing authority, and transmission provider comply with the directives of a reliability coordinator based on next-day assessment in the same manner as would be required in real- time operating conditions. NIPSCO claims that, while the Reliability Standards appear to address the Commission's concerns regarding directives issued in other than emergency conditions through the integration of the term ``operating instruction,'' the standards only allow for the issuance of directives in real-time. NIPSCO points to Reliability Standard TOP-001-3, Requirements R1 and R2, and IRO-001-4, Requirement R1, where transmission operators, balancing authorities, and reliability coordinators are explicitly given authority and responsibility to issue operating instructions to address reliability in their respective areas. NIPSCO states that ``operating instruction'' is ``clearly limited to real-time operations'' as it underscored below: A command by operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. (A discussion of general information and of potential options or alternatives to resolve Bulk Electric System operating concerns is not a command and is not considered an Operating Instruction.) NIPSCO contends that there are no clear requirements addressing potential conflicts between operating plans, no clear requirements authorizing the issuance of a directive to address issues identified in next-day planning, and no clear requirement to comply with any directive so issued. NIPSCO is concerned that this raises the possibility that potential next-day problems identified in the operational planning analyses may not get resolved in the next-day planning period because the reliability coordinator's authority to issue operating instructions is limited to real-time operation. According to NIPSCO, this limitation undermines some of the usefulness of the next-day planning and the performance of operational planning analyses. Commission Determination 60. We do not share NIPSCO's concern. Rather, we believe that, because the reliability coordinator is required to have a coordinated operating plan for the next-day operations, the reliability coordinator will perform its task of developing a coordinated operating plan in good faith, with inputs not only from its transmission operators and balancing authorities, but also from its neighboring reliability coordinators.\48\ A reliability coordinator has a wide-area view and bears the ultimate responsibility to maintain the reliability within its footprint, ``including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations.'' \49\ --------------------------------------------------------------------------- \48\ See Reliability Standards IRO-008-2, Requirements R1 and R2, and IRO-014-3, Requirement R1. \49\ See supra n. 46. --------------------------------------------------------------------------- 61. In addition, we do not agree with NIPSCO's claim that operating instructions are ``clearly limited to real-time operations.'' The phrase ``real-time operation'' in the definition of operating instruction as emphasized by NIPSCO applies to the entity that issues the operating instruction which is ``operating personnel responsible for the Real-time operation.'' The definition of operating instruction is ``[a] command by operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System. . . .'' In addition, the time horizons associated with the issuance of or compliance with an operating instruction are not found in the definition of operating instructions, but found in the individual requirement(s) applicable to issuing an operating instruction. For example, Reliability Standard TOP-001-3, Requirements R1 through R6 and IRO-001-4, Requirements R1 through R3 are all requirements associated with the issuance or compliance of operating instructions. In all nine requirements, the defined time horizon is ``same-day operations'' and ``real-time operations.'' \50\ Accordingly, we deny NIPSCO's request on this issue. --------------------------------------------------------------------------- \50\ NERC's ``Time Horizons'' document defines ``Same-Day Operations'' time horizon as ``routine actions required within the timeframe of a day, but not real-time'' and defines ``Real-Time Operations'' time horizon as ``actions required within one hour or less to preserve the reliability of the bulk electric system.'' See http://www.nerc.com/files/Time_Horizons.pdf. --------------------------------------------------------------------------- 4. Updating Operational Planning Analyses and Real-Time Assessments 62. NIPSCO is concerned that the proposed Reliability Standards are not clear as to whether updates or additional analyses are required. NIPSCO points to Reliability Standards IRO-008-2 and TOP-002-4, which require reliability coordinators to perform--and transmission operators and balancing authorities to have--an operational analysis for the next-day, but do not specify when such analysis must be performed or if it needs to be updated in next-day planning based on any change in inputs. Similarly, NIPSCO asserts that the proposed Reliability Standards require the performance of a real-time assessment every 30 minutes but do not address the need to potentially update operating plans based on changes in system conditions (including unplanned outages of protection system degradation) and do not require the performance of additional real-time assessments or other studies with more frequency based on changes in system conditions. NIPSCO explains that it is not clear if or when, based on the operational planning analysis results, some type of additional study or analysis would need to be undertaken prior to the development of an operating plan. According to NIPSCO, the text of the requirements and the definition do not specifically require additional studies; however, it seems that when issues associated with protection system degradation or outages are identified, further study of these issues would be required and/or additional analyses required to update results as protection system status or transmission or generation outages change. Commission Determination 63. We do not share NIPSCO's concern. Reliability Standards IRO- 008-2 and TOP-002-4 require reliability coordinators to perform and [[Page 73988]] transmission operators to have an operational planning analysis to assess whether its planned operations for next-day will exceed any of its SOLs (for the transmission operator) and SOLs/IROLs (for the reliability coordinator). Both are required to have an operating plan(s) to address potential SOL and/or IROL exceedances based on its operational planning analysis results. We believe that, if the applicable inputs of the operational planning analysis change from one operating day to the next operating day, and because an operational planning analysis is an ``evaluation of projected system conditions,'' a new operational planning analysis must be performed to include the change in applicable inputs. Based on the results of the new operational planning analysis for next-day, operating plans may need updating to reflect the results of the new operational planning analysis. Likewise with the real-time assessment, as system conditions change and the applicable inputs to the real-time assessment change, a new assessment would be needed to accurately reflect applicable inputs, as stated in the real-time assessment definition.\51\ --------------------------------------------------------------------------- \51\ Real-time assessment is defined as ``An evaluation of system conditions using Real-time data to assess existing (pre- Contingency) and potential (post-Contingency) operating conditions. The assessment shall reflect applicable inputs including, but not limited to: Load, generation output levels, known Protection System and Special Protection System status or degradation, Transmission outages, generator outages, Interchange, Facility Ratings, and identified phase angle and equipment limitations. (Real-time Assessment may be provided through internal systems or through third-party services.).'' --------------------------------------------------------------------------- 5. Performing a Real-Time Assessment When Real-Time Contingency Analysis Is Unavailable 64. Reliability Standard TOP-001-3, Requirement R13 requires transmission operators to ensure a real-time assessment is performed at least every 30 minutes. NIPSCO states that NERC's definition of real- time assessment anticipates that real-time assessments must be performed through the use of either an internal tool or third-party service.\52\ NIPSCO believes that compliance with the requirement to perform a real-time assessment should not be dependent on the availability of a system or tool. According to NIPSCO, if a transmission operators' tools are unavailable for 30 minutes or more, they should be permitted to meet the requirement to assess existing conditions through other means. --------------------------------------------------------------------------- \52\ See supra n. 48. --------------------------------------------------------------------------- Commission Determination 65. Reliability Standard TOP-001-3, Requirement R13 requires the transmission operator to ensure the assessment is performed at least once every 30 minutes, but does not state that the transmission operator on its own must perform the assessment and does not specify a system or tool. This gives the transmission operator flexibility to perform its real-time assessment. Further supporting this flexibility, NERC's definition of real-time assessment states that a real-time assessment ``may be provided through internal systems or through third- party services.'' \53\ Therefore, we believe that Reliability Standard TOP-001-3, Requirement R13 does not specify the system or tool a transmission operator must use to perform a real-time assessment. In addition, NERC explains that Reliability Standard TOP-001-3, Requirement R13 and the definition of real-time assessment ``do not specify the manner in which an assessment is performed nor do they preclude Reliability Coordinators and Transmission Operators from taking `alternative actions' and developing procedures or off-normal processes to mitigate analysis tool (RTCA) outages and perform the required assessment of their systems. As an example, the Transmission Operator could rely on its Reliability Coordinator to perform a Real- time Assessment or even review its Reliability Coordinator's Contingency analysis results when its capabilities are unavailable and vice-versa.'' \54\ Accordingly, we conclude that TOP-001-3 adequately addresses NIPSCO's concern, namely, if a transmission operators' tools are unavailable for 30 minutes or more, the transmission operator has the flexibility to meet the requirement to assess system conditions through other means. --------------------------------------------------------------------------- \53\ NERC TOP/IRO Petition at 18. \54\ NERC TOP/IRO Petition, Exh. K (Summary of Development History and Complete Record of Development), Consideration of Comments May 19, 2014 through July 2, 2014) at 61. --------------------------------------------------------------------------- 6. Valid Operating Limits 66. IESO is concerned that the revised TOP standards do not compel an entity to verify existing limits or re-establish limits following an event that results in conditions not previously assessed within an acceptable time frame as is specified in the currently-effective Reliability Standard TOP-004-2 Requirement R4.\55\ IESO disagrees that this is sufficient because there is no requirement in the Reliability Standard TOP-001-3 standard to derive a new set of limits, particularly transient stability limits, or verify that an existing set of limits continue to be valid for the prevailing conditions within an established timeframe. IESO contends that a real-time assessment is useful only if the system conditions are assessed against a valid set of limits and is unable to verify or re-establish stability-restricted SOLs with which to assess system conditions to address reliability concerns. IESO believes that an explicit requirement to verify or re- establish SOLs when entering into an unstudied state must therefore be imposed to fill this reliability gap. --------------------------------------------------------------------------- \55\ Requirement R4 states: ``If a Transmission Operator enters an unknown operating state (i.e. any state for which valid operating limits have not been determined), it will be considered to be in an emergency and shall restore operations to respect proven reliable power system limits within 30 minutes.'' --------------------------------------------------------------------------- 67. Further, IESO asserts that implementing operating plans to mitigate an SOL exceedance does not require transmission operators to determine a valid set of limits with which to compare the prevailing system conditions (i.e. whether or not the limits are exceeded). While the IESO supports performing a real-time assessment every 30 minutes, it asserts that performing an assessment without first validating the current set of limits or re-establishing a new set of limits as the boundary conditions leaves a reliability gap. Commission Determination 68. We agree with IESO that valid operating limits, including transient stability limits, are essential to the reliable operation of the interconnected transmission network and that a transmission operator must not enter into an unknown operating state. Further, we agree with IESO that Reliability Standard TOP-001-3 has no requirements to derive a new set of limits or verify an existing set of limits for prevailing operating conditions within an established timeframe. However, IESO's concerns regarding the establishment of transient stability operating limits are addressed collectively through proposed Reliability Standard TOP-001-3, certain currently-effective Facilities Design, Connections, and Maintenance (FAC) Reliability Standards and NERC's Glossary of Terms definition of SOLs. 69. In its SOL White Paper, NERC stated that the intent of the SOL concept is to bring clarity and consistency for establishing SOLs, exceeding SOLs, and implementing operating plans to mitigate SOL exceedances.\56\ In [[Page 73989]] addition, ``transient stability ratings'' are included in the SOL definition. Further, in the SOL White Paper, NERC states that the ``concept of SOL determination is not complete without looking at the approved NERC FAC standards FAC-008-3, FAC-011-2 and FAC-014-2.'' \57\ Specific to IESO's concerns of establishing transient stability limits, we agree with NERC that approved Reliability Standard FAC-011-2, Requirement R2 requires that the reliability coordinator's SOL methodology include a requirement that SOLs provide a certain level of bulk electric system performance including among other things, that the ``BES shall demonstrate transient, dynamic and voltage stability'' and that ``all Facilities shall be within their . . . stability limits'' for both pre- and post-contingency conditions.\58\ In addition, we note that currently-effective Reliability Standard FAC-011-2, Requirement R2.1 states that ``[i]n the determination of SOLs, the BES condition used shall reflect current or expected system conditions and shall reflect changes to system topology such as Facility outages.'' \59\ --------------------------------------------------------------------------- \56\ NERC Petition, Exh. E (White Paper on System Operating Limit Definition and Exceedance Clarification) at 1. NIPSCO requests clarification as to how NERC's SOL White Paper can be used in determining compliance. NIPSCO requests that any substantive content that is treated as containing enforceable compliance requirements be filed with the Commission for approval. NERC developed the SOL White Paper as a guidance document which provides links between relevant reliability standards and reliability concepts to establish a common understanding necessary for developing effective operating plans to mitigate SOL exceedances. Guidelines are illustrative but not mandatory and enforceable compliance requirements. See, e.g. North American Electric Reliability Corp., 143 FERC ] 61,271, at P 15 (2013). Accordingly, we see no need for further revisions to the Reliability Standards to incorporate the SOL White Paper as requested by NIPSCO. \57\ NERC Petition, Exh. E at 1. \58\ Id. at 2. See also Reliability Standard FAC-011-2, Requirement R2. \59\ Reliability Standard FAC-011-1, Requirement R2.1 (emphasis added). --------------------------------------------------------------------------- 70. With respect to Reliability Standard TOP-001-3, we agree with NERC that Requirement R13 specifies that transmission operators must perform a real-time assessment at least once every 30 minutes, which by definition is an evaluation of system conditions to assess existing and potential operating conditions. The real-time assessment provides the transmission operator with the necessary knowledge of the system operating state to initiate an operating plan, as specified in Requirement R14, when necessary to mitigate an exceedance of SOLs. In addition, the SOL White Paper provides technical guidance for including timelines in the required operating plans to return the system to within prescribed ratings and limits.\60\ Accordingly, we conclude that the establishment of transient stability operating limits is adequately addressed collectively through proposed Reliability Standard TOP-001-3, currently-effective Reliability Standards FAC-011-2 and FAC-014-2 and NERC's Glossary of Terms definition of SOLs.\61\ --------------------------------------------------------------------------- \60\ NERC Petition at 57-58. \61\ See Reliability Standard FAC-014-2, Requirement R2. --------------------------------------------------------------------------- III. Information Collection Statement 71. The collection of information contained in this Final Rule is subject to review by the Office of Management and Budget (OMB) regulations under section 3507(d) of the Paperwork Reduction Act of 1995 (PRA).\62\ OMB's regulations require approval of certain informational collection requirements imposed by agency rules.\63\ Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a 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. --------------------------------------------------------------------------- \62\ 44 U.S.C. 3507(d) (2012). \63\ 5 CFR 1320.11. --------------------------------------------------------------------------- Public Reporting Burden: The number of respondents below is based on an estimate of the NERC compliance registry for the balancing authority, transmission operator, generator operator, distribution provider, generator owner, load-serving entity, purchasing-selling entity, transmission service provider, interchange authority, transmission owner, reliability coordinator, planning coordinator, and transmission planner functions. The Commission based its paperwork burden estimates on the NERC compliance registry as of May 15, 2015. According to the registry, there are 11 reliability coordinators, 99 balancing authorities, 450 distribution providers, 839 generator operators, 80 purchasing-selling entities, 446 load-serving entities, 886 generator owners, 320 transmission owners, 24 interchange authorities, 75 transmission service providers, 68 planning coordinators, 175 transmission planners and 171 transmission operators. The estimates are based on the change in burden from the current standards to the standards approved in this Final Rule. The following table illustrates the burden to be applied to the information collection: RM15-16-000 (Transmission Operations Reliability Standards, Interconnection Reliability Operations and Coordination Reliability Standards) -------------------------------------------------------------------------------------------------------------------------------------------------------- Annual number Average burden & Total annual burden Number of of responses Total number cost per response hours & total annual Cost per respondent respondents \64\ per respondent of responses \65\ cost ($) (1)................. (2) (1) * (2) = (4)................. (3) * (4) = (5)..... (5) / (1) (3) -------------------------------------------------------------------------------------------------------------------------------------------------------- FERC-725A -------------------------------------------------------------------------------------------------------------------------------------------------------- TOP-001-3........................ 196 (TOP & BA)...... 1 196 96 hrs., $6,369..... 18,816 hrs., 96 hrs, $6,369. $1,248,441. TOP-002-4........................ 196 (TOP & BA)...... 1 196 284 hrs., $18,843... 55,664 hrs., 284 hrs., $18,843. $3,693,306. TOP-003-3........................ 196 (TOP & BA)...... 1 196 230 hrs., $15,260... 45,080 hrs., 230 hrs., $15,260. $2,991,058. ------------------------------------------------------------------------------------------------ Sub-Total for FERC-725A.......... .................... .............. .............. .................... 123,252 hrs., ................... $7,932,806. -------------------------------------------------------------------------------------------------------------------------------------------------------- [[Page 73990]] FERC-725Z -------------------------------------------------------------------------------------------------------------------------------------------------------- IRO-001-4 \66\................... 177 (RC & TOP)...... 1 177 0 hrs. $0........... 0 hrs. $0........... 0 hrs. $0. IRO-002-4........................ 11 (RC)............. 1 11 24 hrs., $1,592..... 264 hrs., $17,516... 24 hrs., $1,592. IRO-008-2........................ 11 (RC)............. 1 11 228 hrs., $15,127... 2,508 hrs., $166,405 228 hrs., $15,127. IRO-010-2........................ 11 (RC)............. 1 11 36 hrs., $2,388..... 396 hrs., $26,274... 36 hrs., $2,388. IRO-014-3........................ 11 (RC)............. 1 11 12 hrs., $796....... 132 hrs., $8,758.... 12 hrs., $796. IRO-017-1........................ 180 (RC, PC, & TP).. 1 180 218 hrs., $14,464... 39,240 hrs., 218 hrs., $14,464. $2,603,574. ------------------------------------------------------------------------------------------------ Sub-Total for FERC-725Z.......... .................... .............. .............. .................... 42,540 hrs., ................... $2,822,529.00. Retirement of current standards 457(RC, TOP, BA, 1 457 -223 hrs., -$14,796. -101,911 hrs., - -223 hrs., - currently in FERC-725A. TSP, LSE, PSE, & $6,761,794. $14,796. IA). NET TOTAL of NOPR in RM15-16..... .................... .............. .............. .................... 63,881 hrs., $3,993,540. -------------------------------------------------------------------------------------------------------------------------------------------------------- Title: FERC-725Z, Mandatory Reliability Standards: IRO Reliability Standards, and FERC-725A, Mandatory Reliability Standards for the Bulk- Power System. Action: Proposed Changes to Collections. OMB Control Nos: 1902-0276 (FERC-725Z); 1902-0244 (FERC-725A). Respondents: Business or other for-profit and not-for-profit institutions. Frequency of Responses: On-going. --------------------------------------------------------------------------- \64\ the number of respondents is the number of entities for which a change in burden from the current standards to the proposed exists, not the total number of entities from the current or proposed standards that are applicable. \65\ The estimated hourly costs (salary plus benefits) are based on Bureau of Labor Statistics (BLS) information, as of April 1, 2015, for an electrical engineer ($66.35/hour). These figures are available at http://blsgov/oes/current/naics3_221000.htm#17-0000. \66\ IRO-001-4 is a revised standard with no increase in burden. --------------------------------------------------------------------------- 72. Necessity of the Information and Internal review: The Commission has reviewed the requirements of Reliability Standards TOP- 001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO-002-4, IRO-008-2, IRO-010- 2, IRO-014-3, and IRO-017-1 and made a determination that the standards are necessary to implement section 215 of the FPA. The Commission has assured itself, by means of its internal review, that there is specific, objective support for the burden estimates associated with the information requirements. 73. Interested persons may obtain information on the reporting requirements by contacting the Federal Energy Regulatory Commission, Office of the Executive Director, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. 74. Comments on the requirements of this rule may also be sent to the Office of Management and Budget, Office of Information and Regulatory Affairs [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments should be sent by email to OMB at the following email address: oira_submission@omb.eop.gov. Please reference OMB Control Nos. 1902- 0276 (FERC-725Z) and 1902-0244 (FERC-725A)) in your submission. IV. Environmental Analysis 75. 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.\67\ 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.\68\ The actions approved herein fall within this categorical exclusion in the Commission's regulations. --------------------------------------------------------------------------- \67\ Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regulations Preambles 1986-1990 ] 30,783 (1987). \68\ 18 CFR 380.4(a)(2)(ii). --------------------------------------------------------------------------- V. Regulatory Flexibility Act Analysis 76. The Regulatory Flexibility Act of 1980 (RFA) generally requires a description and analysis of Proposed Rules that will have significant economic impact on a substantial number of small entities.\69\ The Small Business Administration's (SBA) Office of Size Standards develops the numerical definition of a small business.\70\ The SBA revised its size standard for electric utilities (effective January 22, 2014) to a standard based on the number of employees, including affiliates (from a standard based on megawatt hours).\71\ Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO- 014-3, and IRO-017-1 are expected to impose an additional burden on 196 entities (reliability coordinators, transmission operators, balancing authorities, transmission service providers, and planning authorities). Comparison of the applicable entities with the Commission's small business data indicates that approximately 82 of these entities are small entities that will be [[Page 73991]] affected by the proposed Reliability Standards.\72\ As discussed above, Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO- 002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 will serve to enhance reliability by imposing mandatory requirements for operations planning, system monitoring, real-time actions, coordination between applicable entities, and operational reliability data. The Commission estimates that each of the small entities to whom the proposed Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO- 002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 applies will incur costs of approximately $147,364 (annual ongoing) per entity. The Commission does not consider the estimated costs to have a significant economic impact on a substantial number of small entities. --------------------------------------------------------------------------- \69\ 5 U.S.C. 601-12. \70\ 13 CFR 121.101. \71\ SBA Final Rule on ``Small Business Size Standards: Utilities,'' 78 FR 77343 (Dec. 23, 2013). \72\ 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 NOPR, we are using a 750 employee threshold for each affected entity to conduct a comprehensive analysis. --------------------------------------------------------------------------- VI. 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 FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 78. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 79. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502- 6652 (toll free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502- 8371, TTY (202) 502-8659. Email the Public Reference Room at public.referenceroom@ferc.gov. VII. Effective Date and Congressional Notification 80. This final rule is effective January 26, 2016. 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: November 19, 2015. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2015-30110 Filed 11-25-15; 8:45 am] BILLING CODE 6717-01-P
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standards, the entities with market- 86. From the Commission’s Home service if it passes two indicative market
based rates which are affected by this Page on the Internet, this information is power screens: a pivotal supplier
Final Rule likely come under the available on eLibrary. The full text of analysis based on annual peak demand
following categories 117 with the this document is available on eLibrary of the relevant market, and a market
indicated thresholds (in terms of in PDF and Microsoft Word format for share analysis applied on a seasonal
number of employees 118): viewing, printing, and/or downloading. basis. There will be a rebuttable
• Hydroelectric Power Generation, To access this document in eLibrary, presumption that a Seller lacks
500 employees. type the docket number excluding the horizontal market power with respect to
• Fossil Fuel Electric Power last three digits of this document in the sales of operating reserve-spinning and
Generation, 750 employees. docket number field. operating reserve-supplemental services
• Nuclear Electric Power Generation, 87. User assistance is available for if the Seller passes these two indicative
750 employees. eLibrary and the Commission’s Web site market power screens and demonstrates
• Solar Electric Power Generation, during normal business hours from the in its market-based rate application how
250 employees. Commission’s Online Support at 202– the scheduling practices in its region
• Wind Electric Power Generation, 502–6652 (toll free at 1–866–208–3676) support the delivery of operating reserve
250 employees. or email at ferconlinesupport@ferc.gov, resources from one balancing authority
• Geothermal Electric Power or the Public Reference Room at (202) area to another. There will be a
Generation, 250 employees. 502–8371, TTY (202) 502–8659. Email rebuttable presumption that a Seller
• Biomass Electric Power Generation, the Public Reference Room at possesses horizontal market power with
250 employees. public.referenceroom@ferc.gov. respect to sales of energy, capacity,
• Other Electric Power Generation, VIII. Effective Date and Congressional
energy imbalance service, generation
250 employees. imbalance service, operating reserve-
Notification spinning service, operating reserve-
82. The categories for the applicable
entities have a size threshold ranging 88. The Final Rule is effective supplemental service, and primary
from 250 employees to 750 employees. February 25, 2016. The Commission has frequency response service if it fails
For the analysis in this Final Rule, we determined, with the concurrence of the either screen.
are using the threshold of 750 Administrator of the Office of * * * * *
employees for all categories. We Information and Regulatory Affairs of [FR Doc. 2015–30140 Filed 11–25–15; 8:45 am]
anticipate that a maximum of 82 percent OMB, that this Final Rule is not a BILLING CODE 6717–01–P
of the entities potentially affected by ‘‘major rule’’ as defined in section 351
this Final Rule are small. In addition, of the Small Business Regulatory
we expect that not all of those entities Enforcement Fairness Act of 1996. This DEPARTMENT OF ENERGY
will be able to or will choose to offer Final Rule is being submitted to the
primary frequency response service. Senate, House, Government Federal Energy Regulatory
83. Based on the estimates above in Accountability Office, and Small Commission
the Information Collection section, we Business Administration.
expect a one-time cost of $576 18 CFR Part 40
List of Subjects in 18 CFR Part 35
(including the burden cost related to [Docket No. RM15–16–000, Order No. 817]
Electric power rates; Electric utilities;
filing both the tariff and the EQR) for
Reporting and recordkeeping Transmission Operations Reliability
each entity that decides to offer primary
requirements. Standards and Interconnection
frequency response service.
84. The Commission does not By the Commission. Reliability Operations and
consider the estimated cost per small Issued: November 20, 2015. Coordination Reliability Standards
entity to impose a significant economic Nathaniel J. Davis, Sr., AGENCY: Federal Energy Regulatory
impact on a substantial number of small Deputy Secretary. Commission, Energy.
entities. Accordingly, the Commission In consideration of the foregoing, the ACTION: Final rule.
certifies that this Final Rule will not Commission amends Part 35, Chapter I,
have a significant economic impact on Title 18, Code of Federal Regulations, as SUMMARY: The Commission approves
a substantial number of small entities. follows. revisions to the Transmission
Operations and Interconnection
VII. Document Availability
PART 35—FILING OF RATE Reliability Operations and Coordination
85. In addition to publishing the full SCHEDULES AND TARIFFS Reliability Standards, developed by the
text of this document in the Federal North American Electric Reliability
Register, the Commission provides all ■ 1. The authority citation for Part 35 Corporation, which the Commission has
interested persons an opportunity to continues to read as follows: certified as the Electric Reliability
view and/or print the contents of this Authority: 16 U.S.C. 791a–825r, 2601– Organization responsible for developing
document via the Internet through the 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. and enforcing mandatory Reliability
Commission’s Home Page (http:// Standards. The Commission also directs
www.ferc.gov) and in the Commission’s ■ 2. In § 35.37, revise paragraph (c)(1) to
read as follows: NERC to make three modifications to
Public Reference Room during normal the standards within 18 months of the
business hours (8:30 a.m. to 5:00 p.m. § 35.37 Market power analysis required. effective date of the final rule.
mstockstill on DSK4VPTVN1PROD with RULES
Eastern time) at 888 First Street NE., * * * * * DATES: This rule will become effective
Room 2A, Washington, DC 20426. (c)(1) There will be a rebuttable January 26, 2016.
presumption that a Seller lacks FOR FURTHER INFORMATION CONTACT:
117 13 CFR 121.201, Sector 22, Utilities.
118 SBA’s
horizontal market power with respect to Robert T. Stroh (Legal Information),
regulations at 13 CFR 121.201 state that
‘‘[t]he number of employees . . . indicates the
sales of energy, capacity, energy Office of the General Counsel, Federal
maximum allowed for a concern and its affiliates imbalance service, generation imbalance Energy Regulatory Commission, 888
to be considered small.’’ service, and primary frequency response First Street NE., Washington, DC
VerDate Sep<11>2014 16:09 Nov 25, 2015 Jkt 238001 PO 00000 Frm 00035 Fmt 4700 Sfmt 4700 E:\FR\FM\27NOR1.SGM 27NOR1](https://thefederalregister.org/doc/80_FR_74205/page/1.svg)
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improvements over the currently- Standards, are designed to ensure that 10. In the NOPR, the Commission
effective TOP and IRO Reliability the bulk electric system is planned and explained that the proposed TOP and
Standards in (1) operating within SOLs operated in a coordinated manner to IRO Reliability Standards improve on
and IROLs; (2) outage coordination; (3) perform reliably under normal and the currently-effective standards by
situational awareness; (4) improved abnormal conditions. The proposed IRO providing a more precise set of
clarity and content in foundational Reliability Standards set forth the Reliability Standards addressing
definitions; and (5) requirements for responsibility and authority of operating responsibilities and
operational reliability data. NERC stated reliability coordinators to provide for improving the delineation of
that the proposed TOP and IRO reliable operations. NERC stated that, in responsibilities between applicable
Reliability Standards address the proposed IRO Reliability Standards, entities. The Commission also proposed
outstanding Commission directives reliability coordinators must continue to to find that NERC has adequately
relevant to the proposed TOP and IRO monitor SOLs in addition to their addressed the concerns raised by the
Reliability Standards. NERC stated that obligation in the currently effective Remand NOPR issued in November
the proposed Reliability Standards Reliability Standards to monitor and 2013.
provide a comprehensive framework for analyze IROLs. These obligations 11. In the NOPR, the Commission also
reliable operations, with important require reliability coordinators to have discussed the following specific matters
improvements to ensure the bulk the wide-area view necessary for and asked for further comment: (A)
electric system is operated within pre- situational awareness and provide them Possible inconsistencies in identifying
established limits while enhancing the ability to respond to system IROLs; (B) monitoring of non-bulk
situational awareness and strengthening conditions that have the potential to electric system facilities; (C) removal of
operations planning. NERC explained negatively affect reliable operations. the load-serving entity as an applicable
that the proposed Reliability Standards 8. NERC also proposed revised entity for proposed Reliability Standard
establish or revise requirements for definitions for ‘‘operational planning TOP–001–3; and (D) data exchange
operations planning, system monitoring, analysis’’ and ‘‘real-time assessment.’’ capabilities.
real-time actions, coordination between For all standards except proposed 12. Timely comments on the NOPR
applicable entities, and operational Reliability Standards TOP–003–3 and were filed by: NERC; Arizona Public
reliability data. NERC contended that IRO–010–2, NERC proposed the Service Company (APS), Bonneville
the proposed Reliability Standards help effective date to be the first day of the Power Administration (BPA), Dominion
to ensure that reliability coordinators first calendar quarter twelve months Resources Services, Inc. (Dominion), the
and transmission operators work after Commission approval. According Edison Electric Institute (EEI); Electric
together, and with other functional to NERC’s implementation plan, for Reliability Council of Texas, Inc.
entities, to operate the bulk electric proposed TOP–003–3, all requirements (ERCOT), Independent Electricity
system within SOLs and IROLs.11 NERC except Requirement R5 will become System Operator (IESO), ISO/RTOs,13
also provided explanations of how the effective on the first day of the first International Transmission Company
proposed Reliability Standards address calendar quarter nine months after the (ITC); Midcontinent Independent
the reliability issues identified in the date that the standard is approved. For System Operator, Inc., Northern Indiana
report on the Arizona-Southern proposed IRO–010–2, Requirements R1 Public Service Company (NIPSCO),
California Outages on September 8, and R2 would become effective on the Occidental Energy Ventures, LLC
2011, Causes and Recommendations first day of the first calendar quarter that (Occidental), Peak Reliability (Peak),
(‘‘2011 Southwest Outage Blackout is nine months after the date that the and Transmission Access Policy Study
Report’’). standard is approved. Proposed TOP– Group (TAPS).
7. NERC proposed three TOP 003–3, Requirement R5 and IRO–010–2,
Reliability Standards to replace the II. Discussion
Requirement R3 would become effective
existing suite of TOP standards. The on the first day of the first calendar 13. Pursuant to section 215(d) of the
proposed TOP Reliability Standards quarter twelve months after the date that FPA, we adopt our NOPR proposal and
generally address real-time operations the standard is approved. The reason for approve NERC’s revisions to the TOP
and planning for next-day operations, the difference in effective dates for and IRO Reliability Standards,
and apply primarily to the proposed TOP–003–3 and IRO–010–2 is including the associated definitions,
responsibilities and authorities of to allow applicable entities to have time violation risk factors, violation severity
transmission operators, with certain to properly respond to the data levels, and implementation plans, as
requirements applying to the roles and specification requests from their just, reasonable, not unduly
responsibilities of the balancing reliability coordinators, transmission discriminatory or preferential and in the
authority. Among other things, NERC operators, and/or balancing authorities. public interest. We note that all of the
stated that the proposed revisions to the commenters that address the matter
TOP Reliability Standards help ensure C. Notice of Proposed Rulemaking support, or do not oppose, approval of
that transmission operators plan and 9. On June 18, 2015, the Commission the revised suite of TOP and IRO
operate within all SOLs. The proposed issued a Notice of Proposed Rulemaking Reliability Standards. We determine
IRO Reliability Standards, which proposing to approve the TOP and IRO that NERC’s approach of consolidating
complement the proposed TOP Reliability Standards pursuant to FPA requirements and removing
section 215(d)(2), along with the two redundancies generally has merit and is
11 The NERC Glossary of Terms defines IROL as
new definitions referenced in the consistent with Commission policy
‘‘[a] System Operating Limit that, if violated, could
proposed standards, the assigned
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lead to instability, uncontrolled separation, or
Cascading outages that adversely impact the violation risk factors and violation Coordination Reliability Standards, 151 FERC ¶
reliability of the Bulk Electric System.’’ In turn, severity levels, and the proposed 61,236 (2015) (NOPR).
13 ISO/RTOs include Independent Electricity
NERC defines SOL as ‘‘[t]he value (such as MW, implementation plan for each
MVar, Amperes, Frequency or Volts) that satisfies System Operator, ISO New England Inc.,
the most limiting of the prescribed operating standard.12 Midcontinent Independent System Operator, New
criteria for a specified system configuration to York Independent System Operator, Inc., PJM
ensure operation within acceptable reliability 12 Transmission Operations Reliability Standards Interconnection LLC, and Southwest Power Pool,
criteria. . . .’’ and Interconnection Reliability Operations and Inc.
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![73980 Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
promoting increased efficiencies in Reliability Standards give reliability unplanned outage information to
Reliability Standards and reducing coordinators the authority to direct support operational planning analyses
requirements that are either redundant actions to prevent or mitigate instances and real-time assessments in the
with other currently-effective of exceeding IROLs because the primary operating procedures, processes, and
requirements or have little reliability decision-making authority for mitigating plans for activities that require
benefit.14 IROL exceedances is assigned to coordination with adjacent reliability
14. We also determine that the reliability coordinators while coordinators. We believe that these
proposed TOP and IRO Reliability transmission operators have the primary proposed standards adequately address
Standards should improve reliability by responsibility for mitigating SOL our concerns with respect to outage
defining an appropriate division of exceedances.16 coordination as outlined in the Remand
responsibilities between reliability 17. Furthermore, the revised NOPR. However, as we discuss below
coordinators and transmission definitions of operational planning we direct NERC to modify the standards
operators.15 The proposed TOP analysis and real-time assessment are to include transmission operator
Reliability Standards will eliminate critical components of the proposed monitoring of non-BES facilities, and to
multiple TOP standards, resulting in a TOP and IRO Reliability Standards and, specify that data exchange capabilities
more concise set of standards, reducing together with the definitions of SOLs, include redundancy and diverse
redundancy and more clearly IROLs and operating plans, work to routing; as well as testing of the
delineating responsibilities between ensure that reliability coordinators, alternate or less frequently used data
applicable entities. In addition, we find transmission operators and balancing exchange capability, within 18 months
that the proposed Reliability Standards authorities plan and operate the bulk of the effective date of this Final Rule.
provide a comprehensive framework as electric system within all SOLs and 20. Below we discuss the following
well as important improvements to IROLs to prevent instability, matters: (A) Possible inconsistencies of
ensure that the bulk electric system is uncontrolled separation, or cascading. identifying IROLs; (B) monitoring of
operated within pre-established limits In addition, the revised definitions of non-bulk electric system facilities; (C)
while enhancing situational awareness operational planning analysis and real- removal of the load-serving entity
and strengthening operations planning. time assessment address other concerns function from proposed Reliability
The TOP and IRO Reliability Standards raised in the Remand NOPR as well as Standard TOP–001–3; (D) data exchange
address the coordinated efforts to plan multiple recommendations in the 2011 capabilities, and (E) other issues raised
and reliably operate the bulk electric Southwest Outage Blackout Report.17 by commenters.
system under both normal and abnormal Outage Coordination A. Possible Inconsistences in IROLs
conditions. Across Regions
15. In the NOPR, the Commission 18. In the NOPR, the Commission
proposed to find that NERC adequately explained that NERC had addressed NOPR
addressed the concerns raised by the concerns raised in the Remand NOPR
21. In the NOPR, the Commission
Commission in the Remand NOPR with with respect to the IRO standards
noted that in Exhibit E (SOL White
respect to (1) the treatment of SOLs in regarding planned outage coordination.
Paper) of NERC’s petition, NERC stated
the proposed TOP Reliability Standards, In the Remand NOPR, the Commission
that, with regard to the SOL concept, the
and (2) the IRO standards regarding expressed concern with NERC’s
SOL White Paper brings ‘‘clarity and
planned outage coordination, both of proposal because Reliability Standards
consistency to the notion of establishing
which we address below. IRO–008–1, Requirement R3 and IRO–
SOLs, exceeding SOLs, and
010–1a (subjects of the proposed
Operational Responsibilities and implementing Operating Plans to
remand and now withdrawn by NERC)
Actions of SOLs and IROLs mitigate SOL exceedances.’’ 19 The
did not require the coordination of
Commission further noted that IROLs,
16. In the Remand NOPR, the outages, noting that outage coordination
as defined by NERC, are a subset of
Commission expressed concern that the is a critical reliability function that
SOLs that, if violated, could lead to
initially proposed (now withdrawn) should be performed by the reliability
instability, uncontrolled separation, or
TOP standards did not have a coordinator.18
19. In the NOPR, the Commission cascading outages that adversely impact
requirement for transmission operators the reliability of the bulk electric
to plan and operate within all SOLs. noted that Reliability Standard IRO–
017–1, Requirement R1 requires each system. The Commission agreed with
The Commission finds that the TOP NERC that clarity and consistency are
Reliability Standards that NERC reliability coordinator to develop,
implement and maintain an outage important with respect to establishing
subsequently proposed address the and implementing operating plans to
Commission’s Remand NOPR concerns coordination process for generation and
transmission outages within its mitigate SOL and IROL exceedances.
by requiring transmission operators to However, the Commission noted that
plan and operate within all SOLs, and reliability coordinator area.
Additionally, Reliability Standard IRO– NERC, in its 2015 State of Reliability
to monitor and assess SOL conditions report, had stated that the Western
within and outside a transmission 014–3, Requirement R1, Part 1.4
requires reliability coordinators to Interconnection reliability coordinator
operator’s area. Further, the TOP/IRO definition of an IROL has additional
Standards approved herein address the include the exchange of planned and
criteria that may not exist in other
possibility that additional SOLs could 16 See Remand NOPR, 145 FERC ¶ 61,158 at P 85. reliability coordinator areas.20 The
develop or occur in the same-day or Further, currently-effective Reliability Standard
real-time operational time horizon and,
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IRO–009–1, Requirement R4 states that ‘‘[w]hen 19 NERC Petition, Exhibit E, ‘‘White Paper on
therefore, would pose an operational actual system conditions show that there is an System Operating Limit Definition and Exceedance
risk to the interconnected transmission instance of exceeding an IROL in its Reliability Clarification’’ at 1.
Coordinator Area, the Reliability Coordinator shall, 20 NOPR, 151 FERC ¶ 61,236 at P 51, citing NERC
network if not addressed. Likewise, the without delay, act or direct others to act to mitigate 2015 State of Reliability report at 44, available at
the magnitude and duration of the instance of www.nerc.com. See also WECC Reliability
14 SeeOrder No. 788, 145 FERC ¶ 61,147. exceeding that IROL within the IROL’s Tv.’’ Coordination System Operating Limits
15 See, 17 NERC Petition at 17–18.
e.g., Order No. 748, 134 FERC ¶ 61,213, Methodology for the Operations Horizon, Rev. 7.0
at PP 39–40. 18 Remand NOPR, 145 FERC ¶ 61,158 at P 90. (effective March 3, 2014) at 18 (stating that ‘‘SOLs
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because ‘‘non-bulk electric system However, we are concerned that in some section 215(d)(5) of the FPA, we direct
facilities’’ fall outside the scope of the instances the absence of real-time NERC to revise Reliability Standard
NERC Reliability Standards, use of this monitoring of non-BES facilities by the TOP–001–3, Requirement R10 to require
terminology should be avoided. ERCOT transmission operator within and real-time monitoring of non-BES
advocates for the Commission to permit outside its TOP area as necessary for facilities. We believe this is best
monitoring of other sub-100 kV facilities determining SOL exceedances in accomplished by adopting language
to be undertaken as agreed to between proposed TOP–001–3, Requirement R10 similar to Reliability Standard IRO–
the reliability coordinator and the creates a reliability gap. As the 2011 002–4, Requirement R3, which requires
transmission operator. ERCOT and ISO/ Southwest Outage Report indicates, the reliability coordinators to monitor non-
RTOs suggest that the phrase ‘‘non-BES Regional Entity ‘‘should lead other bulk electric system facilities to the
facilities’’ in Reliability Standard IRO– entities, including TOPs and BAs, to extent necessary. NERC can develop an
002–4, Requirement R3 should be ensure that all facilities that can equally efficient and effective
replaced with ‘‘sub-100 kV facilities adversely impact BPS reliability are alternative that addresses our
identified as part of the BES through the either designated as part of the BES or concerns.32
BES exception process or as otherwise otherwise incorporated into planning 36. To be clear, we are not directing
agreed to between the Reliability and operations studies and actively that all current ‘‘non-BES’’ facilities that
Coordinator and Transmission monitored and alarmed in [real-time a transmission operator considers
Operator’’ and the phrase ‘‘non-BES contingency analysis] systems.’’ 29 Such worthy of monitoring also be included
data’’ in Reliability Standards IRO–010– monitoring of non-BES facilities could in the bulk electric system. We believe
2 (Requirement R1.1) and TOP–003–3 provide a ‘‘stop gap’’ during the period that such monitoring may result in some
(Requirement R1.1) should be replaced where a sub-100 kV facility undergoes facilities becoming part of the bulk
with ‘‘data from sub-100 kV facilities analysis as a possible BES facility, electric system through the exception
identified as part of the BES through the allowing for monitoring in the interim process; however it is conceivable that
BES exception process, as otherwise until such time the non-bulk electric others may remain non-BES because
requested by the Responsible Entity, or system facilities become ‘‘BES they are occasional system operating
as agreed to between the Transmission Facilities’’ or the transmission operator limit exceedance performers that may
Operator and the Responsible Entity.’’ 26 determines that a non-bulk electric not qualify as a candidate for inclusion
system facility is no longer needed for in the BES definition.
34. ITC does not support the
monitoring to determine a system C. Removal of Load-Serving Entity
Commission’s proposal. ITC states that
operating limit exceedance in its area.30 Function From TOP–001–3
transmission operators are required to
We believe that the operational
incorporate any non-bulk electric NOPR
planning analyses and real-time
system data into operational planning
assessments performed by the 37. NERC proposed the removal of the
analysis and real-time assessments and
transmission operators as well as the load-serving entity function from
monitoring, which therefore requires
reliability coordinators will serve as the proposed Reliability Standard, TOP–
transmission operators to regularly
basis for determining which ‘‘non-BES 001–3, Requirements R3 through R6, as
review their models to identify facilities’’ require monitoring to
impacting non-bulk electric system a recipient of an operating instruction
determine system operating limit and from a transmission operator or
facilities. Conversely, ITC explains that interconnection reliability operating
conducting a one-time or periodic balancing authority. NERC
limit exceedances. In addition, we supplemented its initial petition with
review and analysis of a transmission believe that monitoring of certain non-
operator’s model ignores the fact that additional explanation for the removal
BES facilities that are occasional system of the load-serving entity function from
changes in system conditions can cause operating limit exceedance performers
the list of impacting non-bulk electric proposed Reliability Standard TOP–
may not qualify as a candidate for 001–3.33 NERC explained that the
system facilities to change frequently. inclusion in the BES definition, yet proposed standard gives transmission
Commission Determination should be monitored for reliability operators and balancing authorities the
purposes.31 Accordingly, pursuant to authority to direct the actions of certain
35. We agree with NERC, TAPS, and
other functional entities by issuing an
EEI that the BES exception process can Bulk Electric System Element (e.g., a line, a
operating instruction to maintain
be a mechanism for identifying non-BES generator, a shunt compensator, transformer, etc.)’’
29 NOPR, 151 FERC ¶ 61,236 at P 55, citing reliability during real-time operations.
facilities to be included in the BES
Recommendation 17 of the 2011 Southwest Outage 38. In the NOPR, the Commission
definition.27 Indeed, once a non-BES Blackout Report (emphasis added). noted that NERC was required to make
facility is included in the BES definition 30 NERC’s BES Frequently Asked Questions,
a compliance filing in Docket No. RR15–
under the BES exception process, the Version 1.6, February 25, 2015, Section 5.6. ‘‘How
4–000, regarding NERC’s Risk-Based
‘‘non-BES facility’’ becomes a BES long will the process take?’’ at page 14 states: ‘‘In
general, assuming a complete application, no Registration initiative, and that the
‘‘Facility’’ under TOP–001–3, appeals, and taking the allotted time for each Commission’s decision on that filing
Requirement R10, and real-time subtask, the process could take up to 11.5 months,
monitoring is required of ‘‘Facilities.’’ 28 but is anticipated to be shorter for less complicated 32 Reliability Standard IRO–002–4, Requirement
Exception Requests. If the Exception Request is
appealed to the NERC Board of Trustees R3 states: Each Reliability Coordinator shall
26 See also ISO/RTOs Comments at 4–6. Compliance Committee pursuant to Section 1703 of monitor Facilities, the status of Special Protection
27 NERC TOP/IRO Petition, Exh. G at 9 states in Systems, and non-BES facilities identified as
the NERC Rules of Procedure, the process could
response to the 2011 Southwest Outage take an additional 8.5 months, totaling 20 months. necessary by the Reliability Coordinator, within its
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Recommendation #17, ‘‘If a non-BES facility This does not include timing related to an appeal Reliability Coordinator Area and neighboring
impacts the BES, such as by contributing to an SOL to the applicable legal authority or Applicable Reliability Coordinator Areas to identify any
or IROL, then the SDT expects that facility to be Governmental Authority. A Regional Entity, upon System Operating Limit exceedances and to
incorporated into the BES through the official BES consultation with NERC, may extend the time frame determine any Interconnection Reliability
Exception Process and it would be covered in of the substantive review process. . . .’’ http:// Operating Limit exceedances within its Reliability
proposed TOP–001–3, Requirement R10, Parts 10.1 www.nerc.com/pa/RAPA/BES%20DL/ Coordinator Area.
and 10.2 by use of the defined term ‘Facilities.’ ’’ BES%20FAQs.pdf. 33 The Commission also notes that Reliability
28 NERC Glossary of Terms defines Facility as: ‘‘A 31 See, e.g., NERC TOP/IRO Petition at 18 and 27– Standards TOP–003–3 and IRO–010–2 also include
set of electrical equipment that operates as a single 28. ‘‘load-serving entity’’ as an applicable entity.
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either explicitly or implicitly require require redundancy and diverse routing. Comments
responsible entities to ensure In addition, we direct NERC to clarify
availability of data and data exchange that ‘‘redundant infrastructure’’ for 50. Commenters assert that the
capabilities. ERCOT states that, should system monitoring in Reliability existing standards have sufficient
the Commission seek to provide further Standards IRO–002–4, Requirement R4 testing requirements. NERC points to
clarification on this issue, such is equivalent to redundant and diversely Reliability Standard EOP–008–1,
clarification should be consistent with routed data exchange capabilities. Requirement R7, which requires that
existing explicit requirements regarding applicable entities conduct annual tests
48. Further, we disagree with
the redundancy of data exchange of their operating plan that
commenter arguments that Reliability
capabilities, such as Requirement R4 of demonstrates, among other things,
Standard EOP–008–1 provides
Reliability Standard IRO–002–4. backup functionality. Similarly, EEI
46. ISOs/RTOs and ERCOT explain alternatives to data exchange
redundancy and diverse routing. The cites EOP–008–1 Requirements R1,
the suite of currently-effective standards R1.2, R1.2.2, R7 and EOP–001–2.1b
and the proposed TOP and IRO NERC standard drafting team that
developed the COM standards Requirements R6 and R6.1 as providing
standards establish performance-based specific requirements for maintaining
requirements for reliability addressed this issue in the standards
development process, responding to a and testing of data exchange
coordinators, balancing authorities, and
commenter seeking clarification on the capabilities. ITC suggests that NERC’s
transmission operators, that create the
need for those entities to have diverse relationship between communication proposed Standard TOP–001–3 provides
and redundantly routed data capabilities, alternative communication ample assurance that the data exchange
communication systems. In the event of capabilities, primary control center capabilities are regularly tested and also
a failure of data communications, ISOs/ functionality and backup control center points to Reliability Standards EOP–
RTOs explain that the functional entity functionality. The standard drafting 001–2.1b and EOP–008–1 which require
should be able to rely on the redundant team responded that ‘‘Interpersonal entities, including those covered by
and diversely routed voice capabilities Communication and Alternative TOP–001–3, to maintain reliable back-
required in the COM standards. Interpersonal Communication are not up data exchange capability as
related to EOP–008,’’ even though necessary to ensure reliable BES
Commission Determination Reliability Standard EOP–008–1 operations, and require that such
47. We agree with NERC and other Requirement R1 applies equally to data capabilities be thoroughly and regularly
commenters that there is a reliability communications and voice tested.
need for the reliability coordinator, communications.41 To the extent the
transmission operator and balancing standard drafting team asserted that Commission Determination
authority to have data exchange Reliability Standard EOP–008 did not
capabilities that are redundant and 51. We agree with NERC and other
supplant the redundancy requirements commenters that there is a reliability
diversely routed. However, we are of the COM Reliability Standards, we
concerned that the TOP and IRO need for the reliability coordinator,
believe the same is true for data
Standards do not clearly address transmission operator and balancing
communications. Redundancy for data
redundancy and diverse routing so that authority to test alternate data exchange
communications is no less important
registered entities will unambiguously capabilities. However, we are not
than the redundancy explicitly required
recognize that they have an obligation to in the COM standards for voice persuaded by the commenters’
address redundancy and diverse routing communications. assertions that the need to test is
as part of their TOP and IRO compliance implied in the TOP and IRO Standards.
obligations. NERC’s comprehensive 2. Testing of the Alternate or Less Rather, we determine that testing of
approach to establishing Frequently Used Data Exchange alternative data exchange capabilities is
communications capabilities necessary Capability important to reliability and should not
to maintain reliability in the COM be left to what may or may not be
NOPR
standards is applicable to data exchange implied in the standards.42 Therefore,
capabilities at issue here.40 Therefore, 49. In the NOPR, the Commission pursuant to section 215(d)(5) of the
pursuant to section 215(d)(5) of the expressed concern that the proposed FPA, we direct NERC to develop a
FPA, we direct NERC to modify TOP and IRO Reliability Standards do modification to the TOP and IRO
Reliability Standards TOP–001–3, not appear to address testing standards that addresses a data
Requirements R19 and R20 to include requirements for alternative or less exchange capability testing framework
the requirement that the data exchange frequently used mediums for data
capabilities of the transmission for the data exchange capabilities used
exchange to ensure they would properly in the primary control centers to test the
operators and balancing authorities function in the event that the primary or alternate or less frequently used data
40 See, e.g, Order No. 808, 151 FERC ¶ 61,039 at
more frequently used data exchange exchange capabilities of the reliability
P 8: ‘‘NERC stated in its [COM] petition that
capabilities failed. Accordingly, the coordinator, transmission operator and
Reliability Standard COM–001–2 establishes Commission sought comment on balancing authority. We believe that the
requirements for Interpersonal Communication whether and how the TOP and IRO structure of Reliability Standard COM–
capabilities necessary to maintain reliability. NERC Reliability Standards address the testing
explained that proposed Reliability Standard COM– 001–2, Requirement R9 could be a
001–2 applies to reliability coordinators, balancing of alternative or less frequently used
data exchange capabilities for the
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authorities, transmission operators, generator 42 In NERC’s COM Petition, Exh. M,
operators, and distribution providers. The proposed transmission operator, balancing (Consideration of Comments, Index to Questions,
Reliability Standard includes eleven requirements authority and reliability coordinator.
and two new defined terms, ‘‘Interpersonal Comments and Responses) at 35, the standard
Communication’’ and ‘‘Alternative Interpersonal drafting team stated that the ‘‘requirement [COM–
Communication,’’ that, according to NERC, 41 See NERC COM Petition, Exh. M, 001–2, Requirement R9 which addresses testing of
collectively provide a comprehensive approach to (Consideration of Comments on Initial Ballot, alternative interpersonal communication] applies to
establishing communications capabilities necessary February 25–March 7, 2011) at 30 (emphasis the primary control center’’ and ‘‘EOP–008 applies
to maintain reliability.’’ added). to the back up control center.’’
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and balancing authorities. Also, NIPSCO contends that there are no clear through R6 and IRO-001-4,
Reliability Standard IRO-008-2, requirements addressing potential Requirements R1 through R3 are all
Requirement R3 requires that the conflicts between operating plans, no requirements associated with the
reliability coordinator notify impacted clear requirements authorizing the issuance or compliance of operating
entities identified in its operating plan issuance of a directive to address issues instructions. In all nine requirements,
as to their role in such plan. Based on identified in next-day planning, and no the defined time horizon is ‘‘same-day
the notification and coordination clear requirement to comply with any operations’’ and ‘‘real-time
processes of Reliability Standards TOP- directive so issued. NIPSCO is operations.’’ 50 Accordingly, we deny
002-4 (for the transmission operator and concerned that this raises the possibility NIPSCO’s request on this issue.
balancing authority) and IRO-008-2 (for that potential next-day problems
4. Updating Operational Planning
the reliability coordinator) for next-day identified in the operational planning
Analyses and Real-Time Assessments
operating plans, as well as the fact that analyses may not get resolved in the
the reliability coordinator is the entity next-day planning period because the 62. NIPSCO is concerned that the
that is the highest level of authority who reliability coordinator’s authority to proposed Reliability Standards are not
is responsible for the reliable operation issue operating instructions is limited to clear as to whether updates or
of the bulk electric system, we believe real-time operation. According to additional analyses are required.
that the reliability coordinator has the NIPSCO, this limitation undermines NIPSCO points to Reliability Standards
authority and necessary next-day some of the usefulness of the next-day IRO-008-2 and TOP-002-4, which
operational information to resolve any planning and the performance of require reliability coordinators to
next-day operational issues within its operational planning analyses. perform—and transmission operators
reliability coordinator area. and balancing authorities to have—an
Commission Determination operational analysis for the next-day,
Accordingly, we deny NIPSCO’s
request. 60. We do not share NIPSCO’s but do not specify when such analysis
concern. Rather, we believe that, must be performed or if it needs to be
3. Reliability Coordinator Authority in because the reliability coordinator is updated in next-day planning based on
Next-Day Operations and the Issuance required to have a coordinated operating any change in inputs. Similarly,
of Operating Instructions plan for the next-day operations, the NIPSCO asserts that the proposed
reliability coordinator will perform its Reliability Standards require the
59. NIPSCO is concerned with the
task of developing a coordinated performance of a real-time assessment
elimination of the explicit requirement
operating plan in good faith, with inputs every 30 minutes but do not address the
in currently-effective Reliability
not only from its transmission operators need to potentially update operating
Standard IRO-004-2 that each
and balancing authorities, but also from plans based on changes in system
transmission operator, balancing
its neighboring reliability conditions (including unplanned
authority, and transmission provider
coordinators.48 A reliability coordinator outages of protection system
comply with the directives of a
has a wide-area view and bears the degradation) and do not require the
reliability coordinator based on next-
ultimate responsibility to maintain the performance of additional real-time
day assessment in the same manner as
reliability within its footprint, assessments or other studies with more
would be required in real-time operating
‘‘including the authority to prevent or frequency based on changes in system
conditions. NIPSCO claims that, while
mitigate emergency operating situations conditions. NIPSCO explains that it is
the Reliability Standards appear to
in both next-day analysis and real-time not clear if or when, based on the
address the Commission’s concerns
operations.’’ 49 operational planning analysis results,
regarding directives issued in other than
61. In addition, we do not agree with some type of additional study or
emergency conditions through the
NIPSCO’s claim that operating analysis would need to be undertaken
integration of the term ‘‘operating
instructions are ‘‘clearly limited to real- prior to the development of an operating
instruction,’’ the standards only allow
time operations.’’ The phrase ‘‘real-time plan. According to NIPSCO, the text of
for the issuance of directives in real-
operation’’ in the definition of operating the requirements and the definition do
time. NIPSCO points to Reliability
instruction as emphasized by NIPSCO not specifically require additional
Standard TOP-001-3, Requirements R1
applies to the entity that issues the studies; however, it seems that when
and R2, and IRO-001-4, Requirement R1,
operating instruction which is issues associated with protection system
where transmission operators, balancing
‘‘operating personnel responsible for the degradation or outages are identified,
authorities, and reliability coordinators
Real-time operation.’’ The definition of further study of these issues would be
are explicitly given authority and
operating instruction is ‘‘[a] command required and/or additional analyses
responsibility to issue operating
by operating personnel responsible for required to update results as protection
instructions to address reliability in
the Real-time operation of the system status or transmission or
their respective areas. NIPSCO states
interconnected Bulk Electric System. generation outages change.
that ‘‘operating instruction’’ is ‘‘clearly
. . .’’ In addition, the time horizons
limited to real-time operations’’ as it Commission Determination
associated with the issuance of or
underscored below: 63. We do not share NIPSCO’s
compliance with an operating
A command by operating personnel instruction are not found in the concern. Reliability Standards IRO-008-
responsible for the Real-time operation of the definition of operating instructions, but 2 and TOP-002-4 require reliability
interconnected Bulk Electric System to found in the individual requirement(s) coordinators to perform and
change or preserve the state, status, output,
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applicable to issuing an operating
or input of an Element of the Bulk Electric instruction. For example, Reliability 50 NERC’s ‘‘Time Horizons’’ document defines
System or Facility of the Bulk Electric Standard TOP-001-3, Requirements R1 ‘‘Same-Day Operations’’ time horizon as ‘‘routine
System. (A discussion of general information actions required within the timeframe of a day, but
not real-time’’ and defines ‘‘Real-Time Operations’’
and of potential options or alternatives to 48 See Reliability Standards IRO-008-2,
time horizon as ‘‘actions required within one hour
resolve Bulk Electric System operating Requirements R1 and R2, and IRO-014-3, or less to preserve the reliability of the bulk electric
concerns is not a command and is not Requirement R1. system.’’ See http://www.nerc.com/files/
considered an Operating Instruction.) 49 See supra n. 46. Time_Horizons.pdf.
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addition, ‘‘transient stability ratings’’ are definition is an evaluation of system requirements of a rule will not be
included in the SOL definition. Further, conditions to assess existing and penalized for failing to respond to these
in the SOL White Paper, NERC states potential operating conditions. The real- collections of information unless the
that the ‘‘concept of SOL determination time assessment provides the collections of information display a
is not complete without looking at the transmission operator with the valid OMB control number.
approved NERC FAC standards FAC- necessary knowledge of the system Public Reporting Burden: The number
008-3, FAC-011-2 and FAC-014-2.’’ 57 operating state to initiate an operating of respondents below is based on an
Specific to IESO’s concerns of plan, as specified in Requirement R14, estimate of the NERC compliance
establishing transient stability limits, we when necessary to mitigate an
registry for the balancing authority,
agree with NERC that approved exceedance of SOLs. In addition, the
transmission operator, generator
Reliability Standard FAC-011-2, SOL White Paper provides technical
operator, distribution provider,
Requirement R2 requires that the guidance for including timelines in the
generator owner, load-serving entity,
reliability coordinator’s SOL required operating plans to return the
system to within prescribed ratings and purchasing-selling entity, transmission
methodology include a requirement that service provider, interchange authority,
SOLs provide a certain level of bulk limits.60 Accordingly, we conclude that
the establishment of transient stability transmission owner, reliability
electric system performance including coordinator, planning coordinator, and
among other things, that the ‘‘BES shall operating limits is adequately addressed
collectively through proposed transmission planner functions. The
demonstrate transient, dynamic and Commission based its paperwork
voltage stability’’ and that ‘‘all Facilities Reliability Standard TOP-001-3,
currently-effective Reliability Standards burden estimates on the NERC
shall be within their . . . stability compliance registry as of May 15, 2015.
limits’’ for both pre- and post- FAC-011-2 and FAC-014-2 and NERC’s
Glossary of Terms definition of SOLs.61 According to the registry, there are 11
contingency conditions.58 In addition, reliability coordinators, 99 balancing
we note that currently-effective III. Information Collection Statement authorities, 450 distribution providers,
Reliability Standard FAC-011-2, 71. The collection of information 839 generator operators, 80 purchasing-
Requirement R2.1 states that ‘‘[i]n the contained in this Final Rule is subject selling entities, 446 load-serving
determination of SOLs, the BES to review by the Office of Management entities, 886 generator owners, 320
condition used shall reflect current or and Budget (OMB) regulations under transmission owners, 24 interchange
expected system conditions and shall section 3507(d) of the Paperwork authorities, 75 transmission service
reflect changes to system topology such Reduction Act of 1995 (PRA).62 OMB’s providers, 68 planning coordinators,
as Facility outages.’’ 59 regulations require approval of certain 175 transmission planners and 171
70. With respect to Reliability informational collection requirements transmission operators. The estimates
Standard TOP-001-3, we agree with imposed by agency rules.63 Upon are based on the change in burden from
NERC that Requirement R13 specifies approval of a collection(s) of the current standards to the standards
that transmission operators must information, OMB will assign an OMB approved in this Final Rule. The
perform a real-time assessment at least control number and an expiration date. following table illustrates the burden to
once every 30 minutes, which by Respondents subject to the filing be applied to the information collection:
RM15–16–000 (TRANSMISSION OPERATIONS RELIABILITY STANDARDS, INTERCONNECTION RELIABILITY OPERATIONS AND
COORDINATION RELIABILITY STANDARDS)
Annual Total annual
Number of number of Total number Average burden & Cost per respond-
burden hours &
respondents 64 responses per of responses cost per response 65 ent ($)
total annual cost
respondent
(1) (2) (1) * (2) = (3) (4) (3) * (4) = (5) (5) ÷ (1)
FERC–725A
TOP–001–3 ........... 196 (TOP & BA) .... 1 196 96 hrs., $6,369 .......... 18,816 hrs., 96 hrs, $6,369.
$1,248,441.
TOP–002–4 ........... 196 (TOP & BA) .... 1 196 284 hrs., $18,843 ...... 55,664 hrs., 284 hrs., $18,843.
$3,693,306.
TOP–003–3 ........... 196 (TOP & BA) .... 1 196 230 hrs., $15,260 ...... 45,080 hrs., 230 hrs., $15,260.
$2,991,058.
Sub-Total for ............................... ........................ ........................ ................................... 123,252 hrs.,
FERC–725A. $7,932,806.
determining compliance. NIPSCO requests that any exceedances. Guidelines are illustrative but not 58 Id. at 2. See also Reliability Standard FAC-011-
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substantive content that is treated as containing mandatory and enforceable compliance 2, Requirement R2.
enforceable compliance requirements be filed with requirements. See, e.g. North American Electric 59 Reliability Standard FAC-011-1, Requirement
the Commission for approval. NERC developed the Reliability Corp., 143 FERC ¶ 61,271, at P 15 (2013). R2.1 (emphasis added).
SOL White Paper as a guidance document which 60 NERC Petition at 57–58.
Accordingly, we see no need for further revisions
provides links between relevant reliability
standards and reliability concepts to establish a to the Reliability Standards to incorporate the SOL 61 See Reliability Standard FAC-014-2,
common understanding necessary for developing White Paper as requested by NIPSCO. Requirement R2.
57 NERC Petition, Exh. E at 1. 62 44 U.S.C. 3507(d) (2012).
effective operating plans to mitigate SOL
63 5 CFR 1320.11.
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![73990 Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
RM15–16–000 (TRANSMISSION OPERATIONS RELIABILITY STANDARDS, INTERCONNECTION RELIABILITY OPERATIONS AND
COORDINATION RELIABILITY STANDARDS)—Continued
Annual Total annual
Number of number of Total number Average burden & burden hours & Cost per respond-
respondents 64 responses per of responses cost per response 65 total annual cost ent ($)
respondent
(1) (2) (1) * (2) = (3) (4) (3) * (4) = (5) (5) ÷ (1)
FERC–725Z
IRO–001–4 66 ........ 177 (RC & TOP) ... 1 177 0 hrs. $0 .................... 0 hrs. $0 ................ 0 hrs. $0.
IRO–002–4 ............ 11 (RC) ................. 1 11 24 hrs., $1,592 .......... 264 hrs., $17,516 .. 24 hrs., $1,592.
IRO–008–2 ............ 11 (RC) ................. 1 11 228 hrs., $15,127 ...... 2,508 hrs., 228 hrs., $15,127.
$166,405.
IRO–010–2 ............ 11 (RC) ................. 1 11 36 hrs., $2,388 .......... 396 hrs., $26,274 .. 36 hrs., $2,388.
IRO–014–3 ............ 11 (RC) ................. 1 11 12 hrs., $796 ............. 132 hrs., $8,758 .... 12 hrs., $796.
IRO–017–1 ............ 180 (RC, PC, & 1 180 218 hrs., $14,464 ...... 39,240 hrs., 218 hrs., $14,464.
TP). $2,603,574.
Sub-Total for ............................... ........................ ........................ ................................... 42,540 hrs.,
FERC–725Z. $2,822,529.00.
Retirement of cur- 457(RC, TOP, BA, 1 457 ¥223 hrs., ¥$14,796 ¥101,911 hrs., ¥223 hrs.,
rent standards TSP, LSE, PSE, ¥$6,761,794. ¥$14,796.
currently in & IA).
FERC–725A.
NET TOTAL of ............................... ........................ ........................ ................................... 63,881 hrs.,
NOPR in RM15– $3,993,540.
16.
Title: FERC–725Z, Mandatory requirements by contacting the Federal regulations being amended.68 The
Reliability Standards: IRO Reliability Energy Regulatory Commission, Office actions approved herein fall within this
Standards, and FERC–725A, Mandatory of the Executive Director, 888 First categorical exclusion in the
Reliability Standards for the Bulk-Power Street NE., Washington, DC 20426 Commission’s regulations.
System. [Attention: Ellen Brown, email:
Action: Proposed Changes to V. Regulatory Flexibility Act Analysis
DataClearance@ferc.gov, phone: (202)
Collections. 502–8663, fax: (202) 273–0873]. 76. The Regulatory Flexibility Act of
OMB Control Nos: 1902–0276 (FERC– 74. Comments on the requirements of 1980 (RFA) generally requires a
725Z); 1902–0244 (FERC–725A). this rule may also be sent to the Office description and analysis of Proposed
Respondents: Business or other for- of Management and Budget, Office of Rules that will have significant
profit and not-for-profit institutions. Information and Regulatory Affairs economic impact on a substantial
Frequency of Responses: On-going. [Attention: Desk Officer for the Federal number of small entities.69 The Small
72. Necessity of the Information and Energy Regulatory Commission]. For Business Administration’s (SBA) Office
Internal review: The Commission has security reasons, comments should be of Size Standards develops the
reviewed the requirements of Reliability sent by email to OMB at the following numerical definition of a small
Standards TOP–001–3, TOP–002–4, email address: business.70 The SBA revised its size
TOP–003–3, IRO–001–4, IRO–002–4, oira_submission@omb.eop.gov. Please standard for electric utilities (effective
IRO–008–2, IRO–010–2, IRO–014–3, reference OMB Control Nos. 1902–0276 January 22, 2014) to a standard based on
and IRO–017–1 and made a (FERC–725Z) and 1902–0244 (FERC– the number of employees, including
determination that the standards are 725A)) in your submission. affiliates (from a standard based on
necessary to implement section 215 of megawatt hours).71 Reliability
the FPA. The Commission has assured IV. Environmental Analysis Standards TOP–001–3, TOP–002–4,
itself, by means of its internal review, 75. The Commission is required to TOP–003–3, IRO–001–4, IRO–002–4,
that there is specific, objective support prepare an Environmental Assessment IRO–008–2, IRO–010–2, IRO–014–3,
for the burden estimates associated with or an Environmental Impact Statement and IRO–017–1 are expected to impose
the information requirements. for any action that may have a an additional burden on 196 entities
73. Interested persons may obtain significant adverse effect on the human (reliability coordinators, transmission
information on the reporting environment.67 The Commission has operators, balancing authorities,
categorically excluded certain actions transmission service providers, and
64 the number of respondents is the number of
from this requirement as not having a planning authorities). Comparison of the
entities for which a change in burden from the
current standards to the proposed exists, not the significant effect on the human applicable entities with the
total number of entities from the current or environment. Included in the exclusion Commission’s small business data
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proposed standards that are applicable. are rules that are clarifying, corrective, indicates that approximately 82 of these
65 The estimated hourly costs (salary plus
or procedural or that do not entities are small entities that will be
benefits) are based on Bureau of Labor Statistics
(BLS) information, as of April 1, 2015, for an substantially change the effect of the
68 18CFR 380.4(a)(2)(ii).
electrical engineer ($66.35/hour). These figures are
69 5
U.S.C. 601–12.
available at http://blsgov/oes/current/ 67 Regulations
Implementing the National
naics3_221000.htm#17-0000. Environmental Policy Act of 1969, Order No. 486, 70 13 CFR 121.101.
66 IRO–001–4 is a revised standard with no 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 71 SBA Final Rule on ‘‘Small Business Size
increase in burden. Regulations Preambles 1986–1990 ¶ 30,783 (1987). Standards: Utilities,’’ 78 FR 77343 (Dec. 23, 2013).
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![Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations 73991
affected by the proposed Reliability VII. Effective Date and Congressional § 776.94 is more appropriate as an
Standards.72 As discussed above, Notification appendix, and this correction amends
Reliability Standards TOP–001–3, TOP– 80. This final rule is effective January the CFR accordingly, redesignating
002–4, TOP–003–3, IRO–001–4, IRO– 26, 2016. The Commission has § 776.94 as an appendix to subpart D. In
002–4, IRO–008–2, IRO–010–2, IRO– determined, with the concurrence of the addition, because § 776.94 becomes an
014–3, and IRO–017–1 will serve to Administrator of the Office of appendix to its subpart, DoN is
enhance reliability by imposing Information and Regulatory Affairs of redesignating § 776.95 in the November
mandatory requirements for operations OMB, that this rule is not a ‘‘major rule’’ 4 rule as § 776.94.
planning, system monitoring, real-time as defined in section 351 of the Small Correction
actions, coordination between Business Regulatory Enforcement In FR Rule Doc. 2015–26982
applicable entities, and operational Fairness Act of 1996. appearing on page 68388 in the Federal
reliability data. The Commission By the Commission. Register of Wednesday, November 4,
estimates that each of the small entities Issued: November 19, 2015. 2015, the following corrections are
to whom the proposed Reliability Nathaniel J. Davis, Sr., made:
Standards TOP–001–3, TOP–002–4, Deputy Secretary. ■ 1. On page 68390, in the first column,
TOP–003–3, IRO–001–4, IRO–002–4, third line, revise ‘‘776.94 Outside Law
[FR Doc. 2015–30110 Filed 11–25–15; 8:45 am]
IRO–008–2, IRO–010–2, IRO–014–3, Practice Questionnaire and Request.’’ to
BILLING CODE 6717–01–P
and IRO–017–1 applies will incur costs read ‘‘Appendix to Subpart D of Part
of approximately $147,364 (annual 776—Outside Law Practice
ongoing) per entity. The Commission Questionnaire and Request.’’ and in the
does not consider the estimated costs to DEPARTMENT OF DEFENSE
seventh line, revise ‘‘776.95 Relations
have a significant economic impact on Department of the Navy with Non-USG Counsel.’’ to read
a substantial number of small entities. ‘‘776.94 Relations with Non-USG
[No. USN–2013–0011] Counsel.’’;
VI. Document Availability ■ 2. On page 68408, in the third column,
RIN 0703–AA92
77. In addition to publishing the full second line, revise ‘‘§ 776.94 of this
text of this document in the Federal 32 CFR Part 776 part’’ to read ‘‘appendix to subpart D of
Register, the Commission provides all part 776’’;
Professional Conduct of Attorneys ■ 3. On page 68408, in the third column,
interested persons an opportunity to
Practicing Under the Cognizance and revise the section heading ‘‘§ 776.94
view and/or print the contents of this
Supervision of the Judge Advocate Outside Law Practice Questionnaire and
document via the Internet through
General; Correction Request.’’ to read ‘‘Appendix to Subpart
FERC’s Home Page (http://www.ferc.gov)
D of Part 776—Outside Law Practice
and in FERC’s Public Reference Room AGENCY: Department of the Navy, DoD. Questionnaire and Request.’’; and
during normal business hours (8:30 a.m. ACTION: Final rule; correction. ■ 4. On page 68409, in the second
to 5:00 p.m. Eastern time) at 888 First column under the Subpart E heading,
Street NE., Room 2A, Washington, DC SUMMARY: On November 4, 2015, the revise ‘‘§ 776.95 Relations with Non-
20426. Department of the Navy (DoN) USG Counsel.’’ to read ‘‘§ 776.94
78. From FERC’s Home Page on the published a final rule to comport with Relations with Non-USG Counsel.’’.
current policy as stated in JAG
Internet, this information is available on Dated: November 20, 2015.
Instruction 5803.1 (Series) governing the
eLibrary. The full text of this document N.A. Hagerty-Ford,
professional conduct of attorneys
is available on eLibrary in PDF and Commander,Office of the Judge Advocate
practicing under the cognizance and
Microsoft Word format for viewing, supervision of the Judge Advocate General,U.S. Navy, Federal Register Liaison
printing, and/or downloading. To access General. The content of one of its CFRs Officer.
this document in eLibrary, type the is better codified as an appendix, and [FR Doc. 2015–30190 Filed 11–25–15; 8:45 am]
docket number excluding the last three this correction amends the CFR BILLING CODE 3810–FF–P
digits of this document in the docket accordingly.
number field.
This correction is effective
DATES:
79. User assistance is available for December 4, 2015. DEPARTMENT OF EDUCATION
eLibrary and the FERC’s Web site during
FOR FURTHER INFORMATION CONTACT: 34 CFR Parts 600, 602, 603, 668, 682,
normal business hours from FERC
Commander Noreen A. Hagerty-Ford, 685, 686, 690, and 691
Online Support at 202–502–6652 (toll
JAGC, U.S. Navy, Office of the Judge
free at 1–866–208–3676) or email at Advocate General (Administrative Law), [Docket ID ED–2010–OPE–0004]
ferconlinesupport@ferc.gov, or the Department of the Navy, 1322 Patterson RIN 1840–AD02
Public Reference Room at (202) 502– Ave. SE., Suite 3000, Washington Navy
8371, TTY (202) 502–8659. Email the Yard, DC 20374–5066, telephone: 703– Program Integrity Issues
Public Reference Room at 614–7408.
public.referenceroom@ferc.gov. AGENCY: Office of Postsecondary
SUPPLEMENTARY INFORMATION: The DoN Education, Department of Education.
published a rule at 80 FR 68388 on ACTION: Final regulations; clarification
mstockstill on DSK4VPTVN1PROD with RULES
72 The Small Business Administration sets the
threshold for what constitutes a small business.
November 4, 2015, to revise 32 CFR part and additional information.
Public utilities may fall under one of several 776, to comport with current policy as
different categories, each with a size threshold stated in JAG Instruction 5803.1 (Series) SUMMARY: On October 29, 2010, the
based on the company’s number of employees, governing the professional conduct of Department of Education published in
including affiliates, the parent company, and
subsidiaries. For the analysis in this NOPR, we are
attorneys practicing under the the Federal Register final regulations for
using a 750 employee threshold for each affected cognizance and supervision of the Judge improving integrity in the programs
entity to conduct a comprehensive analysis. Advocate General. The content of authorized under title IV of the Higher
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Document Created: 2015-12-14 14:05:16
Document Modified: 2015-12-14 14:05:16
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration | |
| Section | Rules and Regulations | |
| Action | Final rule. | |
| Dates | This rule will become effective January 26, 2016. | |
| Contact | Robert T. Stroh (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (202) 502-8473, [email protected] Eugene Blick (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (301) 665-1759, [email protected] Darrell G. Piatt, PE (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, Telephone: (205) 332-3792, [email protected] | |
| FR Citation | 80 FR 73977 |
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