Transmission Planning Reliability Standards, 63036-63052 [2013-24828]

Download as PDF Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations (vii) 7.12.4.1. If the base/stand supports the bassinet bed in any unlocked position, place the inclinometer on the mattress support at the approximate center of the mattress support. Care should be taken to avoid seams, snap fasteners, or other items that may affect the measurement reading. Record the angle measurement. (viii) 7.12.4.2. If the base/stand supports the bassinet bed and the angle of the mattress support surface measured in 7.12.4.1 is less than 20 degrees from a horizontal plane, evaluate whether the bassinet has a false latch/lock visual indicator per 6.10.4. (ix) 7.12.4.3. If the base/stand supports the bassinet bed, and the angle of the mattress support surface measured in 7.12.4.1 is less than 20 degrees from a horizontal plane, and the bassinet does not contain a false latch/ lock visual indicator, test the unit in accordance with sections 7.4.2 through 7.4.7. (x) 7.12.5. Repeat 7.12.2 through 7.12.4 for all of the manufacturer’s base/ stand recommended positions and use modes. (xi) 7.12.6. Repeat 7.12.4 through 7.12.5 with the bassinet bed rotated 180 degrees from the manufacturers recommended use orientation, if the base/stand supports the bassinet bed in this orientation. (A) Rationale. (1) This test requirement addresses fatal and nonfatal incidents involving bassinet beds that tipped over or fell off their base/stand when they were not properly locked/ latched to their base/stand or the latch failed to engage as intended. Products that appear to be in an intended use position when the lock or latch is not properly engaged can create a false VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 sense of security by appearing to be stable. Unsecured or misaligned lock/ latch systems are a hidden hazard because they are not easily seen by consumers due to being located beneath the bassinet or covered by decorative skirts. In addition, consumers will avoid activating lock/latch mechanisms for numerous reasons if a bassinet bed appears stable when placed on a stand/ base. Because of these foreseeable use conditions, this requirement has been added to ensure that bassinets with a removable bassinet bed feature will be inherently stable or it is obvious that they are not properly secured. (2) 6.10 allows bassinet bed designs that: (i) Cannot be supported by the base/ stand in an unlocked configuration, (ii) Automatically lock and cannot be placed in an unlocked position on the base/stand, (iii) Are clearly and obviously unstable when the lock/latch is misaligned or unused, (iv) Provide a visual warning to consumers when the product is not properly locked onto the base/stand, or (v) Have lock/latch mechanisms that are not necessary to provide needed stability. (B) [Reserved] Dated: September 30, 2013. Todd A. Stevenson, Secretary, Consumer Product Safety Commission. [FR Doc. 2013–24203 Filed 10–22–13; 8:45 am] BILLING CODE 6355–01–P PO 00000 Frm 00078 Fmt 4700 Sfmt 4700 DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 40 [Docket Nos. RM12–1–000 and RM13–9– 000; Order No. 786] Transmission Planning Reliability Standards Federal Energy Regulatory Commission, Energy. ACTION: Final rule. AGENCY: Under section 215 of the Federal Power Act, the Federal Energy Regulatory Commission approves Transmission Planning (TPL) Reliability Standard TPL–001–4, submitted by the North American Electric Reliability Corporation, the Commission-certified Electric Reliability Organization. Reliability Standard TPL–001–4 introduces significant revisions and improvements by requiring annual assessments addressing near-term and long-term planning horizons for steady state, short circuit and stability conditions. Reliability Standard TPL– 001–4 also includes a provision that allows a transmission planner to plan for non-consequential load loss following a single contingency by providing a blend of specific quantitative and qualitative parameters for the permissible use of planned nonconsequential load loss to address bulk electric system performance issues, including firm limitations on the maximum amount of load that an entity may plan to shed, safeguards to ensure against inconsistent results and arbitrary determinations that allow for the planned non-consequential load loss, SUMMARY: E:\FR\FM\23OCR1.SGM 23OCR1 ER23OC13.001</GPH> tkelley on DSK3SPTVN1PROD with RULES 63036 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations and a more specifically defined, open and transparent, verifiable, and enforceable stakeholder process. The Commission finds in the Final Rule that the proposed Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest. In addition, the Commission directs NERC to modify Reliability Standard TPL–001–4 to address the concern that the standard could exclude planned maintenance outages of significant facilities from future planning assessments and directs NERC to change the TPL–001–4, Requirement R1 Violation Risk Factor from medium to high. DATES: This rule will become effective December 23, 2013. FOR FURTHER INFORMATION CONTACT: Eugene Blick (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Telephone: (202) 502–8066, Eugene.Blick@ferc.gov. 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, Robert.Stroh@ferc.gov. SUPPLEMENTARY INFORMATION: 145 FERC ¶ 61,051 tkelley on DSK3SPTVN1PROD with RULES Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony Clark. (Issued October 17, 2013) 1. Under section 215(d) of the Federal Power Act (FPA), the Commission approves Transmission Planning (TPL) Reliability Standard TPL–001–4, submitted by the North American Electric Reliability Corporation (NERC), the Commission-certified Electric Reliability Organization (ERO).1 The Commission finds that Reliability Standard TPL–001–4 introduces significant revisions and improvements to the TPL Reliability Standards, including increased specificity of data required for modeling conditions, and requires annual assessments addressing near-term and long-term planning horizons for steady state, short circuit and stability conditions. Further, we find that the Reliability Standard generally addresses the Commission directives set forth in Order No. 693 and subsequent Commission orders.2 We agree with NERC that Reliability 1 16 U.S.C. 824o(d) (2006). Reliability Standards for the BulkPower System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693–A, 120 FERC ¶ 61,053 (2007). 2 Mandatory VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 Standard TPL–001–4 includes specific improvements over the currentlyeffective Transmission Planning Reliability Standards and is responsive to the Commission’s directives. 2. Further, in response to Order No. 762,3 Reliability Standard TPL–001–4 includes a provision that allows a transmission planner to plan for nonconsequential load loss following a single contingency. While the Reliability Standard provides that ‘‘an objective of the planning process is to limit the likelihood and magnitude of Non-Consequential Load Loss following planning events,’’ the standard also recognizes that ‘‘[i]n limited circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance requirements are met.’’ 4 Thus, for such limited circumstances, Reliability Standard TPL–001–4 provides a blend of specific quantitative and qualitative parameters for the permissible use of planned nonconsequential load loss to address bulk electric system performance issues, including firm limitations on the maximum amount of load that an entity may plan to shed, safeguards to ensure against inconsistent results and arbitrary determinations that allow for the planned non-consequential load loss, and a more specifically defined, open and transparent, verifiable, and enforceable stakeholder process. 3. For the reasons discussed in detail below, the Commission finds that Reliability Standard TPL–001–4 is just, reasonable, not unduly discriminatory or preferential, and in the public interest. Therefore, pursuant to section 215(d) of the FPA the Commission approves proposed Reliability Standard TPL–001–4. Thus, the Commission approves footnote 12 to Table 1 of the Reliability Standard (formerly referred to as footnote ‘b’). In addition, as discussed below, the Commission finds NERC’s explanation on protection system failures versus relay failures, assessment of backup or redundant protection systems, single line to ground faults and the Order No. 693 directives to be reasonable. However, the Commission has concerns about two issues and directs NERC to modify Reliability Standard TPL–001–4 to address the concern that the standard 3 Transmission Planning Reliability Standards, Order No. 762, 139 FERC ¶ 61,060 (2012) (Order No. 762), order on reconsideration, 140 FERC ¶ 61,101 (2012). See also Transmission Planning Reliability Standards, 139 FERC ¶ 61,059 (2012) (April 2012 NOPR). 4 Reliability Standard TPL–001–4, Table I (Steady State and Stability Performance Extreme Events), n.12. PO 00000 Frm 00079 Fmt 4700 Sfmt 4700 63037 could exclude planned maintenance outages of significant facilities from future planning assessments and directs NERC to change the TPL–001–4, Requirement R1 VRF from medium to high. I. Background A. Regulatory History 4. In Order No. 693, the Commission accepted the Version 0 TPL Reliability Standards.5 Further, pursuant to FPA section 215(d)(5), the Commission directed NERC to develop modifications through the Reliability Standards development process to address certain issues identified by the Commission. In addition, the Commission neither approved nor remanded Reliability Standards TPL–005–0 and TPL–006–0 because these two standards applied only to regional reliability organizations, the predecessors to the statutorily recognized Regional Entities. With regard to Reliability Standard TPL–002–0b, Table 1, footnote ‘b,’ which applies to planned nonconsequential load loss, the Commission directed NERC to clarify footnote ‘b’ regarding the planned nonconsequential load loss for a single contingency event.6 In a March 18, 2010 order, the Commission directed NERC to submit a modification to footnote ‘b’ responsive to the Commission’s directive in Order No. 693 by June 30, 2010.7 In a June 11, 2010 order, the Commission extended the compliance deadline until March 31, 2011.8 Remand of Footnote b of the Version 1 TPL Reliability Standard (RM11–18– 000) 5. On March 31, 2011, NERC submitted proposed Reliability Standard TPL–002–1 (Version 1). NERC proposed to modify Table 1, footnote ‘b’ to permit planned non-consequential load loss when documented and subjected to an open stakeholder process.9 In Order No. 5 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 1840, 1845. The currently-effective versions of the TPL Reliability Standards are as follows: TPL– 001–0.1, TPL–002–0b, TPL–003–0a, and TPL–004– 0. 6 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792. 7 Mandatory Reliability Standards for the Bulk Power System, 130 FERC ¶ 61,200 (2010). 8 Mandatory Reliability Standards for the Bulk Power System, 131 FERC ¶ 61,231 (2010). 9 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1794. Non-consequential load loss includes the removal, by any means, of any planned firm load that is not directly served by the elements that are removed from service as a result of the contingency. Currently-effective footnote ‘b’ deals with both consequential load loss and non-consequential load loss. NERC’s proposed footnote ‘b’ characterized both types of load loss as ‘‘firm demand.’’ E:\FR\FM\23OCR1.SGM 23OCR1 63038 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations 762, the Commission remanded to NERC the proposed modification to footnote ‘b,’ concluding that the proposed revisions did not meet the Commission’s Order No. 693 directives, nor did the revisions achieve an equally effective and efficient alternative.10 The Commission stated that the proposal did not adequately clarify or define the circumstances in which an entity can use planned non-consequential load loss as a mitigation plan to meet performance requirements for single contingency events. The Commission also explained that the procedural and substantive parameters of NERC’s proposal were too undefined to provide assurances that the process will be effective in determining when it is appropriate to plan for nonconsequential load loss, did not contain NERC-defined criteria on circumstances to determine when an exception for planned non-consequential load loss is permissible, and could result in inconsistent results in implementation. Accordingly, the Commission remanded the filing to NERC and directed NERC to develop revisions to footnote ‘b’ that would address the Commission’s concerns. Additionally, in Order No. 762, the Commission directed NERC to ‘‘identify the specific instances of any planned interruptions of firm demand under footnote ‘b’ and how frequently the provision has been used.’’ 11 Proposed Remand of Version 2 of the TPL Reliability Standard (RM12–1–000) 6. On October 19, 2011, NERC submitted a petition seeking approval of a revised and consolidated TPL Reliability Standard that combined the four currently-effective TPL Reliability Standards into a single standard, TPL– 001–2 (Version 2).12 The Version 2 standard included language similar to NERC’s Version 1 proposal with regard to utilizing non-consequential load loss. The Version 2 standard included a nonconsequential load loss provision in Table 1—Steady State & Stability Performance Footnotes (Planning Events and Extreme Events), footnotes 9 and 12.13 10 Order No. 762, 139 FERC ¶ 61,060. P 20. 12 NERC’s October 2011 petition sought approval of Reliability Standard TPL–001–2, the associated implementation plan and Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs), as well as five new definitions to be added to the NERC Glossary of Terms. NERC also requested approval to retire four currently-effective TPL Reliability Standards: TPL–001–1, TPL–002–1b, TPL–003–1a; and TPL–004–1. In addition, NERC requested to withdraw two pending Reliability Standards: TPL–005–0 and TPL–006–0.1. 13 NERC’s October 2011 Petition at 12. NERC’s proposal in Docket No. RM11–18–000, Table 1, tkelley on DSK3SPTVN1PROD with RULES 11 Id. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 7. On the same day that the Commission issued Order No. 762, the Commission issued a notice of proposed rulemaking (April 2012 NOPR) stating that, notwithstanding that proposed Version 2 included specific improvements over the currentlyeffective Transmission Planning Reliability Standards, footnote 12 ‘‘allow[s] for transmission planners to plan for non-consequential load loss following a single contingency without adequate safeguards [and] undermines the potential benefits the proposed Reliability Standard may provide.’’ 14 Thus, the Commission stated that its concerns regarding the stakeholder process set forth in footnote 12 required a proposal to remand the entire Reliability Standard. The Commission added that resolution of the footnote 12 concerns ‘‘would allow the industry, NERC and the Commission to go forward with the consideration of other improvements contained in proposed Version 2.’’ 15 In addition, the April 2012 NOPR asked for comment on various aspects of the consolidated Version 2 Reliability Standard. Comments on the NOPR were due by July 20, 2012. The following entities submitted comments: NERC, the Edison Electric Institute (EEI), ISO/RTOs,16 ITC Companies,17 Midcontinent Independent System Operator Inc. (MISO),18 American Transmission Company LLC (ATCLLC), Powerex Corporation (Powerex), Bonneville Power Administration (BPA), and Hydro One Networks and the Independent Electricity System Operator (Hydro One and IESO). Proposed Reliability Standard TPL– 001–4—Version 4 (RM13–9–000) 8. On February 28, 2013, NERC submitted proposed Reliability Standard TPL–001–4 (Version 4) in response to the Commission’s remand in Order No. 762 and concerns with regard to Table footnote ‘b’ referred to planned load shed as planned ‘‘interruption of Firm Demand.’’ In footnote 12, proposed to replace footnote ‘b,’ NERC changed the term from ‘‘interruption of Firm Demand’’ to utilization of ‘‘Non-Consequential Load Loss.’’ 14 April 2012 NOPR, 139 FERC ¶ 61,059 at P 55. 15 Id. P 3. 16 The ISO/RTOs consist of Electric Reliability Council of Texas, Inc., ISO New England, Inc., Midcontinent Independent Transmission System Operator Inc., New York Independent System Operator, Inc., PJM Interconnection L.L.C., and Southwest Power Pool, Inc. 17 ITC Companies consist of ITCTransmission, Michigan Electric Transmission Company LLC, ITC Midwest LLC, and ITC Great Plains. 18 Effective April 26, 2013, MISO changed its name from ‘‘Midwest Independent Transmission System Operator, Inc.’’ to ‘‘Midcontinent Independent System Operator, Inc.’’ PO 00000 Frm 00080 Fmt 4700 Sfmt 4700 1 footnote 12 identified in the April 2012 NOPR.19 Reliability Standard TPL–001–4 includes eight requirements and Table 1: 20 Requirement R1: Requires the transmission planner and planning coordinator to maintain system models and provides a specific list of items required for the system models and that the models represent projected system conditions. The planner is required to model the items that are variable, such as load and generation dispatch, based specifically on the expected system conditions. Requirement R2: Requires each transmission planner and planning coordinator to prepare an annual planning assessment of its portion of the bulk electric system and must use current or qualified past studies, document assumptions, and document summarized results of the steady state analyses, short circuit analyses, and stability analyses. Requirement R2, Part 2.1.3 requires the planner to assess system performance utilizing a current annual study or qualified past study for each known outage with a duration of at least six months for certain events. It also clarifies that qualified past studies can be utilized in the analysis while tightly defining the qualifications for those studies. Requirement R2 includes a new part 2.7.3 that allows transmission planners and planning coordinators to utilize nonconsequential load loss to meet performance requirements if the applicable entities are unable to complete a corrective action plan due to circumstances beyond their control. Requirements R3 and R4: Requirement R3 describes the requirements for steady state studies and Requirement R4 explains the requirements for stability studies. Requirement R3 and Requirement R4 also require that simulations duplicate what will occur in an actual power system based on the expected performance of the protection systems. 19 In its filing, NERC stated that the Version 4 standard, i.e., TPL–001–4, modifies the pending Version 2 consolidated standard, TPL–001–2. NERC also submitted, alternatively, a group of four TPL standards (TPL–001–3, TPL–002–2b, TPL–003–2a, and TPL–004–2, collectively, the Version 3 TPL standards) that would modify ‘‘footnote b’’ of the currently-effective TPL standards, ‘‘[i]n the event the Commission does not approve the Consolidated TPL Standards [Version 4].’’ NERC Petition at 4. Because we approve TPL–001–4, references throughout this Final Rule are to the Version 4 standard. 20 The filed proposed Reliability Standard is not attached to the Final Rule but is available on the Commission’s eLibrary document retrieval system in Docket Nos. RM12–1–000 and RM13–9–000 and are available on NERC’s Web site, https:// www.nerc.com. E:\FR\FM\23OCR1.SGM 23OCR1 tkelley on DSK3SPTVN1PROD with RULES Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations Requirement R3 and Requirement R4 also include new parts that require the planners to conduct an evaluation of possible actions designed to reduce the likelihood or the consequences of extreme events that cause cascading. Requirement R5: Requirement R5 deals with voltage criteria and voltage performance. NERC proposes in Requirement R5 that each transmission planner and planning coordinator must have criteria for acceptable system steady state voltage limits, postcontingency voltage deviations, and the transient voltage response for its system. For transient voltage response the criteria must specify a low-voltage level and a maximum length of time that transient voltages may remain below that level. This requirement will establish more robust transmission planning for organizations and greater consistency as these voltage criteria are shared. Requirement R6: Specifies that an entity must define and document the criteria or methodology used to identify system instability for conditions such as cascading, voltage instability, or uncontrolled islanding within its planning assessment. Requirement R7: Mandates coordination of individual and joint responsibilities for the planning coordinator and the transmission planner which is intended to eliminate confusion regarding the responsibilities of the applicable entities and assures that all elements needed for regional and wide area studies are defined with a specific entity responsible for each element and that no gaps will exist in planning for the Bulk-Power System. Requirement R8: Addresses the sharing of planning assessments with neighboring systems. The requirement ensures that information is shared with and input received from adjacent entities and other entities with a reliability related need that may be affected by an entity’s system planning. Table 1: Similar to the currentlyeffective TPL Reliability Standard, the revised standard contains a series of planning events and describes system performance requirements in Table 1 for a range of potential system contingencies required to be evaluated by the planner. Table 1 includes three parts: Steady State & Stability Performance Planning Events, Steady State & Stability Performance Extreme Events, and Steady State & Stability Performance Footnotes. Table 1 categorizes the events as either ‘‘planning events’’ or ‘‘extreme events.’’ The proposed table lists seven contingency planning events that require steady-state and stability VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 analysis as well as five extreme event contingencies. 9. NERC modified footnote 12 of Table 1 to provide specific parameters for the permissible use of planned nonconsequential load loss to address bulk electric system performance issues, including: (1) Firm limitations on the maximum amount of load that an entity may plan to shed, (2) safeguards to ensure against inconsistent results and arbitrary determinations that allow for the planned non-consequential load loss, and (3) a more specifically defined, open and transparent, verifiable, and enforceable stakeholder process. Footnote 12 as modified provides: An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following planning events. In limited circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance requirements are met. However, when Non-Consequential Load Loss is utilized under footnote 12 within the Near-Term Transmission Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the Non-Consequential Load Loss meets the conditions shown in Attachment 1. In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW for US registered entities. The amount of planned Non-Consequential Load Loss for a non-US Registered Entity should be implemented in a manner that is consistent with, or under the direction of, the applicable governmental authority or its agency in the non-US jurisdiction. 10. Attachment 1 to TPL–001–4, referenced in footnote 12 has three sections: (I) Stakeholder process, (II) information an entity must provide to stakeholders, and (III) instances for which regulatory review of planned non-consequential load loss under footnote 12 is required. Section I describes five criteria that apply to the open and transparent stakeholder process that an entity must implement when it seeks to use footnote 12. Section I provides that an entity does not have to repeat the stakeholder process for a specific application of footnote 12 with respect to subsequent planning assessments unless conditions have materially changed for that specific application. 11. Section II of Attachment 1 specifies eight categories of information that entities must provide to stakeholders, including estimated amount, frequency and duration of planned non-consequential load loss under footnote 12. An entity must also provide information on alternatives considered and future plans to alleviate the need for planned non-consequential load loss. PO 00000 Frm 00081 Fmt 4700 Sfmt 4700 63039 12. Section III of Attachment 1 describes the process for planned nonconsequential load loss greater than 25 MW. Specifically, planned nonconsequential load loss between 25 MW and 75 MW, or any planned nonconsequential load loss at the 300 kV level or above would receive greater scrutiny by regulatory authorities and the ERO. Where these parameters apply, ‘‘the Transmission Planner or Planning Coordinator must ensure that applicable regulatory authorities or governing bodies responsible for retail electric service issues do not object to the use of Non-Consequential Load Loss under footnote 12.’’ 21 Further, ‘‘[o]nce assurance has been received that the applicable regulatory authorities . . . responsible for retail electric service issues do not object . . . the Planning Coordinator or Transmission Planner must submit the information [in Section II of Attachment 1] to the ERO for a determination of whether there are any Adverse Reliability Impacts’’ caused by the responsible entity’s request to use footnote 12.22 According to NERC, this provision provides safeguards against arbitrary or inconsistent determinations, and also ‘‘preserves, to the extent practicable, the role of Retail Regulators,’’ while allowing ERO review for possible adverse reliability impacts.23 13. NERC stated that the combination of numerical limitations and other considerations, such as costs and alternatives, guards against a determination based solely on a quantitative threshold becoming an acceptable de facto interpretation of planned non-consequential load loss. According to NERC, the procedures in footnote 12 would enable acceptable, but limited, circumstances of planned non-consequential load loss after a thorough stakeholder review and approval and ERO review. 14. NERC also stated that, because footnote 12 differs from footnote ‘b’ included in the currently-effective TPL Reliability Standards, data do not yet exist on the frequency of instances of planned non-consequential load loss under the new footnote 12. Consequently, NERC stated that it will monitor the use of footnote 12 and will report the results of this monitoring 21 NERC Petition, Exhibit A, proposed Reliability Standard TPL–001–4, Attachment I, section 3. 22 NERC Petition, Exhibit A, proposed Reliability Standard TPL–001–4, Attachment I, section 3. NERC defines ‘‘Adverse Reliability Impact’’ as ‘‘[t]he impact of an event that results in frequencyrelated instability; unplanned tripping of load or generation; or uncontrolled separation or cascading outages that affects a widespread area of the Interconnection.’’ NERC Glossary at 4. 23 NERC February 2013 Petition at 19. E:\FR\FM\23OCR1.SGM 23OCR1 tkelley on DSK3SPTVN1PROD with RULES 63040 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations after the first two years of the footnote’s implementation.24 15. NERC requested that requirements R1 and R7 of the Version 4 Reliability Standard as well as the definitions become effective on the first day of the first calendar quarter twelve months after applicable regulatory approval. In addition, except as indicated below, NERC requested that Requirements R2 through R6 and Requirement R8 including Table 1—Steady State & Stability Performance Planning Events, Table 1—Steady State & Stability Performance Extreme Events, Table 1— Steady State & Stability Performance Footnotes (Planning Events & Extreme Events) and Attachment 1 become effective and subject to compliance on the first day of the first calendar quarter, 24 months after applicable regulatory approval. 16. NERC also proposed that, for 84 calendar months beginning the first day of the first calendar quarter following applicable regulatory approval, concurrent with the 24 month effective date of Requirement R2, corrective action plans applying to specific categories of contingencies and events identified in TPL–001–4, Table 1 are allowed to include non-consequential load loss and curtailment of firm transmission service (in accordance with Requirement R2, Part 2.7.3) that would not otherwise be permitted by the requirements of the Version 4 Reliability Standard. Further, NERC stated that Requirement R2, Part 2.7.3 addresses situations that are beyond the control of the planner that prevent the implementation of a corrective action plan in the required timeframe. Some examples of situations beyond the control of the planner could include a state road widening project taking substation land that was targeted for expansion or a ruling preventing the entity from condemning the land necessary for a project. 17. NERC also requested approval to retire the currently-effective TPL Reliability Standards and to withdraw two pending TPL Reliability Standards, TPL–005–0 and TPL–006–0.1, because it transferred the requirements of the pending Reliability Standards to sections 803 and 804 of NERC’s Rules of Procedure. NERC proposed to retire TPL Reliability Standards TPL–001–0.1, TPL–002–0b, TPL–003–0a, and TPL– 004–0 on midnight of the day immediately prior to the effective date of TPL–001–4. However, during the 24month implementation period, all aspects of the currently-effective TPL Reliability Standards, TPL–001–0.1 24 NERC’s February 2013 Petition at 11. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 through TPL–004–0 will remain in effect for compliance monitoring. NERC stated that the 24 month period is to allow entities to develop, perform and/ or validate new or modified studies necessary to implement and meet Reliability Standard TPL–001–4. NERC explained that the specified effective dates allow sufficient time for proper assessment of the available options necessary to create a viable corrective action plan that is compliant with the new TPL Reliability Standard. Supplemental NOPR 18. On May 16, 2013, the Commission issued a Supplemental NOPR which proposed to approve the Version 4 TPL Reliability Standard, TPL–001–4, as just, reasonable, not unduly discriminatory or preferential, and in the public interest.25 In the Supplemental NOPR, the Commission suggested that, while NERC’s proposal differs from the Commission directives on the matter of utilizing nonconsequential load loss, NERC’s proposal adequately addresses the underlying reliability concerns raised in Order No. 693, Order No. 762 and the April 2012 NOPR and, thus, is an equally effective and efficient alternative to address the Commission’s directives.26 In the Supplemental NOPR, the Commission proposed to find that proposed footnote 12 would improve reliability by providing a blend of specific quantitative and qualitative parameters for the permissible use of planned non-consequential load loss to address bulk electric system performance issues. In addition, the Commission stated that the stakeholder process appears to be adequately defined and includes specific criteria and guidelines that a responsible entity must follow before it may use planned non-consequential load loss to meet Reliability Standard TPL–001–4 performance requirements for a single contingency event. Further, the Supplemental NOPR indicated that NERC’s proposal provides reasonable safeguards, including a review process by NERC, to protect against adverse reliability impacts that could otherwise result from planned non-consequential load loss.27 19. In the Supplemental NOPR, the Commission proposed to direct that NERC submit a report on the use of footnote 12, due at the end of the first calendar quarter after the first two years 25 Transmission Planning Reliability Standards, Notice of Proposed Rulemaking, 143 FERC ¶ 61,136 (2013) (Supplemental NOPR). 26 Supplemental NOPR, 143 FERC ¶ 61,136 at P 18. 27 Id. P 19. PO 00000 Frm 00082 Fmt 4700 Sfmt 4700 of implementation of footnote 12 to provide an analysis of the use of footnote 12, including but not limited to information on the duration, frequency and magnitude of planned nonconsequential load loss, and typical (and if significant, atypical) scenarios where entities plan for nonconsequential load loss. The Commission proposed that the report should also address the effectiveness of the stakeholder process and the use and effectiveness of the local regulatory review and NERC review.28 20. Comments on the Supplemental NOPR were due on June 24, 2013. NERC, MISO and ITC Companies filed comments in response to the Supplemental NOPR. II. Discussion 21. Pursuant to FPA section 215(d), we find that Reliability Standard TPL– 001–4 is just, reasonable, not unduly discriminatory or preferential, and in the public interest. While NERC’s proposal differs from the Commission directives, we find that NERC adequately addressed the directives and underlying reliability concerns of Order No. 693, Order No. 762 and the April 2012 NOPR and, thus, is an equally effective and efficient alternative to address the Commission’s concerns.29 We find that the revised TPL Reliability Standard improves uniformity and transparency in the transmission planning process and clarifies the instances where planners may utilize planned load loss in establishing transmission planning performance requirements for reliable bulk electric system operations across normal and contingency conditions. We also find that Reliability Standard TPL–001–4 will serve as a foundation for annual planning assessments conducted by planning coordinators and transmission planners to plan the bulk electric system reliably in response to a range of potential contingencies. Further, we find that the Reliability Standard presents clear, measurable, and enforceable requirements that each planning coordinator and transmission planner must follow when planning its system. 22. In the Supplemental NOPR, the Commission stated it would issue a final rule that addresses the consolidated transmission planning Reliability Standard, TPL–001–4. Therefore, this Final Rule addresses the modified footnote 12 and comments received in response to the Supplemental NOPR as 28 Id. P 20. Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792. 29 See E:\FR\FM\23OCR1.SGM 23OCR1 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations well as other aspects of the consolidated TPL Reliability Standard raised in the April 2012 NOPR. tkelley on DSK3SPTVN1PROD with RULES A. Footnote 12 and Planned Use of NonConsequential Load Loss NOPR Proposal 23. In the Supplemental NOPR, the Commission proposed to approve footnote 12. The Commission indicated that the proposal differs from the Commission directives but adequately addresses the underlying reliability concerns raised in Order No. 693, Order No. 762 and the April 2012 NOPR and, thus, is an equally effective and efficient alternative to address the Commission’s directives.30 The Supplemental NOPR indicated that proposed footnote 12 would improve reliability by providing a blend of specific quantitative and qualitative parameters for the permissible use of planned nonconsequential load loss to address bulk electric system performance issues. In addition, the Supplemental NOPR stated that the stakeholder process appeared to be adequately defined and includes specific criteria and guidelines that a responsible entity must follow before it may use planned nonconsequential load loss to meet Reliability Standard TPL–001–4 performance requirements for a single contingency event. Further, the Supplemental NOPR stated that NERC’s proposal provides reasonable safeguards, including a review process by NERC, to protect against adverse reliability impacts that could otherwise result from planned non-consequential load loss. Comments 24. NERC supports the Commission’s proposal in the Supplemental NOPR. NERC also commits to monitor the use of footnote 12 and issue a report containing the findings of the monitoring by the end of the first calendar quarter following the first two years of implementation. ITC Companies believe NERC’s proposal is a significant improvement over the currently-effective standard and support approval. ITC Companies urge the Commission to clarify that the use of planned non-consequential load loss should be used rarely and should not be considered a de facto planning solution. 25. MISO supports Reliability Standard TPL–001–4 as an improvement over the current standard but has two concerns regarding Attachment 1, referenced in footnote 12. 30 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792; Mandatory Reliability Standards for the Bulk Power System, 131 FERC ¶ 61,231 at P 21. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 First, MISO argues that the Commission should direct NERC to eliminate or clarify the requirement that requires interaction with and approval by applicable regulatory authorities or government bodies responsible for retail electric service. MISO claims that such a requirement adds an additional layer of complexity and administrative burden to compliance of proposed Reliability Standard TPL–001–4 without any attendant benefit. According to MISO, the reference in Attachment 1 to ‘‘applicable regulatory authorities or governing bodies’’ is not clear. MISO states that, while these terms could encompass a state’s public service commission or public utility commission, the terms could also potentially include other state bodies or agencies such as consumer advocacy and protection bodies, state legislatures, and city or municipal bodies. According to MISO, if these other entities would be considered ‘‘governing bodies responsible for retail electric issues,’’ a transmission planner would need to seek and receive assurances from each of these bodies. MISO also suggests that, prior to finalization of its transmission expansion plan each year, a planner could obtain the assent of the applicable public utility commission, and yet have its transmission plans subsequently upended because it did not obtain additional assent from a different state agency that has some involvement in retail electric matters. 26. MISO also questions what it means to ensure that an applicable regulatory authority or governing body ‘‘does not object’’ to the inclusion of non-consequential load loss in the planning process. MISO suggests that it could mean input of agency staff or a more formal decision that is voted on by the agency’s commissioners. MISO argues that use of an open stakeholder process that allows for robust input by any interested parties will ensure that all interested state agencies will have a say in the process, and that any objections of such agencies to the inclusion of non-consequential load loss will be incorporated into the relevant planning decisions. 27. Alternatively, MISO requests that the Commission clarify or direct NERC to clarify the ‘‘does not object’’ language to mean that: (1) The phrase ‘‘applicable regulatory authorities or governing bodies’’ means only the public utility commission or public service commission in the affected states, and does not refer to any other state entity; and (2) comments or other input submitted by the affected state public service commission or public utility commission in the Attachment 1 PO 00000 Frm 00083 Fmt 4700 Sfmt 4700 63041 stakeholder process indicating that the agency ‘‘does not object’’ to the inclusion of non-consequential load loss in the planning process are sufficient to satisfy the ‘‘does not object’’ requirement. 28. Further, MISO requests that the Commission clarify, or direct NERC to clarify, the language in section II of Attachment 1 that requires planning coordinators and transmission planners to provide stakeholders all assessments of ‘‘potential overlapping uses of footnote 12 including overlaps with adjacent Transmission Planners and Planning Coordinators.’’ MISO believes that this phrase suggests that there are other ‘‘potential overlapping uses’’ that are encompassed by the requirement. MISO states it is not clear what these other overlapping uses might be or how they might be incorporated into the planning process. Commission Determination 29. We approve Reliability Standard, TPL–001–4 with footnote 12 because it satisfies the concerns raised in the Supplemental NOPR. Footnote 12 provides a blend of specific quantitative and qualitative parameters for the permissible use of planned nonconsequential load loss to address bulk electric system performance issues, including firm limitations on the maximum amount of load that an entity may plan to shed, safeguards to ensure against inconsistent results and arbitrary determinations that allow for the planned non-consequential load loss, and a more specifically defined, open and transparent, verifiable, and enforceable stakeholder process. Use of planned non-consequential load loss should be rare and must be used consistent with the process established here. 30. We disagree with MISO that Attachment 1 to footnote 12 adds an additional layer of complexity and administrative burden to compliance without any attendant benefit. Commenters have stated in prior proceedings that a blend of quantitative and qualitative parameters ‘‘should not overly burden NERC or Regional Entity resources as utilization of the planned load shed exception is—and would be— rarely utilized.’’ 31 Further, the Commission directs NERC to report on the use of footnote 12 including the use and effectiveness of the local regulatory review and NERC review. This report is important because it will provide an analysis of the use of footnote 12, including but not limited to information on the duration, frequency and 31 Order E:\FR\FM\23OCR1.SGM No. 762, 139 FERC ¶ 61,060 at P 55. 23OCR1 63042 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations magnitude of planned nonconsequential load loss, and typical (and if significant, atypical) scenarios where entities plan for nonconsequential load loss. Further, the report will serve as a tool to evaluate the usefulness and effectiveness of local regulatory and ERO review, and identify whether MISO’s concern or other issues arise that need to be addressed. 31. We decline to direct NERC to limit the meaning of the phrase ‘‘applicable regulatory authorities or governing bodies.’’ Because each state and locality has different entities that are responsible for reliability of retail electric service, we are reluctant to further define who may participate. NERC’s report should identify any issues with respect to how effective and efficient the review process is working. With regard to MISO’s request that input by the affected regulatory body is sufficient to satisfy the language in the Attachment 1 stakeholder process indicating that the agency ‘‘does not object’’ to the inclusion of nonconsequential load loss, we note that during the standard development process NERC ‘‘modified the footnote to require regulatory authority review rather than approval.’’ 32 Use of an open stakeholder process that allows for robust input and review will ensure that all interested state agencies will have a say in the process, and that any objections of such agencies to the inclusion of non-consequential load loss will be considered in the relevant planning decisions. With regard to MISO’s requested clarification of the phrase ‘‘potential overlapping uses,’’ we note that Attachment 1 section II encompasses potential overlapping uses of footnote 12 either within the responsible entity or with adjacent transmission planners and planning coordinators.33 Accordingly, no further clarification is required. tkelley on DSK3SPTVN1PROD with RULES B. Reliability Issues Raised in the April 2012 NOPR 32. In the April 2012 NOPR, the Commission sought comments regarding the following issues regarding the proposed Version 2 Reliability Standard: (1) Planned maintenance outages, (2) violation risk factors, (3) protection system failures versus relay failures, (4) assessment of backup or redundant protection systems, (5) single 32 NERC’s Petition, Exhibit H, Consideration of Comments, period from July 31, 2012 through August 29, 2012 at 73. 33 Proposed TPL–001–4 Reliability Standard, Attachment 1, section II, category 8: ‘‘Assessment of potential overlapping uses of footnote 12 including overlaps with adjacent Transmission Planners and Planning Coordinators.’’ VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 line to ground faults and (6) Order No. 693 directives. The Version 4 TPL standard that we approve in this Final Rule contains the same provisions as the Version 2 standard, with the exception of footnote 12, Attachment 1 and the VRF for Requirement R6. Accordingly, we address below the issues raised in the April 2012 NOPR. 1. Planned Maintenance Outages NERC Petition 33. NERC proposed new language in TPL–001–2, Requirement R1 to remove an ambiguity in the current standard concerning what the planner needs to include in the specific studies. Requirement R1 also requires the planner to evaluate six-month or longer duration planned outages within its system. NERC states that, while Requirement R1.3.12 of the currentlyeffective TPL–002–0b includes planned outages (including maintenance outages) in the planning studies and requires simulations at the demands levels for which the planned outages are performed, it is not appropriate to have the planner select specific planned outages for inclusion in their studies.34 Consequently, NERC proposes a brightline test to determine whether a planned outage should be included in the system models. NOPR 34. In the April 2012 NOPR, the Commission expressed concern that, under proposed Requirement R1, planned maintenance outages with a duration of less than six months would be excluded from future planning assessments. As a result, any potential impact to bulk electric system reliability from these outages would be unknown.35 The Commission sought comment on whether the proposed six month threshold would materially change the number of planned outages included in planning assessments compared to the number included in planning assessments under the currently-effective standard, and whether the threshold would exclude nuclear plant refueling, large fossil and hydro generating station maintenance, and spring and fall transmission construction projects from future planning assessments. The Commission also sought comment on possible alternatives. 35. In the NOPR, the Commission noted that, with respect to protection system maintenance, currently-effective Reliability Standard TPL–002–0, Requirement R1.3.12 requires the 34 NERC’s 35 April PO 00000 October 2011 Petition at 35. 2012 NOPR, 139 FERC ¶ 61,059 at P 18. Frm 00084 Fmt 4700 Sfmt 4700 planner to ‘‘[i]nclude the planned (including maintenance) outage of any bulk electric equipment (including protection systems or their components) at those demand levels for which planned (including maintenance) outages are performed.’’ 36 NERC explained in the petition that this language did not carry over because protection system maintenance or other outages are not anticipated to last six months. The Commission indicated in the NOPR that it is critical to plan the system so that a protection system can be removed for maintenance and still be operated reliably and sought comment on whether protection systems are necessary to be included as a type of planned outage. Comments 36. NERC and EEI state that the proposed Reliability Standard will not materially change the number of planned outages that must be reflected in initial system conditions as compared to the existing standards. NERC states that applying existing Requirement R1.3.12, planners have traditionally only included those planned outages in their category ‘‘P0 or N–0’’ system condition that resulted from catastrophic equipment failures or extended outage conditions associated with construction or maintenance projects that place their system in an abnormal starting condition.37 NERC believes that going beyond those scenarios would consider ‘‘hypothetical planned outages,’’ and doing so in a planning study horizon would introduce multiple contingency conditions within the existing standard. Further, NERC states that planners will establish sensitivity cases around key generation unit outages, and when applying the category P3 planning event to those sensitivity cases, it will further cover multiple generator unit outages. Similarly, transmission maintenance outages are covered in the planning events when applying the category P6 planning events. 37. BPA believes the six-month planned outage window is workable but that it may be too short to consider in system planning models and suggests a one-year planned outage window. BPA states that planned outages with duration of less than one year should be 36 Reliability Standard TPL–002–0, Requirement R1.3.12. 37 Table 1 of the TPL Reliability Standard contains a series of planning events and describes system performance requirements and lists seven categories of contingency planning events, identified as P0 through P6. P0 is the ‘‘No Contingency,’’ normal system condition. Reliability Standard TPL–001–4, Table 1. E:\FR\FM\23OCR1.SGM 23OCR1 tkelley on DSK3SPTVN1PROD with RULES Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations dealt with operationally by determining new operating limits and taking other actions to mitigate the planned outage. According to Hydro One, it is not necessary to include planned outage of less than six months since long-term planning is intended to assess transmission expansion needs in the usual three to ten year timeframe. Hydro One states that the inclusion of planned outages of less than six months will not increase the accuracy of the results as these are moving targets and there are operational planning measures to provide the required transmission transfer capability to meet forecast demand. 38. On the other hand, ITC Companies, MISO and ATCLLC express concern that some planned outages of less than six months are relevant and should not be eliminated from consideration in planning evaluations. ATCLLC states that, although the number of planned outages may not materially change, the impact of eliminating pertinent planned outages of less than six months in duration is perhaps more material than the impact of outages six months in duration or longer. Some planned outages of less than six months in duration may also result in relevant impacts during one or both of the seasonal off-peak periods. ITC Companies state that, in some instances, certain transmission elements may be so critical that when taken out of service for system maintenance or to facilitate a new capital project, a subsequent single unplanned transmission outage could result in the loss of firm system load. ITC Companies adds that including only known maintenance outages of six months or longer in the transmission models could be a step backwards from the current standard. Since these unplanned outages can have consequential impacts on transmission customers, prudent transmission planning should include providing an adequate transmission system to avoid these undesired outcomes. 39. MISO suggests that limiting planning studies to only include known outages of generation or transmission with duration of at least six months may have a detrimental impact to bulk electric system reliability. According to MISO, proper transmission system planning should ensure that the removal of a facility for maintenance purposes can be accomplished without the need to deny or re-schedule such maintenance to prevent the loss of firm load resulting from the types of contingencies enumerated in the TPL Reliability Standards. MISO requests that the Commission direct NERC to VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 further expand the base planning conditions and assumptions by requiring inclusion of unscheduled, planned outages of any element when applying at a minimum P0 and P1 events to the off-peak cases. Commission Determination 40. Pursuant to section 215(d)(5) of the FPA, we direct NERC to modify Reliability Standard TPL–001–4 to address the concern that the six month threshold could exclude planned maintenance outages of significant facilities from future planning assessments. 41. For the reasons discussed below, the Commission finds that planned maintenance outages of less than six months in duration may result in relevant impacts during one or both of the seasonal off-peak periods. Prudent transmission planning should consider maintenance outages at those load levels when planned outages are performed to allow for a single element to be taken out of service for maintenance without compromising the ability of the system to meet demand without loss of load.38 We agree with commenters such as MISO and ATCLLC that certain elements may be so critical that, when taken out of service for system maintenance or to facilitate a new capital project, a subsequent unplanned outage initiated by a single-event could result in the loss of non-consequential load or may have a detrimental impact to the bulk electric system reliability. A properly planned transmission system should ensure the known, planned removal of facilities (i.e., generation, transmission or protection system facilities) for maintenance purposes without the loss of non-consequential load or detrimental impacts to system reliability such as cascading, voltage instability or uncontrolled islanding. 42. We remain concerned that proposed Reliability Standard TPL– 001–4 will materially change the number of planned outages that must be reflected in initial system conditions as compared to the existing standards. Planned outages lasting less than six months are common, and yet could be overlooked for planning purposes under the proposal. These planned outages are not ‘‘hypothetical planned outages,’’ and should not be treated as multiple contingency conditions within the planning standard. The Commission’s directive is to include known generator and transmission planned maintenance outages in planning assessments, not hypothetical planned outages. 38 ITC PO 00000 Companies Comments at 5. Frm 00085 Fmt 4700 Sfmt 4700 63043 43. While NERC has flexibility on how to address the identified concern, we believe that acceptable approaches include eliminating the six-month threshold altogether; decreasing the threshold to fewer months to include additional significant planned outages; or including parameters on what constitutes a significant planned outage based, for example, on MW or facility ratings. 44. Further, we disagree with NERC’s position that category P3 contingencies cover generator maintenance outages and category P6 covers transmission maintenance outages. P3 and P6 both consist of multiple contingencies, e.g., loss of a generating unit or transmission circuit followed by system adjustments and then the loss of another generator or transmission circuit. In approving NERC’s interpretation of Requirement R1.3.12 of TPL–002–0 and TPL–003–0, the Commission stated that ‘‘planned (including maintenance) outages are not contingencies and are required to be addressed in transmission planning for any bulk electric equipment at demand levels for which the planned outages are performed.’’ 39 The Commission further stated that it ‘‘understands that planned maintenance outages tend to be for a relatively short duration and are routinely planned at a time that provides favorable system conditions, i.e., off-peak conditions. Given that all transmission and generation facilities require maintenance at some point during their service lives, these ‘potential’ planned outages must be addressed, so long as their planned start times and durations may be anticipated as occurring for some period of time during the planning time [horizon]’’ required in the TPL Reliability Standards.40 45. With regard to BPA’s comment, we disagree that planned outages of less than one year in duration should be addressed operationally by determining new operating limits and taking other actions to mitigate the planned outage. The Commission understands that some planned outages such as planned generation outages are known more than one year in advance.41 As a result, the Commission believes the planning time horizon of the TPL Reliability Standards offers more flexibility to assess planned maintenance outages than the 39 North American Electric Reliability Corp., 131 FERC ¶ 61,068, at P 39 (2010) (approving interpretation of Reliability Standards TPL–002–0 and TPL–003–0). 40 Id. P 39. 41 See, e.g., Commissioner-Led Reliability Technical Conference, Docket Nos. AD13–6–000, RC11–6–004, RR13–2–000, July 9, 2013, Volume I at 242. E:\FR\FM\23OCR1.SGM 23OCR1 63044 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations operational time horizon. Further, we disagree with Hydro One’s comment that including planned outages of less than six months is unnecessary since long-term planning to assess transmission expansion occurs in the three to ten year timeframe. The Commission recognizes that the TPL– 001–4 Reliability Standard addresses near-term and long-term transmission planning horizons and, for the near-term horizon, requires annual assessments for years one through five. Accordingly, known planned facility outages (i.e. generation, transmission or protection system facilities) of less than six months should be addressed so long as their planned start times and durations may be anticipated as occurring for some period of time during the planning time horizon. 2. Violation Risk Factors a. Requirement R1 NERC Petition 46. NERC assigned a ‘‘medium’’ violation risk factor (VRF) for proposed Requirement R1. NERC maintains that Requirements R1.3.5, R1.3.7, R1.3.8, and R1.3.9 of the currently-effective Reliability Standard carry a VRF of ‘‘medium’’ and are similar in purpose and effect to proposed Reliability Standard, Requirement R1 because they refer to planning models that include firm transfers, existing and planned facilities, and reactive power requirements.42 tkelley on DSK3SPTVN1PROD with RULES NOPR Proposal 47. In the April 2012 NOPR, the Commission expressed that, if system models are not properly modeled or maintained, the analysis required in the Reliability Standard that uses the models in Requirement R1 may lose their validity and could directly cause or contribute to Bulk-Power System instability, separation, or a cascading sequence of failures, or could place the Bulk-Power System at an unacceptable risk of instability, separation, or cascading, or hinder restoration to a normal condition.43 The Commission noted that Requirement R1 of the Version 0 TPL Standard, which is assigned a ‘‘high’’ VRF, explicitly establishes Category A as the normal system in Table 1, which also creates the model of the normal system prior to any contingency and stated its belief that Requirement R1 of the proposed Reliability Standard and Requirement 1 of currently-effective standard both 42 NERC October 2011 Petition at Exhibit C, Table 1. 43 April 2012 NOPR, 139 FERC ¶ 61,059 at P 21. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 establish the normal system planning model that serves as the foundation for all other conditions and contingencies that are required to be studied and evaluated in a planning assessment. In the NOPR, the Commission sought comment on why Requirement R1 of proposed Reliability Standard carries a VRF of ‘‘medium’’ while Requirement R1 of the currently-effective standard carries a VRF of ‘‘high.’’ Comments 48. NERC states that Requirement R1 of the currently-effective standard directly relates to Requirement R2 of the proposed standard, which has a High VRF. NERC states that Requirement R1 of the proposed standard is a new requirement that addresses the models needed for planning assessments and therefore can have a different VRF. NERC states that while the accuracy of the transmission system model plays a key role in the TPL Reliability Standards, it is ‘‘a model, an approximation constructed and built with multiple entity inputs within a controlled process (e.g., Multiregional Model Working Group).’’ 44 NERC states the base model in proposed Requirement R1 must be modified by adjusting load forecasts and generation dispatch to better assess the range of probable outcomes that the transmission system may experience for various contingency scenarios. 49. ISO/RTOs state that proposed Requirement R1 relates to model maintenance, a necessary condition to being able to perform an assessment, which is a different matter from the current Requirement R1. According to ISO/RTOs Requirement R1 of the currently-effective standard, relating to performing an assessment, corresponds to Requirement R2 of the proposed standard, both of which carry a VRF of ‘‘high.’’ 50. EEI does not believe that proposed Requirement R1 aligns with Requirement R1 of the currentlyeffective standard. According to EEI, however, Requirement R1 does obligate ‘‘Transmission Planners and Planning Coordinators to maintain system models within their respective area for performing studies needed to complete its Planning Assessments.’’ 45 EEI further notes that these studies establish a baseline (Category P0) by which all other studies are based. EEI advocates that, if this requirement is not adhered to, faulty studies could result, possibly leading to misoperation of the system. For this reason, EEI believes the VRF 44 NERC 45 EEI PO 00000 Comments at 8. Comments at 5. Frm 00086 Fmt 4700 was improperly categorized as a medium risk VRF and suggests consideration be given to increasing the VRF to ‘‘high.’’ Commission Determination 51. We direct NERC to modify Reliability Standard TPL–001–4, Requirement R1 and change its VRF from medium to high. As discussed in the April 2012 NOPR, Requirement R1 establishes the normal system planning model that serves as the foundation for all other conditions and contingencies that are required to be studied and evaluated in a planning assessment. The Commission agrees with EEI that if the baseline studies established in Requirement R1 are not adhered to, faulty studies could result, possibly leading to misoperation of the system. 52. The Commission is not persuaded by NERC’s argument that Reliability Standard TPL–001–4, Requirement R1 warrants a medium VRF because the base model in Requirement R1 must be modified by adjusting load forecasts and generation dispatch for various contingency scenarios. Rather, the Commission finds that Requirement R1 and its sub-parts require system models to represent projected system conditions including items such as resources required for load, and real and reactive load forecasts, all of which ‘‘establishes Category P0 as the normal condition in Table 1.’’ 46 Although the Commission agrees with NERC that the accuracy of the system model plays a key role in the TPL Reliability Standards and that a system model is ‘‘a model, an approximation constructed and built with multiple entity inputs within a controlled process,’’ the Commission finds that the system model of Requirement R1 establishes a baseline (Category P0) for which all other studies are based and if not adhered to, faulty studies could result, possibly leading to misoperation of the system. 53. Further, the Commission disagrees with ISO/RTOs that proposed Requirement R1 is a different matter from the current Requirement R1. The Commission stated in the April 2012 NOPR that Requirement R1 of the Version 0 TPL Standard, which is assigned a ‘‘high’’ VRF, explicitly establishes Category A as the normal system in Table 1 that serves as the foundation for all other conditions and contingencies that are required to be studied and evaluated in a planning assessment. Accordingly, the Commission believes that TPL–001–4, Requirement R1 similarly establishes 46 NERC’s February 2013 Petition, Exhibit A, TPL–001–4, Requirement R1. Sfmt 4700 E:\FR\FM\23OCR1.SGM 23OCR1 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations Category P0 as the normal system in Table 1 that serves as the foundation for all other conditions and contingencies that are required to be studied and evaluated in a planning assessment. For these reasons, the Commission directs NERC to modify the VRF assigned to Requirement R1 from medium to high. b. VRF for Requirement R6 NERC Petition 54. NERC proposed to assign a ‘‘low’’ VRF for Requirement R6 47 because ‘‘failure to have established criteria for determining System instability is an administrative requirement affecting a planning time frame.’’ 48 NERC explains that Requirement R6 is a new requirement and that violations would not be expected to adversely affect the electrical state or capability of the bulk electric system. NOPR Proposal 55. In the NOPR, the Commission recognized that documenting criteria or methodology is an administrative act but stated that defining the criteria or methodology to be used is not an administrative act. The Commission sought clarification why the VRF level assigned to Requirement R6 is ‘‘low’’ since it appears that Requirement R6 requires more than a purely administrative task. Comments 56. NERC agrees that proposed TPL– 001–2 Requirement R6 is not strictly an administrative task, and therefore the VRF should be adjusted to medium. In its February 28, 2013 Petition, NERC revised the VRF for Reliability Standard TPL–001–4, Requirement R6 from low to medium. 57. EEI and ISO/RTOs contend that Requirement R6 was correctly assigned a ‘‘low’’ VRF because ‘‘defining and documenting’’ is an administrative task. According to EEI, the fact that the planner poorly documented the criteria and methodology does not mean that their assessment was not conducted appropriately or that it placed the bulk electric system at risk. Commission Determination tkelley on DSK3SPTVN1PROD with RULES 58. The Commission agrees with NERC that TPL–001–4, Requirement R6 47 NERC’s February 2013 Petition, Exhibit A, TPL–001–4, Requirement R6 states ‘‘[e]ach Transmission Planner and Planning Coordinator shall define and document, within their Planning Assessment, the criteria or methodology used in the analysis to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding.’’ 48 NERC’s October 2011 Petition, Exhibit C, at 110. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 is not strictly an administrative task and approves the change from a low VRF to a medium VRF. The Commission disagrees with commenters that TPL– 001–4 Reliability Standard, Requirement R6 is purely an administrative task of documentation of criteria and methodologies. Requirement R6 goes beyond documentation by requiring planners to apply engineering judgment and analysis to ‘‘define…the criteria or methodology used in the analysis to identify system instability for conditions such as cascading, voltage instability or uncontrolled islanding.’’ 49 3. Protection System Failures versus Relay Failures NERC Petition 59. NERC’s proposal includes modifications to the planning contingency categories in Table 1. NERC explains that the modifications are intended to add clarity and consistency regarding the modeling of a delayed fault clearing in a planning study. NERC stated that the basic elements of any protection system design involve inputs to protective relays and outputs from protective relays and that reliability issues associated with improper clearing of a fault on the bulk electric system can result from the failure of hundreds of individual protection system components in a substation. According to NERC, while the population of components that could fail and result in improper clearing is large, the population can be reduced dramatically by eliminating those components which share failure modes with other components. NERC stated that the critical components in protection systems are the protective relays themselves, and a failure of a nonredundant protective relay will often result in undesired consequences during a fault. According to NERC, other protection system components related to the protective relay could fail and lead to a bulk electric system issue, but the event that would be studied is identical, from both transient and steady state perspectives, to the event resulting from a protective relay failure if an adequate population of protective relays is considered.50 NOPR Proposal 60. In the April 2012 NOPR, the Commission expressed that, based on various protection system designs, the planner will have to choose which protection system component failure 49 Proposed TPL–001–4 Reliability Standard, Requirement R6. 50 NERC’s October 2011 Petition at 48. PO 00000 Frm 00087 Fmt 4700 Sfmt 4700 63045 would have the most significant impact on the Bulk-Power System because asbuilt designs are not standardized and the most critical component failure may not always be the relay.51 The Commission sought comment on whether the proposed provisions pertaining to study of multiple contingencies limits the planners’ assessment of a protection system failure because the proposed provisions only include the contingency of a faulty relay component. The Commission also sought comment on whether the relay is always the larger contingency and how the loss of protection system components that is integral to multiple protection systems impacts reliability. Comments 61. NERC states that the proposed Reliability Standard addresses the existing ambiguity requiring a study of a stuck breaker or protection system failure by specifying that both a stuck breaker and protection system failure must be evaluated. NERC states that its solution ensures that simulations of both categories are performed, reducing the probability of multiple contingency events leading to cascading and uncontrolled islanding. Similarly, Hydro One and EEI contend that a planner does not need to choose which protection system component failure would have the most significant impact on the Bulk-Power System in the planning assessment. According to Hydro One, the contingencies stipulated in Table 1, P5 of the proposed TPL Standard are appropriate for the conditions and events to be assessed in the P5 groups which focus on the combination of a single line to ground fault coupled with delayed clearing that may be caused by a protection system failing to open to clear the fault. Hydro One also states that what causes the protection system to fail is irrelevant in the context of delayed clearing by the backup protection system to clear the fault. EEI expresses concern that expanding planning studies to include all manner of protection system failures could create a scenario where planners would have to conduct unlimited and unbounded studies.’; 62. In contrast, MISO agrees with the NOPR that the more severe or larger contingency may not be assessed because the proposed Reliability Standard limits the planners’ assessment of a protection system failure since it only includes the contingency of a faulty relay component. MISO suggests expanding the assessment of relay failures to 51 April E:\FR\FM\23OCR1.SGM 2012 NOPR, 139 FERC ¶ 61,059 at P 31. 23OCR1 tkelley on DSK3SPTVN1PROD with RULES 63046 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations include all components of a protection system, including instrument transformers, protective relays, auxiliary relays and communications systems. 63. With regard to the Commission’s question whether, based on protection system as-built designs, the relay may not always be the larger contingency, NERC states that the proposed Table 1, category P5 (fault plus relay failure to operate) planning event requires evaluation of the failure of the protection system relays whose failure is most likely to cause cascading or uncontrolled islanding of the bulk electric system. 64. Hydro One recognizes that a number of components necessary to operate properly may fail to render a protection system failing to operate when needed, and that such component failures may result in disabling more than one protective relay and the impact of multiple relay failures may be more severe than the SLG fault on a bulk electric system facility with delayed clearing. According to Hydro One, the more severe consequences of an initial bulk electric system facility contingency combined with multiple or more severe protection system failures would more appropriately be considered or included in the extreme events category. 65. ISO/RTOs agree that the range of potential assessments should be expanded to include all components of a protection system including instrument transformers, protective relays, auxiliary relays and communications systems for the purpose of category P–5 contingencies, but because these devices are often in series, consideration of all of these components will not necessarily have any significant impact on analyses. 66. With regard to the question of how does the loss of a protection system component integral to multiple protection systems impact reliability, NERC states that the loss of a relay that is integral to multiple protection systems would require simulation of the full impact of that relay’s failure on the system for the event being studied under the category P5 planning event. With respect to whether there is a reliability concern regarding single points of failure on protection systems, NERC indicates that it has a project underway to assess that question.52 67. Hydro One views the avoidance of having single component failure affecting more than one protection system as a protection system design issue. Hydro One states that some regional reliability organizations have in place criteria to ensure protection 52 NERC Comments at 10. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 systems operate properly and to avoid failure of a single component affecting multiple protection systems. Commission Determination 68. The Commission agrees with NERC’s statement that Reliability Standard-TPL–001–4 addresses the existing ambiguity of the currentlyeffective TPL Reliability Standards requiring a study of a stuck breaker or protection system failure. We find that Reliability Standard TPL–001–4, specifying that both a stuck breaker and a relay failure must be evaluated, is reasonable to remove the ambiguity. Further, as explained by NERC, the loss of a relay that is integral to multiple protection systems would require simulation of the full impact of that relay’s failure on the system for the event being studied under the category P5 planning event. In addition, Reliability Standard TPL–001–4 requires study and evaluation of both a stuck breaker (Table 1, Category P4) and a relay failure (Table 1, Category P5) and that simulations of both categories reduce the probability of multiple contingency events leading to cascading, instability or uncontrolled islanding. 69. The Commission does not find the need to take any further action with regard to this issue. We note, however, that an assessment of a relay component failure may not necessarily assess the more severe or larger contingency, compared to a protection system failure under the currently-effective TPL Standards. Based on various protection system as-built designs, NERC has indicated that the planner should use ‘‘engineering judgment in its selection of the protection system component failures for evaluation that would produce the more severe system results or impact. . . . The evaluation would include addressing all protection systems affected by the selected component. A protection system component failure that impacts one or more protection systems and increases the total fault clearing time requires the [planner] to simulate the full impact (clearing time and facilities removed) on the Bulk Electric System performance.’’ 53 However, the Commission will not direct NERC to modify the standard at this time, pending completion of NERC’s work on 53 NERC Petition For The Approval of An Interpretation to Reliability Standards TPL–003–0a and TPL–004–0, April 12, 2013 at 13, Docket No. RD13–8–000, approved by unpublished letter order June 20, 3013. PO 00000 Frm 00088 Fmt 4700 Sfmt 4700 single points of failure on protection systems.54 4. Assessment of Backup or Redundant Protection Systems NOPR Proposal 70. Requirement R3, Part 3.3.1 and Requirement R4, Part 4.3.1 of Reliability Standard TPL–001–4 require that simulations duplicate what will happen in an actual power system based on the expected performance of the protection systems.55 According to NERC, these requirements ensure that, for a protection system designed ‘‘to remove multiple Elements from service for an event that the simulation will be run with all of those Elements removed from service.’’ 56 In the NOPR, the Commission observed that these provisions do not explicitly refer to ‘‘backup or redundant systems’’ as in the currently-effective Reliability Standards and sought clarification whether the proposal includes backup and redundant protection systems. Comments 71. NERC clarifies that proposed Requirement R3, Part 3.3.1 and Requirement R4, Part 4.3.1 ‘‘require the consideration of all protection systems that are relevant to the contingency studied,’’ which includes ‘‘backup and redundant systems.’’ 57 EEI believes that the language is sufficiently clear to ensure a common understanding that backup and redundant protection system impacts needed to be studied regardless of whether the specific words as found in the currently active standard were used. ISO/RTOs and MISO believe that if a protection system is not fully redundant, contingencies should be studied to simulate both delayed clearing and operation of remote backup protection to trip additional facilities when required. MISO states that if a protection system is fully redundant, that is, if a single failure of any component in the protection system (other than monitored DC voltage) would not result in delayed or failed tripping it should not be necessary to analyze the redundant protection system failure. Commission Determination 72. The Commission agrees with NERC and finds that Requirement R3, Part 3.3.1 and Requirement R4, Part 4.3.1 include the assessments of backup protection systems. The Commission 54 March 15, 2012 NERC Informational Filing in Docket No. RM10–6–000 at 5, 7, stating that NERC has initiated a data request to evaluate potential exposure to types of protection system failures. 55 NERC’s October 2011 Petition at 20. 56 Id. 57 NERC Comments at 11. E:\FR\FM\23OCR1.SGM 23OCR1 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations 73. In the April 2012 NOPR, the Commission sought clarification whether ‘‘fault types’’ in Table 1 refers to the initiating event.58 load models and proxies to simulate cascade.59 77. The Commission is satisfied and agrees with the comments submitted by NERC, EEI and ISO/RTO on issues regarding controlled load interruption (i.e., third parties must have the same non-consequential load loss options as available to the planner), dynamic load models (i.e., documentation of dynamic load models used in system studies and the supporting rationale for their use is required) and proxies to simulate cascade (i.e., planners must define and document their criteria or methodology including proxies that are used in planning assessments due to modeling and simulation limitations). Below, we address in greater detail the comments on peer review of planning assessments, spare equipment strategy, range of extreme events, and footnote ‘a.’ Comments a. Peer Review of Planning Assessments 74. NERC, EEI, BPA and ISO/RTOs all concur that ‘‘fault types’’ refer to the initiating fault to be studied, not to what the fault may evolve into as a result of the simulated conditions. According to NERC, the possibility of a single-line-toground fault evolving into a three-phase fault is addressed by requiring the study of a three-phase fault as the initial fault. NOPR Proposal 78. The Commission stated in Order No. 693 that, because neighboring systems may adversely impact one another, such systems should be involved in determining and reviewing system conditions and contingencies to be assessed under the currently-effective TPL Reliability Standards.60 In its petition, NERC stated the proposed Reliability Standard does not include a ‘‘peer review’’ of planning assessments but instead includes an equally effective and efficient manner to provide for the appropriate sharing of information with neighboring systems in proposed Requirement R3, Part 3.4.1, Requirement R4, Part 4.4.1, and Requirement R8.61 79. In the April 2012 NOPR, the Commission sought clarification on how the NERC proposal ensures the early input of peers into the planning assessments or any type of coordination among peers will occur. The Commission also sought comment on whether and how neighboring systems can sufficiently evaluate and provide feedback to the planners on the development and result of assessments and whether it requires input on the comments to be included in the results or the development of the planning assessments. agrees with ISOs/RTOs and MISO that if a primary protection system has a fully redundant backup protection system, assessments of the primary protection system is required, but not of the fully redundant backup protection system since the assessment results will be identical. Further, we agree that if a protection system is not fully redundant, contingencies are studied to simulate both delayed clearing and operation of remote backup protection which may trip additional facilities when required. P5 Single Line to Ground Faults NOPR Proposal Commission Determination’ 75. The Commission finds that the explanation of NERC and others, i.e., ‘‘fault types’’ in Reliability Standard TPL–001–4, Table 1—Steady State & Stability Performance Planning Events means the type of fault that initiated the event, is reasonable. For example, if the initiating fault type is a single-line-toground fault and it evolves into a threephase fault, the single-line-to-ground fault is still evaluated as the initiating fault type. If a three-phase fault occurs as the initiating event, the fault is assessed as a three phase fault. Regardless of what the initiating fault type becomes, it does not change the initiating fault type. tkelley on DSK3SPTVN1PROD with RULES 6. Order No. 693 Directives 76. In the April 2012 NOPR, the Commission indicated that the Version 4 TPL Standard appeared responsive to the Order No. 693 directives regarding the TPL Reliability Standards. However, the Commission sought clarification and comment on the following issues: (a) Peer review of planning assessments, (b) spare equipment strategy, (c) range of extreme events, (d) footnote ‘a’ and (e) controlled load interruption, dynamic 58 April 2012 NOPR, 139 FERC ¶ 61,059 at P 38. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 Comments 80. NERC and EEI state that, prior to sharing planning assessment results in Requirement R8, Requirement R3, Part 59 April 2012 NOPR, 139 FERC ¶ 61,059 at PP 39– 54. 60 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1750. 61 NERC’s October 2011 Petition at 21. PO 00000 Frm 00089 Fmt 4700 Sfmt 4700 63047 3.4.1 and Requirement R4, Part 4.4.1 require planners to coordinate with adjacent planners to develop contingency lists for steady state and stability analysis. EEI states it is most beneficial to planners if coordination occurs earlier in the planning assessment process. 81. NERC and EEI also explain that Requirements R2 through R6 provide adjacent entities sufficient information on how the assessment was performed and expected system performance to effectively evaluate the assessment results and to provide feedback. Further, Requirement R8 requires that each planner must distribute its planning assessment results to adjacent planners within 90 calendar days of completing its assessment. 82. 1BPA states that, while adjacent planners and coordinators should have a stake in the results of an affected planning assessment, they should not be allowed to second guess the transmission planner’s or planning coordinator’s studies and methodologies. BPA adds that it is important for adjacent planners to have input on how other planning assessments will affect them, and the proposed Reliability Standards allows such input. Commission Determination 83. The Commission agrees with NERC and EEI that coordination of contingency lists with adjacent planners under TPL–001–4 Reliability Standard, Requirement R3, Part 3.4.1 and Requirement R4, Part 4.4.1 ensures that contingencies on adjacent systems that impact other systems are developed and included in the planners’ steady state and stability analysis planning assessments.62 Coordination of contingency lists provides one aspect of early coordination among planners. 84. We are satisfied with the explanation of NERC and EEI that TPL– 001–4 Reliability Standard, Requirement R8 allows planners to coordinate and distribute conditions to adjacent planners as part of their planning assessment and to provide feedback to other planners. While we also agree with BPA that adjacent planners should be informed of and have a stake in the results of another planner’s assessment, we disagree with BPA’s characterization that a planner ‘‘should not be allowed to second guess’’ another planner’s studies or 62 Because neighboring systems may be adversely impacted by other systems, such systems should be involved early in determining and reviewing conditions and contingencies in planning assessments. Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 1750, 1754. E:\FR\FM\23OCR1.SGM 23OCR1 63048 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations methodologies. Rather, early peer input in the planning assessments and coordination among peers to identify possible interdependent or adverse impacts on neighboring systems are essential to the reliable operation of the bulk electric system.63 Spare Equipment Strategy NOPR Proposal 85. In Order No. 693, the Commission directed NERC to develop a modification ‘‘to require assessments of outages of critical long lead-time equipment, consistent with the entity’s spare equipment strategy.’’ 64 In response, NERC developed proposed Requirement 2, Part 2.1.5 which addresses steady state conditions to determine system response when equipment is unavailable for prolonged periods of time. 86. In the NOPR, the Commission raised the concern that the proposed spare equipment strategy appears to be limited to ‘‘steady state analysis’’ and sought clarification why ‘‘stability analysis’’ conditions are not mentioned. Comments 87. NERC, ISOs/RTOs, and EEI comment that the burden of additional stability analyses would not provide significant reliability benefits because stability analysis already required under ‘‘category P6’’ will produce more definitive tests of longer-term equipment unavailability. They also claim that any potential stability impacts related to an entity’s spare equipment strategy will be observed in the normal planning process driven by other requirements. tkelley on DSK3SPTVN1PROD with RULES Commission Determination 88. The Commission agrees that NERC has met the spare equipment strategy directive for steady state analysis under Reliability Standard TPL–001–4, Requirement R2, Part 2.1.5. However, the Commission finds that a spare equipment strategy for stability analysis is not addressed under category P6. 89. The spare equipment strategy for steady state analysis under Reliability Standard TPL–001–4, Requirement R2, Part 2.1.5 requires that steady state studies be performed for the P0, P1 and P2 categories identified in Table 1 with the conditions that the system is 63 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1754: ‘‘Given that neighboring systems assessments by one entity may identify possible interdependant or adverse impacts on its neighboring systems, this peer review will provide an early opportunity to provide input and coordinate plans.’’ 64 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1786. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 expected to experience during the possible unavailability of the long lead time equipment. The Commission believes that a similar spare equipment strategy for stability analysis should exist that requires studies to be performed for P0, P1 and P2 categories with the conditions that the system is expected to experience during the possible unavailability of the long lead time equipment. Further, we are not persuaded by the explanation of NERC and others that a similar spare equipment strategy for stability analysis would cause unjustified burden because stability analysis is already required under category P6. The Commission notes that the category P2 contingencies studied under the spare equipment strategy for steady state analysis are different than the contingencies studied under category P6. For example, under the spare equipment strategy for steady state, a planner would study a long leadtime piece of equipment out of service (e.g., a transformer) along with a bus section fault contingency (i.e., category P2, event 2). The study of this same condition for stability analysis under category P6 is not addressed. However, the Commission will not direct a change and instead directs NERC to consider a similar spare equipment strategy for stability analysis upon the next review cycle of Reliability Standard TPL–001– 4. Comments C. Range of Extreme Events 91. NERC asserts that it addressed the Order No. 693 directive to expand the range of events considered in the planning assessment by adding a new category ‘‘wide area events’’ as extreme events. NERC contends that it is raising the bar concerning extreme events by requiring the planners to evaluate the loss of two generating stations for a wide range of external events that could cause the loss of all generating units at two generating stations. NERC adds that extreme events in item 3b of Table 1 means that the planner will consider even more extreme events (i.e., the loss of more facilities than the loss of two generating stations) based upon operating experience and knowledge of its system. 92. EEI agrees with the Commission that there are conditions that provide far more serious impacts to the grid than that which is described in item 3a of Table 1 of the proposed standard. However, those conditions are largely area specific thereby making it impossible to describe or address all possibilities in a Standard. EEI, therefore, supports NERC’s approach which obligates planners to consider, as stated in Item 3b, ‘‘[o]ther events based upon operating experience that may result in wide area disturbances.’’ EEI believes that Table 1, Item No. 3b provides the necessary backstop to ensure that extreme events are fully captured from a planning standpoint.67 NOPR Proposal Commission Determination 90. In Order No. 693, the Commission directed NERC to modify the Version 0 Reliability Standard, TPL–004–0, to require that, in determining the range of the extreme events to be assessed, the contingency list of category D would be expanded to include recent events such as hurricanes and ice storms.65 In the April 2012 NOPR, the Commission indicated that, while the proposed Version 4 TPL Standard appropriately expands the list of extreme event examples in Table 1, the list limits these items to the loss of two generating stations under Item No. 3a. The Commission sought clarification on conditioning extreme events on the loss of two generating stations.66 The Commission also sought clarification regarding whether the ‘‘two generation stations’’ limitation would adequately capture a scenario where an extreme event can impact more than two generation stations. 93. The Commission is satisfied with the explanation of NERC and EEI that Table 1, item No. 3b provides the necessary backstop to ensure that extreme events are fully captured from a planning standpoint including extreme events that can impact more than two generating stations and that a planner will consider even more extreme events based on operating experience and knowledge of its system. 65 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1834. 66 April 2012 NOPR, 139 FERC ¶ 61,059 at P 48. PO 00000 Frm 00090 Fmt 4700 Sfmt 4700 d. Footnote ‘a’ NOPR Proposal 94. In Order No. 693, the Commission directed NERC to modify footnote ‘a’ of Table 1 with regard to ‘‘applicability of emergency ratings and consistency of normal ratings and voltages with values obtained from other reliability standards.’’ 68 In its petition, NERC noted that proposed Table 1, header note ‘e,’ which provides that planned system adjustments must be executable 67 EEI Comments at 14–15. No. 693, FERC Stats. & Regs. ¶ 31,242 at 68 Order P 1770. E:\FR\FM\23OCR1.SGM 23OCR1 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES within the time duration applicable to facility ratings. Further, according to NERC, header note ‘f,’ which states applicable facility ratings shall not be exceeded, meets the Order No. 693 directive pertaining to footnote ‘a’ in the current standard. 95. In the NOPR the Commission observed that the proposed standard applies header note ‘e’ to ‘‘Steady State and Stability,’’ while header note ‘f’ is excluded from ‘‘Stability’’ and only applies to ‘‘Steady State’’ studies. Accordingly, the Commission sought clarification regarding the rationale for excluding header note ‘f’ from ‘‘Stability’’ studies. In addition, for Table 1, header notes ‘e’ and ‘f,’ the Commission sought comment on whether the normal facility ratings align with Reliability Standard FAC–008–1 and normal voltage ratings align with Reliability Standard VAR–001–1. Furthermore, the Commission sought clarification whether facility ratings used in planning assessments align with other reliability standards such as Reliability Standards NUC–001–2, BAL– 001–0.1a and the PRC Reliability Standards for UFLS and UVLS. Comments 96. NERC states that it excluded header note ‘f’ from stability studies because facility ratings are defined for a finite period which may be between a few minutes and several hours, or longer. According to NERC, in stability studies the analysis is conducted over a few seconds and because facility ratings are established based on the overheating of elements, the few seconds in the stability timeframe is not significant to the overheating of elements.69 97. ISO/RTO states that the observation of facility trip ratings (i.e., relay trip ratings) are valid in the stability simulation time frame, and should be considered if associated protective relay schemes are sensitive to power swings (e.g., impedance relays with no out-of step trip blocking for stable swings, etc.). Further, ISO/RTO believes that there is no reason to include a requirement to observe thermal facility ratings in stability studies, but also believes that facility trip ratings should be observed in stability studies. 98. NERC and EEI also explain that the values used for facility ratings within transmission planning models are developed in accordance with standard FAC–008–1 ‘‘Facility Ratings Methodology’’ and communicated to other functional entities as required by 69 See also BPA Comments at 5, EEI Comments at 15 and ISO/RTOs Comments at 11. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 FAC–009–1 ‘‘Establish and Communicate Facility Ratings.’’ 99. In response to the Commission’s request for clarification whether facility ratings used in planning assessments align with other Reliability Standards, commenters generally stated that facility ratings used in the TPL standard are consistent throughout the NERC standards. Further, commenters stated that Reliability Standard VAR–001–2 is not a ratings standard but an operational (real-time) standard to ensure voltage levels, reactive flows and reactive resources are monitored, controlled and maintained within the limits of the equipment.70 Commission Determination 100. The Commission is satisfied with commenters’ explanation and agrees that it is not necessary to include a requirement to observe thermal facility ratings in stability studies. The Commission agrees with ISO/RTO that facility trip ratings (i.e., relay trip ratings) are valid ratings in the stability simulation time frame, and should be considered in the planning assessment if associated protective relay schemes are sensitive to power swings (e.g., impedance relays with no out-of step trip blocking for stable swings). Further, the Commission accepts the explanation of NERC and others that facility ratings used in planning assessments are determined in accordance with Reliability Standard FAC–008–3,71 which states that a ‘‘Facility Rating shall respect the most limiting applicable Equipment Rating of the individual equipment that comprises that Facility.’’ C. Other Matters Raised by Commenters 101. Powerex states that additional clarification is needed with respect to Footnote 9 to Table 1 in order to provide clarity and ensure consistent interpretation as to when transmission planners may plan to curtail firm transmission service. Powerex is concerned that the revised TPL Standard may provide transmission planners with broad discretion to plan for the curtailment of firm transmission service without providing purchaseselling entities with the notice and certainty they need to make appropriate alternate arrangements. Powerex believes that the phrase in footnote 9 ‘‘resources obligated to re-dispatch’’ should be clarified as referring to a 70 See NERC Comments at 16 and EEI Comments at 15. 71 In ‘‘Order Approving Reliability Standard’’ issued November 17, 2011 (Docket No. RD11–10– 000), the Commission approved FAC–008–3 Reliability Standard and the retirement of FAC– 008–1 and FAC–009–1 Reliability Standards. PO 00000 Frm 00091 Fmt 4700 Sfmt 4700 63049 formal agreement between the transmission provider and a generation owner, located on the load side of a transmission constraint, to resupply the load that had been receiving energy from a remote source before the firm transmission service was curtailed. Commission Determination 102. We will not direct NERC to modify footnote 9. We find NERC’s explanation satisfactory that ‘‘the planner must be able to show that the curtailment is supported by a valid redispatch of generation that would be ‘obligated to redispatch’ . . . [t]herefore, the planner cannot simply re-dispatch units outside the area of control for the transmission system for which it is reviewing—the re-dispatch must be valid and realistic.’’ 72 III. Information Collection Statement 103. The Office of Management and Budget (OMB) regulations require that OMB approve certain reporting and recordkeeping (collections of information) imposed by an agency.73 Upon approval of a collection(s) of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. 104. The Commission is submitting these reporting and recordkeeping requirements to OMB for its review and approval under section 3507(d) of Paperwork Reduction Act of 1995. The Commission solicited comments on the need for and the purpose of the information contained in Reliability Standard TPL–001–4 and the corresponding burden to implement the Reliability Standard. The Commission received comments on specific requirements in the Reliability Standard, which we address in this Final Rule. However, the Commission did not receive any comments on our reporting burden estimates. The Final Rule approves Reliability Standard TPL–001–4. 105. Public Reporting Burden: The burden and cost estimates below are based on the increase in the reporting and recordkeeping burden imposed by the proposed Reliability Standards. Our estimates are based on the NERC Compliance Registry as of February 28, 2013, which indicate that NERC has 72 NERC Petition, Consideration of Comments on Assess Transmission Future Needs and Develop Transmission Plans—Project 2006–02, draft 6, pp. 78–79. 73 5 CFR 1320.11. E:\FR\FM\23OCR1.SGM 23OCR1 63050 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations registered 183 transmission planners and planning coordinators. Number and type of entity 75 Number of annual responses per entity Average number of paperwork hours per response Total burden hours (1) (2) (3) (1)*(2)*(3) Year 1 ....................... 183 Transmission Planners and Planning Coordinators. 1 response ................ 9 (5 engineer hours and 4 record keeping hours). 1,647 Year 2 and Year 3 .... 183 Transmission Planners and Planning Coordinators. 183 Transmission Planners and Planning Coordinators. 1 response ................ 5 (3 engineer hours and 2 record keeping hours). 145 (84 engineer hours, 61 record keeping hours). 915 183 Transmission Planners and Planning Coordinators. 1 Transmission Planner and Planning Coordinator. 1 response ................ 15,372 1 Transmission Planner and Planning Coordinator. 4 responses to Attachment 1, Sections I, II, and III. 84 (45 engineer hours, 39 record keeping hours). 63 (40 engineer hours, 17 record keeping hours, 6 legal hours). 68 (40 engineer hours, 20 record keeping hours, 8 legal hours). Improved requirement 74 Identification of Joint Responsibilities and System Modeling Enhancements 76. New Assessments, Simulations, Studies, Modeling Enhancements and associated Documentation77. Year Year 2 ....................... Year 3 ....................... Attachment 1 stakeholder process. Year 3 ....................... Year 3 ....................... tkelley on DSK3SPTVN1PROD with RULES Costs To Comply With Paperwork Requirements • Year 1: $77,592. • Year 2: $1,312,659. • Year 3 and ongoing: $820,149. 106. Year 1 costs include the implementation of those improved requirements that become effective on the first day of the first calendar quarter, 12 months after applicable regulatory approval, which include requirements such as coordination between entities and incremental system modeling enhancements. Year 2 costs include a portion of year 1 reoccurring costs plus the implementation of the remaining improved requirements that become effective on the first day of the first calendar quarter, 24 months after applicable regulatory approval, which 74 Each requirement identifies a reliability improvement by proposed Reliability Standard TPL–001–4. 75 NERC registered transmission planners and planning coordinators responsible for the improved requirement. Further, if a single entity is registered as both a transmission planner and planning coordinator, that entity is counted as one unique entity. 76 The Commission estimates a reduction in burden hours from year 1 to year 2 because year 1 represents a portion of one-time tasks not repeated in subsequent years. 77 The Commission estimates a reduction in burden hours from year 2 to year 3 because year 2 represents a portion of one-time tasks not repeated in subsequent years. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 1 response ................ 12 responses to Attachment 1, sections I and II. include requirements such as sensitivity studies for steady state and stability analysis, implementation of a spare equipment strategy, short circuit studies, an expansion of contingencies and extreme events, and all associated system modeling enhancements and documentation. Year 3 costs include a portion of year 2 reoccurring costs plus an estimated cost for Attachment 1 stakeholder process, if needed. 107. For the burden categories above, the loaded (salary plus benefits) costs are: $60/hour for an engineer; $31/hour for recordkeeping; and $128/hour for legal.78 The estimated breakdown of annual cost is as follows: • Year 1 Æ Identification of Joint Responsibilities and System Modeling Enhancements: 183 entities * [(5 hours/ response * $60/hour) + (4 hours/ response * $31/hour)] = $77,592. • Year 2 Æ Identification of Joint Responsibilities and System Modeling Enhancements: 183 entities * [(3 hours/ response * $60/hour) + (2 hours/ response * $31/hour)] = $44,286. 78 Labor rates from Bureau of Labor Statistics (BLS) (https://bls.gov/oes/current/naics2_22.htm). Loaded costs are BLS rates divided by 0.703 and rounded to the nearest dollar (https://www.bls.gov/ news.release/ecec.nr0.htm). PO 00000 Frm 00092 Fmt 4700 Sfmt 4700 26,535 756 272 Æ New Assessments, Simulations, Studies, Modeling Enhancements and associated Documentation: 183 entities * [(84 hours/response * $60/hour) + (61 hours/response * $31/hour)] = $1,268,373. • Year 3 Æ Identification of Joint Responsibilities and System Modeling Enhancements: 183 entities * [(3 hours/ response * $60/hour) + (2 hours/ response * $31/hour)] = $44,286. Æ New Assessments, Simulations, Studies, Modeling Enhancements and associated Documentation: 183 entities * [(45 hours/response * $60/hour) + (39 hours/response * $31/hour)] = $715,347. Æ Implementation of footnote 12 and the stakeholder process: {12 responses * [(40 hours/response * $60/hour) + (17 hours/response * $31/hour) + (6 hours/ response * $128/hour)]} + {4 responses * [(40 hours/response * $60/hr) + (20 hours/response * $31/hour) + (8 hours/ response * $128/hour)]} = $60,516. Title: 725N, Mandatory Reliability Standards: Reliability Standard TPL– 001–4.79 79 The Supplemental NOPR used the identifier FERC–725A (OMB Control No. 1902–0244). However, for administrative purposes and to submit the information collection requirements to OMB timely, the requirements were labeled FERC–725N (OMB Control No. 1902–0264) in the submittal to OMB associated with the NOPR. We are using E:\FR\FM\23OCR1.SGM 23OCR1 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES Action: Proposed Collection FERC– 725N. OMB Control No: 1902–0264. Respondents: Business or other for profit, and not for profit institutions. Frequency of Responses: Annually and one-time. Necessity of the Information: The approved Reliability Standard TPL– 001–4 implements the Congressional mandate of the Energy Policy Act of 2005 to develop mandatory and enforceable Reliability Standards to better ensure the reliability of the nation’s Bulk-Power System. Specifically, the Reliability Standard ensures that planning coordinators and transmission planners establish transmission system planning performance requirements within the planning horizon to develop a bulk electric system that will operate reliability and meet specified performance requirements over a broad spectrum of system conditions to meet present and future system needs. Internal review: The Commission has reviewed the revised Reliability Standard TPL–001–4 and made a determination that its action is 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. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: 202–502–8663, fax: 202–273–0873]. For submitting comments concerning the collection(s) of information and the associated burden estimate(s), please send your comments to the Commission and to the Office of Management and Budget, Office of Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: 202–395–4638, fax: 202–395– 7285]. For security reasons, comments to OMB should be submitted by email to: oira_submission@omb.eop.gov. Comments submitted to OMB should include FERC–725N and Docket Nos. RM12–1–000 and RM13–9–000. IV. Environmental Analysis 108. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement FERC–725N in this Final Rule and in the associated submittal to OMB. VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 for any action that may have a significant adverse effect on the human environment.80 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.81 The actions proposed herein fall within this categorical exclusion in the Commission’s regulations. V. Regulatory Flexibility Act Analysis 109. The Regulatory Flexibility Act of 1980 (RFA) 82 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The RFA mandates consideration of regulatory alternatives that accomplish the stated objectives of a proposed rule and that minimize any significant economic impact on a substantial number of small entities. The Small Business Administration’s (SBA) Office of Size Standards develops the numerical definition of a small business.83 The SBA has established a size standard for electric utilities, stating that a firm is small if, including its affiliates, it is primarily engaged in the transmission, generation and/or distribution of electric energy for sale and its total electric output for the preceding twelve months did not exceed four million megawatt hours.84 110. As discussed above, Reliability Standard TPL–001–4 would apply to 183 transmission planners and planning coordinators identified in the NERC Compliance Registry. Comparison of the NERC Compliance Registry with data submitted to the Energy Information Administration on Form EIA–861 indicates that, of the 183 registered transmission planners and planning coordinators registered by NERC, 41 may qualify as small entities. 111. The Commission estimates that, on average, each of the 41 small entities affected will have an estimated cost of $1,324 in Year 1, $16,953 in Year 2 85 and $11,471 in Year 3 (without Attachment 1). In addition, based on the 80 Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987). 81 18 CFR 380.4(a)(2)(ii). 82 5 U.S.C. 601–12. 83 13 CFR 121.101. 84 13 CFR 121.201, Sector 22, Utilities & n.1. 85 The increase in Year 2 costs include a portion of year 1 recurring costs plus the implementation of the remaining improved requirements that become effective on the first day of the first calendar quarter, 24 months after applicable regulatory approval. PO 00000 Frm 00093 Fmt 4700 Sfmt 4700 63051 results of NERC’s data request approximately 10 percent of all registered transmission planners and planning coordinators used planned non-consequential load loss under the currently-effective TPL Reliability Standards. The Commission estimates that approximately 4 of the 41 small entities would use the stakeholder process set forth in Attachment 1. The total estimated cost per response for each of these 4 small entities in Year 3 is approximately $19,500 if Attachment 1, sections I and II are used, or $20,000 if Attachment 1, sections I, II and III are used. These figures are based on information collection costs plus additional costs for compliance. Based on this estimate, the Commission certifies that Reliability Standard TPL– 001–4 will not have a significant economic impact on a substantial number of small entities. Accordingly, no regulatory flexibility analysis is required. VI. Document Availability 112. 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 (https:// 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. 113. 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. 114. 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 115. These regulations are effective December 23, 2013. The Commission has determined that this rule is not a ‘‘major rule’’ as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. E:\FR\FM\23OCR1.SGM 23OCR1 63052 Federal Register / Vol. 78, No. 205 / Wednesday, October 23, 2013 / Rules and Regulations By the Commission. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2013–24828 Filed 10–22–13; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection DEPARTMENT OF THE TREASURY 19 CFR Parts 10, 24, 162, 163, and 178 [USCBP–2013–0040; CBP Dec. 13–17] RIN 1515–AD93 United States-Panama Trade Promotion Agreement U.S. Customs and Border Protection, Department of Homeland Security; Department of the Treasury. ACTION: Interim regulations; solicitation of comments. AGENCY: This rule amends the U.S. Customs and Border Protection (CBP) regulations on an interim basis to implement the preferential tariff treatment and other customs-related provisions of the United States-Panama Trade Promotion Agreement entered into by the United States and the Republic of Panama. DATES: Interim rule effective October 23, 2013; comments must be received by December 23, 2013. ADDRESSES: You may submit comments, identified by docket number, by one of the following methods: • Federal eRulemaking Portal: https:// www.regulations.gov. Follow the instructions for submitting comments via docket number USCBP–2013–0040. • Mail: Trade and Commercial Regulations Branch, Regulations and Rulings, Office of International Trade, U.S. Customs and Border Protection, 90 K Street NE., 10th Floor, Washington, DC 20229–1177. Instructions: All submissions received must include the agency name and docket number for this rulemaking. All comments received will be posted without change to https:// www.regulations.gov, including any personal information provided. For detailed instructions on submitting comments and additional information on the rulemaking process, see the ‘‘Public Participation’’ heading of the SUPPLEMENTARY INFORMATION section of this document. Docket: For access to the docket to read background documents or tkelley on DSK3SPTVN1PROD with RULES SUMMARY: VerDate Mar<15>2010 16:30 Oct 22, 2013 Jkt 232001 comments received, go to https:// www.regulations.gov. Submitted comments may also be inspected during regular business days between the hours of 9 a.m. and 4:30 p.m. at the Trade and Commercial Regulations Branch, Regulations and Rulings, Office of International Trade, U.S. Customs and Border Protection, 90 K Street NE., 10th Floor, Washington, DC. Arrangements to inspect submitted comments should be made in advance by calling Mr. Joseph Clark at (202) 325–0118. FOR FURTHER INFORMATION CONTACT: Textile Operational Aspects: Diane Liberta, Textile Operations Branch, Office of International Trade, (202) 863– 6241. Other Operational Aspects: Katrina Chang, Trade Policy and Programs, Office of International Trade, (202) 863– 6532. Legal Aspects: Karen Greene, Regulations and Rulings, Office of International Trade, (202) 325–0041. SUPPLEMENTARY INFORMATION: Public Participation Interested persons are invited to participate in this rulemaking by submitting written data, views, or arguments on all aspects of the interim rule. U.S. Customs and Border Protection (CBP) also invites comments that relate to the economic, environmental, or federalism effects that might result from this interim rule. Comments that will provide the most assistance to CBP in developing these regulations will reference a specific portion of the interim rule, explain the reason for any recommended change, and include data, information, or authority that support such recommended change. See ADDRESSES above for information on how to submit comments. Background On June 28, 2007, the United States and the Republic of Panama (the ‘‘Parties’’) signed the United StatesPanama Trade Promotion Agreement (‘‘PANTPA’’ or ‘‘Agreement’’). On October 21, 2011, the President signed into law the United StatesPanama Trade Promotion Agreement Implementation Act (the ‘‘Act’’), Public Law 112–43, 125 Stat. 497 (19 U.S.C. 3805 note), which approved and made statutory changes to implement the PANTPA. Section 103 of the Act requires that regulations be prescribed as necessary to implement the provisions of the PANTPA. On October 29, 2012, the President signed Proclamation 8894 to implement the PANTPA. The Proclamation, which PO 00000 Frm 00094 Fmt 4700 Sfmt 4700 was published in the Federal Register on November 5, 2012, (77 FR 66507), modified the Harmonized Tariff Schedule of the United States (‘‘HTSUS’’) as set forth in Annexes I and II of Publication 4349 of the U.S. International Trade Commission. The modifications to the HTSUS included the addition of new General Note 35, incorporating the relevant PANTPA rules of origin as set forth in the Act, and the insertion throughout the HTSUS of the preferential duty rates applicable to individual products under the PANTPA where the special program indicator ‘‘PA’’ appears in parenthesis in the ‘‘Special’’ rate of duty subcolumn. The modifications to the HTSUS also included a new Subchapter XIX to Chapter 99 to provide for temporary tariff-rate quotas and applicable safeguards implemented by the PANTPA, as well as modifications to Subchapter XXII of Chapter 98. After the Proclamation was signed, CBP issued instructions to the field and the public implementing the Agreement by allowing the trade to receive the benefits under the PANTPA effective on or after October 31, 2012. CBP is responsible for administering the provisions of the PANTPA and the Act that relate to the importation of goods into the United States from the Republic of Panama (‘‘Panama’’). Those customs-related PANTPA provisions, which require implementation through regulation, include certain tariff and non-tariff provisions within Chapter One (Initial Provisions), Chapter Two (General Definitions), Chapter Three (National Treatment and Market Access for Goods), Chapter Four (Rules of Origin and Origin Procedures), and Chapter Five (Customs Administration and Trade Facilitation). Certain general definitions set forth in Chapter Two of the PANTPA have been incorporated into the PANTPA implementing regulations. These regulations also implement Article 3.6 (Goods Re-entered after Repair or Alteration) of the PANTPA. Chapter Three of the PANTPA sets forth provisions relating to trade in textile and apparel goods between Panama and the United States. The provisions within Chapter Three that require regulatory action by CBP are Articles 3.21 (Customs Cooperation), Article 3.25 (Rules of Origin and Related Matters), and Article 3.30 (Definitions). Chapter Four of the PANTPA sets forth the rules for determining whether an imported good is an originating good of a Party and, as such, is therefore eligible for preferential tariff (duty-free or reduced duty) treatment under the PANTPA as specified in the Agreement E:\FR\FM\23OCR1.SGM 23OCR1

Agencies

[Federal Register Volume 78, Number 205 (Wednesday, October 23, 2013)]
[Rules and Regulations]
[Pages 63036-63052]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-24828]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket Nos. RM12-1-000 and RM13-9-000; Order No. 786]

Transmission Planning Reliability Standards

AGENCY: Federal Energy Regulatory Commission, Energy.

ACTION: Final rule.

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SUMMARY: Under section 215 of the Federal Power Act, the Federal Energy
Regulatory Commission approves Transmission Planning (TPL) Reliability
Standard TPL-001-4, submitted by the North American Electric
Reliability Corporation, the Commission-certified Electric Reliability
Organization. Reliability Standard TPL-001-4 introduces significant
revisions and improvements by requiring annual assessments addressing
near-term and long-term planning horizons for steady state, short
circuit and stability conditions. Reliability Standard TPL-001-4 also
includes a provision that allows a transmission planner to plan for
non-consequential load loss following a single contingency by providing
a blend of specific quantitative and qualitative parameters for the
permissible use of planned non-consequential load loss to address bulk
electric system performance issues, including firm limitations on the
maximum amount of load that an entity may plan to shed, safeguards to
ensure against inconsistent results and arbitrary determinations that
allow for the planned non-consequential load loss,

[[Page 63037]]

and a more specifically defined, open and transparent, verifiable, and
enforceable stakeholder process. The Commission finds in the Final Rule
that the proposed Reliability Standard is just, reasonable, not unduly
discriminatory or preferential, and in the public interest. In
addition, the Commission directs NERC to modify Reliability Standard
TPL-001-4 to address the concern that the standard could exclude
planned maintenance outages of significant facilities from future
planning assessments and directs NERC to change the TPL-001-4,
Requirement R1 Violation Risk Factor from medium to high.

DATES: This rule will become effective December 23, 2013.

FOR FURTHER INFORMATION CONTACT:

Eugene Blick (Technical Information), Office of Electric Reliability,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, Telephone: (202) 502-8066, Eugene.Blick@ferc.gov.
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, Robert.Stroh@ferc.gov.

SUPPLEMENTARY INFORMATION:

145 FERC ] 61,051

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, Cheryl A. LaFleur, and Tony Clark.

(Issued October 17, 2013)

1. Under section 215(d) of the Federal Power Act (FPA), the
Commission approves Transmission Planning (TPL) Reliability Standard
TPL-001-4, submitted by the North American Electric Reliability
Corporation (NERC), the Commission-certified Electric Reliability
Organization (ERO).\1\ The Commission finds that Reliability Standard
TPL-001-4 introduces significant revisions and improvements to the TPL
Reliability Standards, including increased specificity of data required
for modeling conditions, and requires annual assessments addressing
near-term and long-term planning horizons for steady state, short
circuit and stability conditions. Further, we find that the Reliability
Standard generally addresses the Commission directives set forth in
Order No. 693 and subsequent Commission orders.\2\ We agree with NERC
that Reliability Standard TPL-001-4 includes specific improvements over
the currently-effective Transmission Planning Reliability Standards and
is responsive to the Commission's directives.
---------------------------------------------------------------------------

\1\ 16 U.S.C. 824o(d) (2006).
\2\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, FERC Stats. & Regs. ] 31,242, order on reh'g, Order
No. 693-A, 120 FERC ] 61,053 (2007).
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2. Further, in response to Order No. 762,\3\ Reliability Standard
TPL-001-4 includes a provision that allows a transmission planner to
plan for non-consequential load loss following a single contingency.
While the Reliability Standard provides that ``an objective of the
planning process is to limit the likelihood and magnitude of Non-
Consequential Load Loss following planning events,'' the standard also
recognizes that ``[i]n limited circumstances, Non-Consequential Load
Loss may be needed throughout the planning horizon to ensure that BES
performance requirements are met.'' \4\ Thus, for such limited
circumstances, Reliability Standard TPL-001-4 provides a blend of
specific quantitative and qualitative parameters for the permissible
use of planned non-consequential load loss to address bulk electric
system performance issues, including firm limitations on the maximum
amount of load that an entity may plan to shed, safeguards to ensure
against inconsistent results and arbitrary determinations that allow
for the planned non-consequential load loss, and a more specifically
defined, open and transparent, verifiable, and enforceable stakeholder
process.
---------------------------------------------------------------------------

\3\ Transmission Planning Reliability Standards, Order No. 762,
139 FERC ] 61,060 (2012) (Order No. 762), order on reconsideration,
140 FERC ] 61,101 (2012). See also Transmission Planning Reliability
Standards, 139 FERC ] 61,059 (2012) (April 2012 NOPR).
\4\ Reliability Standard TPL-001-4, Table I (Steady State and
Stability Performance Extreme Events), n.12.
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3. For the reasons discussed in detail below, the Commission finds
that Reliability Standard TPL-001-4 is just, reasonable, not unduly
discriminatory or preferential, and in the public interest. Therefore,
pursuant to section 215(d) of the FPA the Commission approves proposed
Reliability Standard TPL-001-4. Thus, the Commission approves footnote
12 to Table 1 of the Reliability Standard (formerly referred to as
footnote `b'). In addition, as discussed below, the Commission finds
NERC's explanation on protection system failures versus relay failures,
assessment of backup or redundant protection systems, single line to
ground faults and the Order No. 693 directives to be reasonable.
However, the Commission has concerns about two issues and directs NERC
to modify Reliability Standard TPL-001-4 to address the concern that
the standard could exclude planned maintenance outages of significant
facilities from future planning assessments and directs NERC to change
the TPL-001-4, Requirement R1 VRF from medium to high.

I. Background

A. Regulatory History

4. In Order No. 693, the Commission accepted the Version 0 TPL
Reliability Standards.\5\ Further, pursuant to FPA section 215(d)(5),
the Commission directed NERC to develop modifications through the
Reliability Standards development process to address certain issues
identified by the Commission. In addition, the Commission neither
approved nor remanded Reliability Standards TPL-005-0 and TPL-006-0
because these two standards applied only to regional reliability
organizations, the predecessors to the statutorily recognized Regional
Entities. With regard to Reliability Standard TPL-002-0b, Table 1,
footnote `b,' which applies to planned non-consequential load loss, the
Commission directed NERC to clarify footnote `b' regarding the planned
non-consequential load loss for a single contingency event.\6\ In a
March 18, 2010 order, the Commission directed NERC to submit a
modification to footnote `b' responsive to the Commission's directive
in Order No. 693 by June 30, 2010.\7\ In a June 11, 2010 order, the
Commission extended the compliance deadline until March 31, 2011.\8\
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\5\ Order No. 693, FERC Stats. & Regs. ] 31,242 at PP 1840,
1845. The currently-effective versions of the TPL Reliability
Standards are as follows: TPL-001-0.1, TPL-002-0b, TPL-003-0a, and
TPL-004-0.
\6\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1792.
\7\ Mandatory Reliability Standards for the Bulk Power System,
130 FERC ] 61,200 (2010).
\8\ Mandatory Reliability Standards for the Bulk Power System,
131 FERC ] 61,231 (2010).
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Remand of Footnote b of the Version 1 TPL Reliability Standard (RM11-
18-000)
5. On March 31, 2011, NERC submitted proposed Reliability Standard
TPL-002-1 (Version 1). NERC proposed to modify Table 1, footnote `b' to
permit planned non-consequential load loss when documented and
subjected to an open stakeholder process.\9\ In Order No.

[[Page 63038]]

762, the Commission remanded to NERC the proposed modification to
footnote `b,' concluding that the proposed revisions did not meet the
Commission's Order No. 693 directives, nor did the revisions achieve an
equally effective and efficient alternative.\10\ The Commission stated
that the proposal did not adequately clarify or define the
circumstances in which an entity can use planned non-consequential load
loss as a mitigation plan to meet performance requirements for single
contingency events. The Commission also explained that the procedural
and substantive parameters of NERC's proposal were too undefined to
provide assurances that the process will be effective in determining
when it is appropriate to plan for non-consequential load loss, did not
contain NERC-defined criteria on circumstances to determine when an
exception for planned non-consequential load loss is permissible, and
could result in inconsistent results in implementation. Accordingly,
the Commission remanded the filing to NERC and directed NERC to develop
revisions to footnote `b' that would address the Commission's concerns.
Additionally, in Order No. 762, the Commission directed NERC to
``identify the specific instances of any planned interruptions of firm
demand under footnote `b' and how frequently the provision has been
used.'' \11\
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\9\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1794.
Non-consequential load loss includes the removal, by any means, of
any planned firm load that is not directly served by the elements
that are removed from service as a result of the contingency.
Currently-effective footnote `b' deals with both consequential load
loss and non-consequential load loss. NERC's proposed footnote `b'
characterized both types of load loss as ``firm demand.''
\10\ Order No. 762, 139 FERC ] 61,060.
\11\ Id. P 20.
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Proposed Remand of Version 2 of the TPL Reliability Standard (RM12-1-
000)
6. On October 19, 2011, NERC submitted a petition seeking approval
of a revised and consolidated TPL Reliability Standard that combined
the four currently-effective TPL Reliability Standards into a single
standard, TPL-001-2 (Version 2).\12\ The Version 2 standard included
language similar to NERC's Version 1 proposal with regard to utilizing
non-consequential load loss. The Version 2 standard included a non-
consequential load loss provision in Table 1--Steady State & Stability
Performance Footnotes (Planning Events and Extreme Events), footnotes 9
and 12.\13\
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\12\ NERC's October 2011 petition sought approval of Reliability
Standard TPL-001-2, the associated implementation plan and Violation
Risk Factors (VRFs) and Violation Severity Levels (VSLs), as well as
five new definitions to be added to the NERC Glossary of Terms. NERC
also requested approval to retire four currently-effective TPL
Reliability Standards: TPL-001-1, TPL-002-1b, TPL-003-1a; and TPL-
004-1. In addition, NERC requested to withdraw two pending
Reliability Standards: TPL-005-0 and TPL-006-0.1.
\13\ NERC's October 2011 Petition at 12. NERC's proposal in
Docket No. RM11-18-000, Table 1, footnote `b' referred to planned
load shed as planned ``interruption of Firm Demand.'' In footnote
12, proposed to replace footnote `b,' NERC changed the term from
``interruption of Firm Demand'' to utilization of ``Non-
Consequential Load Loss.''
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7. On the same day that the Commission issued Order No. 762, the
Commission issued a notice of proposed rulemaking (April 2012 NOPR)
stating that, notwithstanding that proposed Version 2 included specific
improvements over the currently-effective Transmission Planning
Reliability Standards, footnote 12 ``allow[s] for transmission planners
to plan for non-consequential load loss following a single contingency
without adequate safeguards [and] undermines the potential benefits the
proposed Reliability Standard may provide.'' \14\ Thus, the Commission
stated that its concerns regarding the stakeholder process set forth in
footnote 12 required a proposal to remand the entire Reliability
Standard. The Commission added that resolution of the footnote 12
concerns ``would allow the industry, NERC and the Commission to go
forward with the consideration of other improvements contained in
proposed Version 2.'' \15\ In addition, the April 2012 NOPR asked for
comment on various aspects of the consolidated Version 2 Reliability
Standard. Comments on the NOPR were due by July 20, 2012. The following
entities submitted comments: NERC, the Edison Electric Institute (EEI),
ISO/RTOs,\16\ ITC Companies,\17\ Midcontinent Independent System
Operator Inc. (MISO),\18\ American Transmission Company LLC (ATCLLC),
Powerex Corporation (Powerex), Bonneville Power Administration (BPA),
and Hydro One Networks and the Independent Electricity System Operator
(Hydro One and IESO).
---------------------------------------------------------------------------

\14\ April 2012 NOPR, 139 FERC ] 61,059 at P 55.
\15\ Id. P 3.
\16\ The ISO/RTOs consist of Electric Reliability Council of
Texas, Inc., ISO New England, Inc., Midcontinent Independent
Transmission System Operator Inc., New York Independent System
Operator, Inc., PJM Interconnection L.L.C., and Southwest Power
Pool, Inc.
\17\ ITC Companies consist of ITCTransmission, Michigan Electric
Transmission Company LLC, ITC Midwest LLC, and ITC Great Plains.
\18\ Effective April 26, 2013, MISO changed its name from
``Midwest Independent Transmission System Operator, Inc.'' to
``Midcontinent Independent System Operator, Inc.''
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Proposed Reliability Standard TPL-001-4--Version 4 (RM13-9-000)
8. On February 28, 2013, NERC submitted proposed Reliability
Standard TPL-001-4 (Version 4) in response to the Commission's remand
in Order No. 762 and concerns with regard to Table 1 footnote 12
identified in the April 2012 NOPR.\19\ Reliability Standard TPL-001-4
includes eight requirements and Table 1: \20\
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\19\ In its filing, NERC stated that the Version 4 standard,
i.e., TPL-001-4, modifies the pending Version 2 consolidated
standard, TPL-001-2. NERC also submitted, alternatively, a group of
four TPL standards (TPL-001-3, TPL-002-2b, TPL-003-2a, and TPL-004-
2, collectively, the Version 3 TPL standards) that would modify
``footnote b'' of the currently-effective TPL standards, ``[i]n the
event the Commission does not approve the Consolidated TPL Standards
[Version 4].'' NERC Petition at 4. Because we approve TPL-001-4,
references throughout this Final Rule are to the Version 4 standard.
\20\ The filed proposed Reliability Standard is not attached to
the Final Rule but is available on the Commission's eLibrary
document retrieval system in Docket Nos. RM12-1-000 and RM13-9-000
and are available on NERC's Web site, https://www.nerc.com.
---------------------------------------------------------------------------

Requirement R1: Requires the transmission planner and planning
coordinator to maintain system models and provides a specific list of
items required for the system models and that the models represent
projected system conditions. The planner is required to model the items
that are variable, such as load and generation dispatch, based
specifically on the expected system conditions.
Requirement R2: Requires each transmission planner and planning
coordinator to prepare an annual planning assessment of its portion of
the bulk electric system and must use current or qualified past
studies, document assumptions, and document summarized results of the
steady state analyses, short circuit analyses, and stability analyses.
Requirement R2, Part 2.1.3 requires the planner to assess system
performance utilizing a current annual study or qualified past study
for each known outage with a duration of at least six months for
certain events. It also clarifies that qualified past studies can be
utilized in the analysis while tightly defining the qualifications for
those studies. Requirement R2 includes a new part 2.7.3 that allows
transmission planners and planning coordinators to utilize non-
consequential load loss to meet performance requirements if the
applicable entities are unable to complete a corrective action plan due
to circumstances beyond their control.
Requirements R3 and R4: Requirement R3 describes the requirements
for steady state studies and Requirement R4 explains the requirements
for stability studies. Requirement R3 and Requirement R4 also require
that simulations duplicate what will occur in an actual power system
based on the expected performance of the protection systems.

[[Page 63039]]

Requirement R3 and Requirement R4 also include new parts that require
the planners to conduct an evaluation of possible actions designed to
reduce the likelihood or the consequences of extreme events that cause
cascading.
Requirement R5: Requirement R5 deals with voltage criteria and
voltage performance. NERC proposes in Requirement R5 that each
transmission planner and planning coordinator must have criteria for
acceptable system steady state voltage limits, post-contingency voltage
deviations, and the transient voltage response for its system. For
transient voltage response the criteria must specify a low-voltage
level and a maximum length of time that transient voltages may remain
below that level. This requirement will establish more robust
transmission planning for organizations and greater consistency as
these voltage criteria are shared.
Requirement R6: Specifies that an entity must define and document
the criteria or methodology used to identify system instability for
conditions such as cascading, voltage instability, or uncontrolled
islanding within its planning assessment.
Requirement R7: Mandates coordination of individual and joint
responsibilities for the planning coordinator and the transmission
planner which is intended to eliminate confusion regarding the
responsibilities of the applicable entities and assures that all
elements needed for regional and wide area studies are defined with a
specific entity responsible for each element and that no gaps will
exist in planning for the Bulk-Power System.
Requirement R8: Addresses the sharing of planning assessments with
neighboring systems. The requirement ensures that information is shared
with and input received from adjacent entities and other entities with
a reliability related need that may be affected by an entity's system
planning.
Table 1: Similar to the currently-effective TPL Reliability
Standard, the revised standard contains a series of planning events and
describes system performance requirements in Table 1 for a range of
potential system contingencies required to be evaluated by the planner.
Table 1 includes three parts: Steady State & Stability Performance
Planning Events, Steady State & Stability Performance Extreme Events,
and Steady State & Stability Performance Footnotes. Table 1 categorizes
the events as either ``planning events'' or ``extreme events.'' The
proposed table lists seven contingency planning events that require
steady-state and stability analysis as well as five extreme event
contingencies.
9. NERC modified footnote 12 of Table 1 to provide specific
parameters for the permissible use of planned non-consequential load
loss to address bulk electric system performance issues, including: (1)
Firm limitations on the maximum amount of load that an entity may plan
to shed, (2) safeguards to ensure against inconsistent results and
arbitrary determinations that allow for the planned non-consequential
load loss, and (3) a more specifically defined, open and transparent,
verifiable, and enforceable stakeholder process. Footnote 12 as
modified provides:

An objective of the planning process is to minimize the
likelihood and magnitude of Non-Consequential Load Loss following
planning events. In limited circumstances, Non-Consequential Load
Loss may be needed throughout the planning horizon to ensure that
BES performance requirements are met. However, when Non-
Consequential Load Loss is utilized under footnote 12 within the
Near-Term Transmission Planning Horizon to address BES performance
requirements, such interruption is limited to circumstances where
the Non-Consequential Load Loss meets the conditions shown in
Attachment 1. In no case can the planned Non-Consequential Load Loss
under footnote 12 exceed 75 MW for US registered entities. The
amount of planned Non-Consequential Load Loss for a non-US
Registered Entity should be implemented in a manner that is
consistent with, or under the direction of, the applicable
governmental authority or its agency in the non-US jurisdiction.

10. Attachment 1 to TPL-001-4, referenced in footnote 12 has three
sections: (I) Stakeholder process, (II) information an entity must
provide to stakeholders, and (III) instances for which regulatory
review of planned non-consequential load loss under footnote 12 is
required. Section I describes five criteria that apply to the open and
transparent stakeholder process that an entity must implement when it
seeks to use footnote 12. Section I provides that an entity does not
have to repeat the stakeholder process for a specific application of
footnote 12 with respect to subsequent planning assessments unless
conditions have materially changed for that specific application.
11. Section II of Attachment 1 specifies eight categories of
information that entities must provide to stakeholders, including
estimated amount, frequency and duration of planned non-consequential
load loss under footnote 12. An entity must also provide information on
alternatives considered and future plans to alleviate the need for
planned non-consequential load loss.
12. Section III of Attachment 1 describes the process for planned
non-consequential load loss greater than 25 MW. Specifically, planned
non-consequential load loss between 25 MW and 75 MW, or any planned
non-consequential load loss at the 300 kV level or above would receive
greater scrutiny by regulatory authorities and the ERO. Where these
parameters apply, ``the Transmission Planner or Planning Coordinator
must ensure that applicable regulatory authorities or governing bodies
responsible for retail electric service issues do not object to the use
of Non-Consequential Load Loss under footnote 12.'' \21\ Further,
``[o]nce assurance has been received that the applicable regulatory
authorities . . . responsible for retail electric service issues do not
object . . . the Planning Coordinator or Transmission Planner must
submit the information [in Section II of Attachment 1] to the ERO for a
determination of whether there are any Adverse Reliability Impacts''
caused by the responsible entity's request to use footnote 12.\22\
According to NERC, this provision provides safeguards against arbitrary
or inconsistent determinations, and also ``preserves, to the extent
practicable, the role of Retail Regulators,'' while allowing ERO review
for possible adverse reliability impacts.\23\
---------------------------------------------------------------------------

\21\ NERC Petition, Exhibit A, proposed Reliability Standard
TPL-001-4, Attachment I, section 3.
\22\ NERC Petition, Exhibit A, proposed Reliability Standard
TPL-001-4, Attachment I, section 3. NERC defines ``Adverse
Reliability Impact'' as ``[t]he impact of an event that results in
frequency-related instability; unplanned tripping of load or
generation; or uncontrolled separation or cascading outages that
affects a widespread area of the Interconnection.'' NERC Glossary at
4.
\23\ NERC February 2013 Petition at 19.
---------------------------------------------------------------------------

13. NERC stated that the combination of numerical limitations and
other considerations, such as costs and alternatives, guards against a
determination based solely on a quantitative threshold becoming an
acceptable de facto interpretation of planned non-consequential load
loss. According to NERC, the procedures in footnote 12 would enable
acceptable, but limited, circumstances of planned non-consequential
load loss after a thorough stakeholder review and approval and ERO
review.
14. NERC also stated that, because footnote 12 differs from
footnote `b' included in the currently-effective TPL Reliability
Standards, data do not yet exist on the frequency of instances of
planned non-consequential load loss under the new footnote 12.
Consequently, NERC stated that it will monitor the use of footnote 12
and will report the results of this monitoring

[[Page 63040]]

after the first two years of the footnote's implementation.\24\
---------------------------------------------------------------------------

\24\ NERC's February 2013 Petition at 11.
---------------------------------------------------------------------------

15. NERC requested that requirements R1 and R7 of the Version 4
Reliability Standard as well as the definitions become effective on the
first day of the first calendar quarter twelve months after applicable
regulatory approval. In addition, except as indicated below, NERC
requested that Requirements R2 through R6 and Requirement R8 including
Table 1--Steady State & Stability Performance Planning Events, Table
1--Steady State & Stability Performance Extreme Events, Table 1--Steady
State & Stability Performance Footnotes (Planning Events & Extreme
Events) and Attachment 1 become effective and subject to compliance on
the first day of the first calendar quarter, 24 months after applicable
regulatory approval.
16. NERC also proposed that, for 84 calendar months beginning the
first day of the first calendar quarter following applicable regulatory
approval, concurrent with the 24 month effective date of Requirement
R2, corrective action plans applying to specific categories of
contingencies and events identified in TPL-001-4, Table 1 are allowed
to include non-consequential load loss and curtailment of firm
transmission service (in accordance with Requirement R2, Part 2.7.3)
that would not otherwise be permitted by the requirements of the
Version 4 Reliability Standard. Further, NERC stated that Requirement
R2, Part 2.7.3 addresses situations that are beyond the control of the
planner that prevent the implementation of a corrective action plan in
the required timeframe. Some examples of situations beyond the control
of the planner could include a state road widening project taking
substation land that was targeted for expansion or a ruling preventing
the entity from condemning the land necessary for a project.
17. NERC also requested approval to retire the currently-effective
TPL Reliability Standards and to withdraw two pending TPL Reliability
Standards, TPL-005-0 and TPL-006-0.1, because it transferred the
requirements of the pending Reliability Standards to sections 803 and
804 of NERC's Rules of Procedure. NERC proposed to retire TPL
Reliability Standards TPL-001-0.1, TPL-002-0b, TPL-003-0a, and TPL-004-
0 on midnight of the day immediately prior to the effective date of
TPL-001-4. However, during the 24-month implementation period, all
aspects of the currently-effective TPL Reliability Standards, TPL-001-
0.1 through TPL-004-0 will remain in effect for compliance monitoring.
NERC stated that the 24 month period is to allow entities to develop,
perform and/or validate new or modified studies necessary to implement
and meet Reliability Standard TPL-001-4. NERC explained that the
specified effective dates allow sufficient time for proper assessment
of the available options necessary to create a viable corrective action
plan that is compliant with the new TPL Reliability Standard.
Supplemental NOPR
18. On May 16, 2013, the Commission issued a Supplemental NOPR
which proposed to approve the Version 4 TPL Reliability Standard, TPL-
001-4, as just, reasonable, not unduly discriminatory or preferential,
and in the public interest.\25\ In the Supplemental NOPR, the
Commission suggested that, while NERC's proposal differs from the
Commission directives on the matter of utilizing non-consequential load
loss, NERC's proposal adequately addresses the underlying reliability
concerns raised in Order No. 693, Order No. 762 and the April 2012 NOPR
and, thus, is an equally effective and efficient alternative to address
the Commission's directives.\26\ In the Supplemental NOPR, the
Commission proposed to find that proposed footnote 12 would improve
reliability by providing a blend of specific quantitative and
qualitative parameters for the permissible use of planned non-
consequential load loss to address bulk electric system performance
issues. In addition, the Commission stated that the stakeholder process
appears to be adequately defined and includes specific criteria and
guidelines that a responsible entity must follow before it may use
planned non-consequential load loss to meet Reliability Standard TPL-
001-4 performance requirements for a single contingency event. Further,
the Supplemental NOPR indicated that NERC's proposal provides
reasonable safeguards, including a review process by NERC, to protect
against adverse reliability impacts that could otherwise result from
planned non-consequential load loss.\27\
---------------------------------------------------------------------------

\25\ Transmission Planning Reliability Standards, Notice of
Proposed Rulemaking, 143 FERC ] 61,136 (2013) (Supplemental NOPR).
\26\ Supplemental NOPR, 143 FERC ] 61,136 at P 18.
\27\ Id. P 19.
---------------------------------------------------------------------------

19. In the Supplemental NOPR, the Commission proposed to direct
that NERC submit a report on the use of footnote 12, due at the end of
the first calendar quarter after the first two years of implementation
of footnote 12 to provide an analysis of the use of footnote 12,
including but not limited to information on the duration, frequency and
magnitude of planned non-consequential load loss, and typical (and if
significant, atypical) scenarios where entities plan for non-
consequential load loss. The Commission proposed that the report should
also address the effectiveness of the stakeholder process and the use
and effectiveness of the local regulatory review and NERC review.\28\
---------------------------------------------------------------------------

\28\ Id. P 20.
---------------------------------------------------------------------------

20. Comments on the Supplemental NOPR were due on June 24, 2013.
NERC, MISO and ITC Companies filed comments in response to the
Supplemental NOPR.

II. Discussion

21. Pursuant to FPA section 215(d), we find that Reliability
Standard TPL-001-4 is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. While NERC's proposal differs
from the Commission directives, we find that NERC adequately addressed
the directives and underlying reliability concerns of Order No. 693,
Order No. 762 and the April 2012 NOPR and, thus, is an equally
effective and efficient alternative to address the Commission's
concerns.\29\ We find that the revised TPL Reliability Standard
improves uniformity and transparency in the transmission planning
process and clarifies the instances where planners may utilize planned
load loss in establishing transmission planning performance
requirements for reliable bulk electric system operations across normal
and contingency conditions. We also find that Reliability Standard TPL-
001-4 will serve as a foundation for annual planning assessments
conducted by planning coordinators and transmission planners to plan
the bulk electric system reliably in response to a range of potential
contingencies. Further, we find that the Reliability Standard presents
clear, measurable, and enforceable requirements that each planning
coordinator and transmission planner must follow when planning its
system.
---------------------------------------------------------------------------

\29\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1792.
---------------------------------------------------------------------------

22. In the Supplemental NOPR, the Commission stated it would issue
a final rule that addresses the consolidated transmission planning
Reliability Standard, TPL-001-4. Therefore, this Final Rule addresses
the modified footnote 12 and comments received in response to the
Supplemental NOPR as

[[Page 63041]]

well as other aspects of the consolidated TPL Reliability Standard
raised in the April 2012 NOPR.

A. Footnote 12 and Planned Use of Non-Consequential Load Loss NOPR
Proposal

23. In the Supplemental NOPR, the Commission proposed to approve
footnote 12. The Commission indicated that the proposal differs from
the Commission directives but adequately addresses the underlying
reliability concerns raised in Order No. 693, Order No. 762 and the
April 2012 NOPR and, thus, is an equally effective and efficient
alternative to address the Commission's directives.\30\ The
Supplemental NOPR indicated that proposed footnote 12 would improve
reliability by providing a blend of specific quantitative and
qualitative parameters for the permissible use of planned non-
consequential load loss to address bulk electric system performance
issues. In addition, the Supplemental NOPR stated that the stakeholder
process appeared to be adequately defined and includes specific
criteria and guidelines that a responsible entity must follow before it
may use planned non-consequential load loss to meet Reliability
Standard TPL-001-4 performance requirements for a single contingency
event. Further, the Supplemental NOPR stated that NERC's proposal
provides reasonable safeguards, including a review process by NERC, to
protect against adverse reliability impacts that could otherwise result
from planned non-consequential load loss.
---------------------------------------------------------------------------

\30\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1792;
Mandatory Reliability Standards for the Bulk Power System, 131 FERC
] 61,231 at P 21.
---------------------------------------------------------------------------

Comments
24. NERC supports the Commission's proposal in the Supplemental
NOPR. NERC also commits to monitor the use of footnote 12 and issue a
report containing the findings of the monitoring by the end of the
first calendar quarter following the first two years of implementation.
ITC Companies believe NERC's proposal is a significant improvement over
the currently-effective standard and support approval. ITC Companies
urge the Commission to clarify that the use of planned non-
consequential load loss should be used rarely and should not be
considered a de facto planning solution.
25. MISO supports Reliability Standard TPL-001-4 as an improvement
over the current standard but has two concerns regarding Attachment 1,
referenced in footnote 12. First, MISO argues that the Commission
should direct NERC to eliminate or clarify the requirement that
requires interaction with and approval by applicable regulatory
authorities or government bodies responsible for retail electric
service. MISO claims that such a requirement adds an additional layer
of complexity and administrative burden to compliance of proposed
Reliability Standard TPL-001-4 without any attendant benefit. According
to MISO, the reference in Attachment 1 to ``applicable regulatory
authorities or governing bodies'' is not clear. MISO states that, while
these terms could encompass a state's public service commission or
public utility commission, the terms could also potentially include
other state bodies or agencies such as consumer advocacy and protection
bodies, state legislatures, and city or municipal bodies. According to
MISO, if these other entities would be considered ``governing bodies
responsible for retail electric issues,'' a transmission planner would
need to seek and receive assurances from each of these bodies. MISO
also suggests that, prior to finalization of its transmission expansion
plan each year, a planner could obtain the assent of the applicable
public utility commission, and yet have its transmission plans
subsequently upended because it did not obtain additional assent from a
different state agency that has some involvement in retail electric
matters.
26. MISO also questions what it means to ensure that an applicable
regulatory authority or governing body ``does not object'' to the
inclusion of non-consequential load loss in the planning process. MISO
suggests that it could mean input of agency staff or a more formal
decision that is voted on by the agency's commissioners. MISO argues
that use of an open stakeholder process that allows for robust input by
any interested parties will ensure that all interested state agencies
will have a say in the process, and that any objections of such
agencies to the inclusion of non-consequential load loss will be
incorporated into the relevant planning decisions.
27. Alternatively, MISO requests that the Commission clarify or
direct NERC to clarify the ``does not object'' language to mean that:
(1) The phrase ``applicable regulatory authorities or governing
bodies'' means only the public utility commission or public service
commission in the affected states, and does not refer to any other
state entity; and (2) comments or other input submitted by the affected
state public service commission or public utility commission in the
Attachment 1 stakeholder process indicating that the agency ``does not
object'' to the inclusion of non-consequential load loss in the
planning process are sufficient to satisfy the ``does not object''
requirement.
28. Further, MISO requests that the Commission clarify, or direct
NERC to clarify, the language in section II of Attachment 1 that
requires planning coordinators and transmission planners to provide
stakeholders all assessments of ``potential overlapping uses of
footnote 12 including overlaps with adjacent Transmission Planners and
Planning Coordinators.'' MISO believes that this phrase suggests that
there are other ``potential overlapping uses'' that are encompassed by
the requirement. MISO states it is not clear what these other
overlapping uses might be or how they might be incorporated into the
planning process.
Commission Determination
29. We approve Reliability Standard, TPL-001-4 with footnote 12
because it satisfies the concerns raised in the Supplemental NOPR.
Footnote 12 provides a blend of specific quantitative and qualitative
parameters for the permissible use of planned non-consequential load
loss to address bulk electric system performance issues, including firm
limitations on the maximum amount of load that an entity may plan to
shed, safeguards to ensure against inconsistent results and arbitrary
determinations that allow for the planned non-consequential load loss,
and a more specifically defined, open and transparent, verifiable, and
enforceable stakeholder process. Use of planned non-consequential load
loss should be rare and must be used consistent with the process
established here.
30. We disagree with MISO that Attachment 1 to footnote 12 adds an
additional layer of complexity and administrative burden to compliance
without any attendant benefit. Commenters have stated in prior
proceedings that a blend of quantitative and qualitative parameters
``should not overly burden NERC or Regional Entity resources as
utilization of the planned load shed exception is--and would be--rarely
utilized.'' \31\ Further, the Commission directs NERC to report on the
use of footnote 12 including the use and effectiveness of the local
regulatory review and NERC review. This report is important because it
will provide an analysis of the use of footnote 12, including but not
limited to information on the duration, frequency and

[[Page 63042]]

magnitude of planned non-consequential load loss, and typical (and if
significant, atypical) scenarios where entities plan for non-
consequential load loss. Further, the report will serve as a tool to
evaluate the usefulness and effectiveness of local regulatory and ERO
review, and identify whether MISO's concern or other issues arise that
need to be addressed.
---------------------------------------------------------------------------

\31\ Order No. 762, 139 FERC ] 61,060 at P 55.
---------------------------------------------------------------------------

31. We decline to direct NERC to limit the meaning of the phrase
``applicable regulatory authorities or governing bodies.'' Because each
state and locality has different entities that are responsible for
reliability of retail electric service, we are reluctant to further
define who may participate. NERC's report should identify any issues
with respect to how effective and efficient the review process is
working. With regard to MISO's request that input by the affected
regulatory body is sufficient to satisfy the language in the Attachment
1 stakeholder process indicating that the agency ``does not object'' to
the inclusion of non-consequential load loss, we note that during the
standard development process NERC ``modified the footnote to require
regulatory authority review rather than approval.'' \32\ Use of an open
stakeholder process that allows for robust input and review will ensure
that all interested state agencies will have a say in the process, and
that any objections of such agencies to the inclusion of non-
consequential load loss will be considered in the relevant planning
decisions. With regard to MISO's requested clarification of the phrase
``potential overlapping uses,'' we note that Attachment 1 section II
encompasses potential overlapping uses of footnote 12 either within the
responsible entity or with adjacent transmission planners and planning
coordinators.\33\ Accordingly, no further clarification is required.
---------------------------------------------------------------------------

\32\ NERC's Petition, Exhibit H, Consideration of Comments,
period from July 31, 2012 through August 29, 2012 at 73.
\33\ Proposed TPL-001-4 Reliability Standard, Attachment 1,
section II, category 8: ``Assessment of potential overlapping uses
of footnote 12 including overlaps with adjacent Transmission
Planners and Planning Coordinators.''
---------------------------------------------------------------------------

B. Reliability Issues Raised in the April 2012 NOPR

32. In the April 2012 NOPR, the Commission sought comments
regarding the following issues regarding the proposed Version 2
Reliability Standard: (1) Planned maintenance outages, (2) violation
risk factors, (3) protection system failures versus relay failures, (4)
assessment of backup or redundant protection systems, (5) single line
to ground faults and (6) Order No. 693 directives. The Version 4 TPL
standard that we approve in this Final Rule contains the same
provisions as the Version 2 standard, with the exception of footnote
12, Attachment 1 and the VRF for Requirement R6. Accordingly, we
address below the issues raised in the April 2012 NOPR.
1. Planned Maintenance Outages NERC Petition
33. NERC proposed new language in TPL-001-2, Requirement R1 to
remove an ambiguity in the current standard concerning what the planner
needs to include in the specific studies. Requirement R1 also requires
the planner to evaluate six-month or longer duration planned outages
within its system. NERC states that, while Requirement R1.3.12 of the
currently-effective TPL-002-0b includes planned outages (including
maintenance outages) in the planning studies and requires simulations
at the demands levels for which the planned outages are performed, it
is not appropriate to have the planner select specific planned outages
for inclusion in their studies.\34\ Consequently, NERC proposes a
bright-line test to determine whether a planned outage should be
included in the system models.
---------------------------------------------------------------------------

\34\ NERC's October 2011 Petition at 35.
---------------------------------------------------------------------------

NOPR
34. In the April 2012 NOPR, the Commission expressed concern that,
under proposed Requirement R1, planned maintenance outages with a
duration of less than six months would be excluded from future planning
assessments. As a result, any potential impact to bulk electric system
reliability from these outages would be unknown.\35\ The Commission
sought comment on whether the proposed six month threshold would
materially change the number of planned outages included in planning
assessments compared to the number included in planning assessments
under the currently-effective standard, and whether the threshold would
exclude nuclear plant refueling, large fossil and hydro generating
station maintenance, and spring and fall transmission construction
projects from future planning assessments. The Commission also sought
comment on possible alternatives.
---------------------------------------------------------------------------

\35\ April 2012 NOPR, 139 FERC ] 61,059 at P 18.
---------------------------------------------------------------------------

35. In the NOPR, the Commission noted that, with respect to
protection system maintenance, currently-effective Reliability Standard
TPL-002-0, Requirement R1.3.12 requires the planner to ``[i]nclude the
planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand
levels for which planned (including maintenance) outages are
performed.'' \36\ NERC explained in the petition that this language did
not carry over because protection system maintenance or other outages
are not anticipated to last six months. The Commission indicated in the
NOPR that it is critical to plan the system so that a protection system
can be removed for maintenance and still be operated reliably and
sought comment on whether protection systems are necessary to be
included as a type of planned outage.
---------------------------------------------------------------------------

\36\ Reliability Standard TPL-002-0, Requirement R1.3.12.
---------------------------------------------------------------------------

Comments
36. NERC and EEI state that the proposed Reliability Standard will
not materially change the number of planned outages that must be
reflected in initial system conditions as compared to the existing
standards. NERC states that applying existing Requirement R1.3.12,
planners have traditionally only included those planned outages in
their category ``P0 or N-0'' system condition that resulted from
catastrophic equipment failures or extended outage conditions
associated with construction or maintenance projects that place their
system in an abnormal starting condition.\37\ NERC believes that going
beyond those scenarios would consider ``hypothetical planned outages,''
and doing so in a planning study horizon would introduce multiple
contingency conditions within the existing standard. Further, NERC
states that planners will establish sensitivity cases around key
generation unit outages, and when applying the category P3 planning
event to those sensitivity cases, it will further cover multiple
generator unit outages. Similarly, transmission maintenance outages are
covered in the planning events when applying the category P6 planning
events.
---------------------------------------------------------------------------

\37\ Table 1 of the TPL Reliability Standard contains a series
of planning events and describes system performance requirements and
lists seven categories of contingency planning events, identified as
P0 through P6. P0 is the ``No Contingency,'' normal system
condition. Reliability Standard TPL-001-4, Table 1.
---------------------------------------------------------------------------

37. BPA believes the six-month planned outage window is workable
but that it may be too short to consider in system planning models and
suggests a one-year planned outage window. BPA states that planned
outages with duration of less than one year should be

[[Page 63043]]

dealt with operationally by determining new operating limits and taking
other actions to mitigate the planned outage. According to Hydro One,
it is not necessary to include planned outage of less than six months
since long-term planning is intended to assess transmission expansion
needs in the usual three to ten year timeframe. Hydro One states that
the inclusion of planned outages of less than six months will not
increase the accuracy of the results as these are moving targets and
there are operational planning measures to provide the required
transmission transfer capability to meet forecast demand.
38. On the other hand, ITC Companies, MISO and ATCLLC express
concern that some planned outages of less than six months are relevant
and should not be eliminated from consideration in planning
evaluations. ATCLLC states that, although the number of planned outages
may not materially change, the impact of eliminating pertinent planned
outages of less than six months in duration is perhaps more material
than the impact of outages six months in duration or longer. Some
planned outages of less than six months in duration may also result in
relevant impacts during one or both of the seasonal off-peak periods.
ITC Companies state that, in some instances, certain transmission
elements may be so critical that when taken out of service for system
maintenance or to facilitate a new capital project, a subsequent single
unplanned transmission outage could result in the loss of firm system
load. ITC Companies adds that including only known maintenance outages
of six months or longer in the transmission models could be a step
backwards from the current standard. Since these unplanned outages can
have consequential impacts on transmission customers, prudent
transmission planning should include providing an adequate transmission
system to avoid these undesired outcomes.
39. MISO suggests that limiting planning studies to only include
known outages of generation or transmission with duration of at least
six months may have a detrimental impact to bulk electric system
reliability. According to MISO, proper transmission system planning
should ensure that the removal of a facility for maintenance purposes
can be accomplished without the need to deny or re-schedule such
maintenance to prevent the loss of firm load resulting from the types
of contingencies enumerated in the TPL Reliability Standards. MISO
requests that the Commission direct NERC to further expand the base
planning conditions and assumptions by requiring inclusion of
unscheduled, planned outages of any element when applying at a minimum
P0 and P1 events to the off-peak cases.
Commission Determination
40. Pursuant to section 215(d)(5) of the FPA, we direct NERC to
modify Reliability Standard TPL-001-4 to address the concern that the
six month threshold could exclude planned maintenance outages of
significant facilities from future planning assessments.
41. For the reasons discussed below, the Commission finds that
planned maintenance outages of less than six months in duration may
result in relevant impacts during one or both of the seasonal off-peak
periods. Prudent transmission planning should consider maintenance
outages at those load levels when planned outages are performed to
allow for a single element to be taken out of service for maintenance
without compromising the ability of the system to meet demand without
loss of load.\38\ We agree with commenters such as MISO and ATCLLC that
certain elements may be so critical that, when taken out of service for
system maintenance or to facilitate a new capital project, a subsequent
unplanned outage initiated by a single-event could result in the loss
of non-consequential load or may have a detrimental impact to the bulk
electric system reliability. A properly planned transmission system
should ensure the known, planned removal of facilities (i.e.,
generation, transmission or protection system facilities) for
maintenance purposes without the loss of non-consequential load or
detrimental impacts to system reliability such as cascading, voltage
instability or uncontrolled islanding.
---------------------------------------------------------------------------

\38\ ITC Companies Comments at 5.
---------------------------------------------------------------------------

42. We remain concerned that proposed Reliability Standard TPL-001-
4 will materially change the number of planned outages that must be
reflected in initial system conditions as compared to the existing
standards. Planned outages lasting less than six months are common, and
yet could be overlooked for planning purposes under the proposal. These
planned outages are not ``hypothetical planned outages,'' and should
not be treated as multiple contingency conditions within the planning
standard. The Commission's directive is to include known generator and
transmission planned maintenance outages in planning assessments, not
hypothetical planned outages.
43. While NERC has flexibility on how to address the identified
concern, we believe that acceptable approaches include eliminating the
six-month threshold altogether; decreasing the threshold to fewer
months to include additional significant planned outages; or including
parameters on what constitutes a significant planned outage based, for
example, on MW or facility ratings.
44. Further, we disagree with NERC's position that category P3
contingencies cover generator maintenance outages and category P6
covers transmission maintenance outages. P3 and P6 both consist of
multiple contingencies, e.g., loss of a generating unit or transmission
circuit followed by system adjustments and then the loss of another
generator or transmission circuit. In approving NERC's interpretation
of Requirement R1.3.12 of TPL-002-0 and TPL-003-0, the Commission
stated that ``planned (including maintenance) outages are not
contingencies and are required to be addressed in transmission planning
for any bulk electric equipment at demand levels for which the planned
outages are performed.'' \39\ The Commission further stated that it
``understands that planned maintenance outages tend to be for a
relatively short duration and are routinely planned at a time that
provides favorable system conditions, i.e., off-peak conditions. Given
that all transmission and generation facilities require maintenance at
some point during their service lives, these `potential' planned
outages must be addressed, so long as their planned start times and
durations may be anticipated as occurring for some period of time
during the planning time [horizon]'' required in the TPL Reliability
Standards.\40\
---------------------------------------------------------------------------

\39\ North American Electric Reliability Corp., 131 FERC ]
61,068, at P 39 (2010) (approving interpretation of Reliability
Standards TPL-002-0 and TPL-003-0).
\40\ Id. P 39.
---------------------------------------------------------------------------

45. With regard to BPA's comment, we disagree that planned outages
of less than one year in duration should be addressed operationally by
determining new operating limits and taking other actions to mitigate
the planned outage. The Commission understands that some planned
outages such as planned generation outages are known more than one year
in advance.\41\ As a result, the Commission believes the planning time
horizon of the TPL Reliability Standards offers more flexibility to
assess planned maintenance outages than the

[[Page 63044]]

operational time horizon. Further, we disagree with Hydro One's comment
that including planned outages of less than six months is unnecessary
since long-term planning to assess transmission expansion occurs in the
three to ten year timeframe. The Commission recognizes that the TPL-
001-4 Reliability Standard addresses near-term and long-term
transmission planning horizons and, for the near-term horizon, requires
annual assessments for years one through five. Accordingly, known
planned facility outages (i.e. generation, transmission or protection
system facilities) of less than six months should be addressed so long
as their planned start times and durations may be anticipated as
occurring for some period of time during the planning time horizon.
---------------------------------------------------------------------------

\41\ See, e.g., Commissioner-Led Reliability Technical
Conference, Docket Nos. AD13-6-000, RC11-6-004, RR13-2-000, July 9,
2013, Volume I at 242.
---------------------------------------------------------------------------

2. Violation Risk Factors
a. Requirement R1
NERC Petition
46. NERC assigned a ``medium'' violation risk factor (VRF) for
proposed Requirement R1. NERC maintains that Requirements R1.3.5,
R1.3.7, R1.3.8, and R1.3.9 of the currently-effective Reliability
Standard carry a VRF of ``medium'' and are similar in purpose and
effect to proposed Reliability Standard, Requirement R1 because they
refer to planning models that include firm transfers, existing and
planned facilities, and reactive power requirements.\42\
---------------------------------------------------------------------------

\42\ NERC October 2011 Petition at Exhibit C, Table 1.
---------------------------------------------------------------------------

NOPR Proposal
47. In the April 2012 NOPR, the Commission expressed that, if
system models are not properly modeled or maintained, the analysis
required in the Reliability Standard that uses the models in
Requirement R1 may lose their validity and could directly cause or
contribute to Bulk-Power System instability, separation, or a cascading
sequence of failures, or could place the Bulk-Power System at an
unacceptable risk of instability, separation, or cascading, or hinder
restoration to a normal condition.\43\ The Commission noted that
Requirement R1 of the Version 0 TPL Standard, which is assigned a
``high'' VRF, explicitly establishes Category A as the normal system in
Table 1, which also creates the model of the normal system prior to any
contingency and stated its belief that Requirement R1 of the proposed
Reliability Standard and Requirement 1 of currently-effective standard
both establish the normal system planning model that serves as the
foundation for all other conditions and contingencies that are required
to be studied and evaluated in a planning assessment. In the NOPR, the
Commission sought comment on why Requirement R1 of proposed Reliability
Standard carries a VRF of ``medium'' while Requirement R1 of the
currently-effective standard carries a VRF of ``high.''
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\43\ April 2012 NOPR, 139 FERC ] 61,059 at P 21.
---------------------------------------------------------------------------

Comments
48. NERC states that Requirement R1 of the currently-effective
standard directly relates to Requirement R2 of the proposed standard,
which has a High VRF. NERC states that Requirement R1 of the proposed
standard is a new requirement that addresses the models needed for
planning assessments and therefore can have a different VRF. NERC
states that while the accuracy of the transmission system model plays a
key role in the TPL Reliability Standards, it is ``a model, an
approximation constructed and built with multiple entity inputs within
a controlled process (e.g., Multiregional Model Working Group).'' \44\
NERC states the base model in proposed Requirement R1 must be modified
by adjusting load forecasts and generation dispatch to better assess
the range of probable outcomes that the transmission system may
experience for various contingency scenarios.
---------------------------------------------------------------------------

\44\ NERC Comments at 8.
---------------------------------------------------------------------------

49. ISO/RTOs state that proposed Requirement R1 relates to model
maintenance, a necessary condition to being able to perform an
assessment, which is a different matter from the current Requirement
R1. According to ISO/RTOs Requirement R1 of the currently-effective
standard, relating to performing an assessment, corresponds to
Requirement R2 of the proposed standard, both of which carry a VRF of
``high.''
50. EEI does not believe that proposed Requirement R1 aligns with
Requirement R1 of the currently-effective standard. According to EEI,
however, Requirement R1 does obligate ``Transmission Planners and
Planning Coordinators to maintain system models within their respective
area for performing studies needed to complete its Planning
Assessments.'' \45\ EEI further notes that these studies establish a
baseline (Category P0) by which all other studies are based. EEI
advocates that, if this requirement is not adhered to, faulty studies
could result, possibly leading to misoperation of the system. For this
reason, EEI believes the VRF was improperly categorized as a medium
risk VRF and suggests consideration be given to increasing the VRF to
``high.''
---------------------------------------------------------------------------

\45\ EEI Comments at 5.
---------------------------------------------------------------------------

Commission Determination
51. We direct NERC to modify Reliability Standard TPL-001-4,
Requirement R1 and change its VRF from medium to high. As discussed in
the April 2012 NOPR, Requirement R1 establishes the normal system
planning model that serves as the foundation for all other conditions
and contingencies that are required to be studied and evaluated in a
planning assessment. The Commission agrees with EEI that if the
baseline studies established in Requirement R1 are not adhered to,
faulty studies could result, possibly leading to misoperation of the
system.
52. The Commission is not persuaded by NERC's argument that
Reliability Standard TPL-001-4, Requirement R1 warrants a medium VRF
because the base model in Requirement R1 must be modified by adjusting
load forecasts and generation dispatch for various contingency
scenarios. Rather, the Commission finds that Requirement R1 and its
sub-parts require system models to represent projected system
conditions including items such as resources required for load, and
real and reactive load forecasts, all of which ``establishes Category
P0 as the normal condition in Table 1.'' \46\ Although the Commission
agrees with NERC that the accuracy of the system model plays a key role
in the TPL Reliability Standards and that a system model is ``a model,
an approximation constructed and built with multiple entity inputs
within a controlled process,'' the Commission finds that the system
model of Requirement R1 establishes a baseline (Category P0) for which
all other studies are based and if not adhered to, faulty studies could
result, possibly leading to misoperation of the system.
---------------------------------------------------------------------------

\46\ NERC's February 2013 Petition, Exhibit A, TPL-001-4,
Requirement R1.
---------------------------------------------------------------------------

53. Further, the Commission disagrees with ISO/RTOs that proposed
Requirement R1 is a different matter from the current Requirement R1.
The Commission stated in the April 2012 NOPR that Requirement R1 of the
Version 0 TPL Standard, which is assigned a ``high'' VRF, explicitly
establishes Category A as the normal system in Table 1 that serves as
the foundation for all other conditions and contingencies that are
required to be studied and evaluated in a planning assessment.
Accordingly, the Commission believes that TPL-001-4, Requirement R1
similarly establishes

[[Page 63045]]

Category P0 as the normal system in Table 1 that serves as the
foundation for all other conditions and contingencies that are required
to be studied and evaluated in a planning assessment. For these
reasons, the Commission directs NERC to modify the VRF assigned to
Requirement R1 from medium to high.
b. VRF for Requirement R6
NERC Petition
54. NERC proposed to assign a ``low'' VRF for Requirement R6 \47\
because ``failure to have established criteria for determining System
instability is an administrative requirement affecting a planning time
frame.'' \48\ NERC explains that Requirement R6 is a new requirement
and that violations would not be expected to adversely affect the
electrical state or capability of the bulk electric system.
---------------------------------------------------------------------------

\47\ NERC's February 2013 Petition, Exhibit A, TPL-001-4,
Requirement R6 states ``[e]ach Transmission Planner and Planning
Coordinator shall define and document, within their Planning
Assessment, the criteria or methodology used in the analysis to
identify System instability for conditions such as Cascading,
voltage instability, or uncontrolled islanding.''
\48\ NERC's October 2011 Petition, Exhibit C, at 110.
---------------------------------------------------------------------------

NOPR Proposal
55. In the NOPR, the Commission recognized that documenting
criteria or methodology is an administrative act but stated that
defining the criteria or methodology to be used is not an
administrative act. The Commission sought clarification why the VRF
level assigned to Requirement R6 is ``low'' since it appears that
Requirement R6 requires more than a purely administrative task.
Comments
56. NERC agrees that proposed TPL-001-2 Requirement R6 is not
strictly an administrative task, and therefore the VRF should be
adjusted to medium. In its February 28, 2013 Petition, NERC revised the
VRF for Reliability Standard TPL-001-4, Requirement R6 from low to
medium.
57. EEI and ISO/RTOs contend that Requirement R6 was correctly
assigned a ``low'' VRF because ``defining and documenting'' is an
administrative task. According to EEI, the fact that the planner poorly
documented the criteria and methodology does not mean that their
assessment was not conducted appropriately or that it placed the bulk
electric system at risk.
Commission Determination
58. The Commission agrees with NERC that TPL-001-4, Requirement R6
is not strictly an administrative task and approves the change from a
low VRF to a medium VRF. The Commission disagrees with commenters that
TPL-001-4 Reliability Standard, Requirement R6 is purely an
administrative task of documentation of criteria and methodologies.
Requirement R6 goes beyond documentation by requiring planners to apply
engineering judgment and analysis to ``define[hellip]the criteria or
methodology used in the analysis to identify system instability for
conditions such as cascading, voltage instability or uncontrolled
islanding.'' \49\
---------------------------------------------------------------------------

\49\ Proposed TPL-001-4 Reliability Standard, Requirement R6.
---------------------------------------------------------------------------

3. Protection System Failures versus Relay Failures
NERC Petition
59. NERC's proposal includes modifications to the planning
contingency categories in Table 1. NERC explains that the modifications
are intended to add clarity and consistency regarding the modeling of a
delayed fault clearing in a planning study. NERC stated that the basic
elements of any protection system design involve inputs to protective
relays and outputs from protective relays and that reliability issues
associated with improper clearing of a fault on the bulk electric
system can result from the failure of hundreds of individual protection
system components in a substation. According to NERC, while the
population of components that could fail and result in improper
clearing is large, the population can be reduced dramatically by
eliminating those components which share failure modes with other
components. NERC stated that the critical components in protection
systems are the protective relays themselves, and a failure of a non-
redundant protective relay will often result in undesired consequences
during a fault. According to NERC, other protection system components
related to the protective relay could fail and lead to a bulk electric
system issue, but the event that would be studied is identical, from
both transient and steady state perspectives, to the event resulting
from a protective relay failure if an adequate population of protective
relays is considered.\50\
---------------------------------------------------------------------------

\50\ NERC's October 2011 Petition at 48.
---------------------------------------------------------------------------

NOPR Proposal
60. In the April 2012 NOPR, the Commission expressed that, based on
various protection system designs, the planner will have to choose
which protection system component failure would have the most
significant impact on the Bulk-Power System because as-built designs
are not standardized and the most critical component failure may not
always be the relay.\51\ The Commission sought comment on whether the
proposed provisions pertaining to study of multiple contingencies
limits the planners' assessment of a protection system failure because
the proposed provisions only include the contingency of a faulty relay
component. The Commission also sought comment on whether the relay is
always the larger contingency and how the loss of protection system
components that is integral to multiple protection systems impacts
reliability.
---------------------------------------------------------------------------

\51\ April 2012 NOPR, 139 FERC ] 61,059 at P 31.
---------------------------------------------------------------------------

Comments
61. NERC states that the proposed Reliability Standard addresses
the existing ambiguity requiring a study of a stuck breaker or
protection system failure by specifying that both a stuck breaker and
protection system failure must be evaluated. NERC states that its
solution ensures that simulations of both categories are performed,
reducing the probability of multiple contingency events leading to
cascading and uncontrolled islanding. Similarly, Hydro One and EEI
contend that a planner does not need to choose which protection system
component failure would have the most significant impact on the Bulk-
Power System in the planning assessment. According to Hydro One, the
contingencies stipulated in Table 1, P5 of the proposed TPL Standard
are appropriate for the conditions and events to be assessed in the P5
groups which focus on the combination of a single line to ground fault
coupled with delayed clearing that may be caused by a protection system
failing to open to clear the fault. Hydro One also states that what
causes the protection system to fail is irrelevant in the context of
delayed clearing by the backup protection system to clear the fault.
EEI expresses concern that expanding planning studies to include all
manner of protection system failures could create a scenario where
planners would have to conduct unlimited and unbounded studies.';
62. In contrast, MISO agrees with the NOPR that the more severe or
larger contingency may not be assessed because the proposed Reliability
Standard limits the planners' assessment of a protection system failure
since it only includes the contingency of a faulty relay component.
MISO suggests expanding the assessment of relay failures to

[[Page 63046]]

include all components of a protection system, including instrument
transformers, protective relays, auxiliary relays and communications
systems.
63. With regard to the Commission's question whether, based on
protection system as-built designs, the relay may not always be the
larger contingency, NERC states that the proposed Table 1, category P5
(fault plus relay failure to operate) planning event requires
evaluation of the failure of the protection system relays whose failure
is most likely to cause cascading or uncontrolled islanding of the bulk
electric system.
64. Hydro One recognizes that a number of components necessary to
operate properly may fail to render a protection system failing to
operate when needed, and that such component failures may result in
disabling more than one protective relay and the impact of multiple
relay failures may be more severe than the SLG fault on a bulk electric
system facility with delayed clearing. According to Hydro One, the more
severe consequences of an initial bulk electric system facility
contingency combined with multiple or more severe protection system
failures would more appropriately be considered or included in the
extreme events category.
65. ISO/RTOs agree that the range of potential assessments should
be expanded to include all components of a protection system including
instrument transformers, protective relays, auxiliary relays and
communications systems for the purpose of category P-5 contingencies,
but because these devices are often in series, consideration of all of
these components will not necessarily have any significant impact on
analyses.
66. With regard to the question of how does the loss of a
protection system component integral to multiple protection systems
impact reliability, NERC states that the loss of a relay that is
integral to multiple protection systems would require simulation of the
full impact of that relay's failure on the system for the event being
studied under the category P5 planning event. With respect to whether
there is a reliability concern regarding single points of failure on
protection systems, NERC indicates that it has a project underway to
assess that question.\52\
---------------------------------------------------------------------------

\52\ NERC Comments at 10.
---------------------------------------------------------------------------

67. Hydro One views the avoidance of having single component
failure affecting more than one protection system as a protection
system design issue. Hydro One states that some regional reliability
organizations have in place criteria to ensure protection systems
operate properly and to avoid failure of a single component affecting
multiple protection systems.
Commission Determination
68. The Commission agrees with NERC's statement that Reliability
Standard-TPL-001-4 addresses the existing ambiguity of the currently-
effective TPL Reliability Standards requiring a study of a stuck
breaker or protection system failure. We find that Reliability Standard
TPL-001-4, specifying that both a stuck breaker and a relay failure
must be evaluated, is reasonable to remove the ambiguity. Further, as
explained by NERC, the loss of a relay that is integral to multiple
protection systems would require simulation of the full impact of that
relay's failure on the system for the event being studied under the
category P5 planning event. In addition, Reliability Standard TPL-001-4
requires study and evaluation of both a stuck breaker (Table 1,
Category P4) and a relay failure (Table 1, Category P5) and that
simulations of both categories reduce the probability of multiple
contingency events leading to cascading, instability or uncontrolled
islanding.
69. The Commission does not find the need to take any further
action with regard to this issue. We note, however, that an assessment
of a relay component failure may not necessarily assess the more severe
or larger contingency, compared to a protection system failure under
the currently-effective TPL Standards. Based on various protection
system as-built designs, NERC has indicated that the planner should use
``engineering judgment in its selection of the protection system
component failures for evaluation that would produce the more severe
system results or impact. . . . The evaluation would include addressing
all protection systems affected by the selected component. A protection
system component failure that impacts one or more protection systems
and increases the total fault clearing time requires the [planner] to
simulate the full impact (clearing time and facilities removed) on the
Bulk Electric System performance.'' \53\ However, the Commission will
not direct NERC to modify the standard at this time, pending completion
of NERC's work on single points of failure on protection systems.\54\
---------------------------------------------------------------------------

\53\ NERC Petition For The Approval of An Interpretation to
Reliability Standards TPL-003-0a and TPL-004-0, April 12, 2013 at
13, Docket No. RD13-8-000, approved by unpublished letter order June
20, 3013.
\54\ March 15, 2012 NERC Informational Filing in Docket No.
RM10-6-000 at 5, 7, stating that NERC has initiated a data request
to evaluate potential exposure to types of protection system
failures.
---------------------------------------------------------------------------

4. Assessment of Backup or Redundant Protection Systems NOPR Proposal
70. Requirement R3, Part 3.3.1 and Requirement R4, Part 4.3.1 of
Reliability Standard TPL-001-4 require that simulations duplicate what
will happen in an actual power system based on the expected performance
of the protection systems.\55\ According to NERC, these requirements
ensure that, for a protection system designed ``to remove multiple
Elements from service for an event that the simulation will be run with
all of those Elements removed from service.'' \56\ In the NOPR, the
Commission observed that these provisions do not explicitly refer to
``backup or redundant systems'' as in the currently-effective
Reliability Standards and sought clarification whether the proposal
includes backup and redundant protection systems.
---------------------------------------------------------------------------

\55\ NERC's October 2011 Petition at 20.
\56\ Id.
---------------------------------------------------------------------------

Comments
71. NERC clarifies that proposed Requirement R3, Part 3.3.1 and
Requirement R4, Part 4.3.1 ``require the consideration of all
protection systems that are relevant to the contingency studied,''
which includes ``backup and redundant systems.'' \57\ EEI believes that
the language is sufficiently clear to ensure a common understanding
that backup and redundant protection system impacts needed to be
studied regardless of whether the specific words as found in the
currently active standard were used. ISO/RTOs and MISO believe that if
a protection system is not fully redundant, contingencies should be
studied to simulate both delayed clearing and operation of remote
backup protection to trip additional facilities when required. MISO
states that if a protection system is fully redundant, that is, if a
single failure of any component in the protection system (other than
monitored DC voltage) would not result in delayed or failed tripping it
should not be necessary to analyze the redundant protection system
failure.
---------------------------------------------------------------------------

\57\ NERC Comments at 11.
---------------------------------------------------------------------------

Commission Determination
72. The Commission agrees with NERC and finds that Requirement R3,
Part 3.3.1 and Requirement R4, Part 4.3.1 include the assessments of
backup protection systems. The Commission

[[Page 63047]]

agrees with ISOs/RTOs and MISO that if a primary protection system has
a fully redundant backup protection system, assessments of the primary
protection system is required, but not of the fully redundant backup
protection system since the assessment results will be identical.
Further, we agree that if a protection system is not fully redundant,
contingencies are studied to simulate both delayed clearing and
operation of remote backup protection which may trip additional
facilities when required.
P5 Single Line to Ground Faults
NOPR Proposal
73. In the April 2012 NOPR, the Commission sought clarification
whether ``fault types'' in Table 1 refers to the initiating event.\58\
---------------------------------------------------------------------------

\58\ April 2012 NOPR, 139 FERC ] 61,059 at P 38.
---------------------------------------------------------------------------

Comments
74. NERC, EEI, BPA and ISO/RTOs all concur that ``fault types''
refer to the initiating fault to be studied, not to what the fault may
evolve into as a result of the simulated conditions. According to NERC,
the possibility of a single-line-to-ground fault evolving into a three-
phase fault is addressed by requiring the study of a three-phase fault
as the initial fault.
Commission Determination'
75. The Commission finds that the explanation of NERC and others,
i.e., ``fault types'' in Reliability Standard TPL-001-4, Table 1--
Steady State & Stability Performance Planning Events means the type of
fault that initiated the event, is reasonable. For example, if the
initiating fault type is a single-line-to-ground fault and it evolves
into a three-phase fault, the single-line-to-ground fault is still
evaluated as the initiating fault type. If a three-phase fault occurs
as the initiating event, the fault is assessed as a three phase fault.
Regardless of what the initiating fault type becomes, it does not
change the initiating fault type.
6. Order No. 693 Directives
76. In the April 2012 NOPR, the Commission indicated that the
Version 4 TPL Standard appeared responsive to the Order No. 693
directives regarding the TPL Reliability Standards. However, the
Commission sought clarification and comment on the following issues:
(a) Peer review of planning assessments, (b) spare equipment strategy,
(c) range of extreme events, (d) footnote `a' and (e) controlled load
interruption, dynamic load models and proxies to simulate cascade.\59\
---------------------------------------------------------------------------

\59\ April 2012 NOPR, 139 FERC ] 61,059 at PP 39-54.
---------------------------------------------------------------------------

77. The Commission is satisfied and agrees with the comments
submitted by NERC, EEI and ISO/RTO on issues regarding controlled load
interruption (i.e., third parties must have the same non-consequential
load loss options as available to the planner), dynamic load models
(i.e., documentation of dynamic load models used in system studies and
the supporting rationale for their use is required) and proxies to
simulate cascade (i.e., planners must define and document their
criteria or methodology including proxies that are used in planning
assessments due to modeling and simulation limitations). Below, we
address in greater detail the comments on peer review of planning
assessments, spare equipment strategy, range of extreme events, and
footnote `a.'
a. Peer Review of Planning Assessments
NOPR Proposal
78. The Commission stated in Order No. 693 that, because
neighboring systems may adversely impact one another, such systems
should be involved in determining and reviewing system conditions and
contingencies to be assessed under the currently-effective TPL
Reliability Standards.\60\ In its petition, NERC stated the proposed
Reliability Standard does not include a ``peer review'' of planning
assessments but instead includes an equally effective and efficient
manner to provide for the appropriate sharing of information with
neighboring systems in proposed Requirement R3, Part 3.4.1, Requirement
R4, Part 4.4.1, and Requirement R8.\61\
---------------------------------------------------------------------------

\60\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1750.
\61\ NERC's October 2011 Petition at 21.
---------------------------------------------------------------------------

79. In the April 2012 NOPR, the Commission sought clarification on
how the NERC proposal ensures the early input of peers into the
planning assessments or any type of coordination among peers will
occur. The Commission also sought comment on whether and how
neighboring systems can sufficiently evaluate and provide feedback to
the planners on the development and result of assessments and whether
it requires input on the comments to be included in the results or the
development of the planning assessments.
Comments
80. NERC and EEI state that, prior to sharing planning assessment
results in Requirement R8, Requirement R3, Part 3.4.1 and Requirement
R4, Part 4.4.1 require planners to coordinate with adjacent planners to
develop contingency lists for steady state and stability analysis. EEI
states it is most beneficial to planners if coordination occurs earlier
in the planning assessment process.
81. NERC and EEI also explain that Requirements R2 through R6
provide adjacent entities sufficient information on how the assessment
was performed and expected system performance to effectively evaluate
the assessment results and to provide feedback. Further, Requirement R8
requires that each planner must distribute its planning assessment
results to adjacent planners within 90 calendar days of completing its
assessment.
82. 1BPA states that, while adjacent planners and coordinators
should have a stake in the results of an affected planning assessment,
they should not be allowed to second guess the transmission planner's
or planning coordinator's studies and methodologies. BPA adds that it
is important for adjacent planners to have input on how other planning
assessments will affect them, and the proposed Reliability Standards
allows such input.
Commission Determination
83. The Commission agrees with NERC and EEI that coordination of
contingency lists with adjacent planners under TPL-001-4 Reliability
Standard, Requirement R3, Part 3.4.1 and Requirement R4, Part 4.4.1
ensures that contingencies on adjacent systems that impact other
systems are developed and included in the planners' steady state and
stability analysis planning assessments.\62\ Coordination of
contingency lists provides one aspect of early coordination among
planners.
---------------------------------------------------------------------------

\62\ Because neighboring systems may be adversely impacted by
other systems, such systems should be involved early in determining
and reviewing conditions and contingencies in planning assessments.
Order No. 693, FERC Stats. & Regs. ] 31,242 at PP 1750, 1754.
---------------------------------------------------------------------------

84. We are satisfied with the explanation of NERC and EEI that TPL-
001-4 Reliability Standard, Requirement R8 allows planners to
coordinate and distribute conditions to adjacent planners as part of
their planning assessment and to provide feedback to other planners.
While we also agree with BPA that adjacent planners should be informed
of and have a stake in the results of another planner's assessment, we
disagree with BPA's characterization that a planner ``should not be
allowed to second guess'' another planner's studies or

[[Page 63048]]

methodologies. Rather, early peer input in the planning assessments and
coordination among peers to identify possible interdependent or adverse
impacts on neighboring systems are essential to the reliable operation
of the bulk electric system.\63\
---------------------------------------------------------------------------

\63\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1754:
``Given that neighboring systems assessments by one entity may
identify possible interdependant or adverse impacts on its
neighboring systems, this peer review will provide an early
opportunity to provide input and coordinate plans.''
---------------------------------------------------------------------------

Spare Equipment Strategy
NOPR Proposal
85. In Order No. 693, the Commission directed NERC to develop a
modification ``to require assessments of outages of critical long lead-
time equipment, consistent with the entity's spare equipment
strategy.'' \64\ In response, NERC developed proposed Requirement 2,
Part 2.1.5 which addresses steady state conditions to determine system
response when equipment is unavailable for prolonged periods of time.
---------------------------------------------------------------------------

\64\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1786.
---------------------------------------------------------------------------

86. In the NOPR, the Commission raised the concern that the
proposed spare equipment strategy appears to be limited to ``steady
state analysis'' and sought clarification why ``stability analysis''
conditions are not mentioned.
Comments
87. NERC, ISOs/RTOs, and EEI comment that the burden of additional
stability analyses would not provide significant reliability benefits
because stability analysis already required under ``category P6'' will
produce more definitive tests of longer-term equipment unavailability.
They also claim that any potential stability impacts related to an
entity's spare equipment strategy will be observed in the normal
planning process driven by other requirements.
Commission Determination
88. The Commission agrees that NERC has met the spare equipment
strategy directive for steady state analysis under Reliability Standard
TPL-001-4, Requirement R2, Part 2.1.5. However, the Commission finds
that a spare equipment strategy for stability analysis is not addressed
under category P6.
89. The spare equipment strategy for steady state analysis under
Reliability Standard TPL-001-4, Requirement R2, Part 2.1.5 requires
that steady state studies be performed for the P0, P1 and P2 categories
identified in Table 1 with the conditions that the system is expected
to experience during the possible unavailability of the long lead time
equipment. The Commission believes that a similar spare equipment
strategy for stability analysis should exist that requires studies to
be performed for P0, P1 and P2 categories with the conditions that the
system is expected to experience during the possible unavailability of
the long lead time equipment. Further, we are not persuaded by the
explanation of NERC and others that a similar spare equipment strategy
for stability analysis would cause unjustified burden because stability
analysis is already required under category P6. The Commission notes
that the category P2 contingencies studied under the spare equipment
strategy for steady state analysis are different than the contingencies
studied under category P6. For example, under the spare equipment
strategy for steady state, a planner would study a long lead-time piece
of equipment out of service (e.g., a transformer) along with a bus
section fault contingency (i.e., category P2, event 2). The study of
this same condition for stability analysis under category P6 is not
addressed. However, the Commission will not direct a change and instead
directs NERC to consider a similar spare equipment strategy for
stability analysis upon the next review cycle of Reliability Standard
TPL-001-4.
C. Range of Extreme Events
NOPR Proposal
90. In Order No. 693, the Commission directed NERC to modify the
Version 0 Reliability Standard, TPL-004-0, to require that, in
determining the range of the extreme events to be assessed, the
contingency list of category D would be expanded to include recent
events such as hurricanes and ice storms.\65\ In the April 2012 NOPR,
the Commission indicated that, while the proposed Version 4 TPL
Standard appropriately expands the list of extreme event examples in
Table 1, the list limits these items to the loss of two generating
stations under Item No. 3a. The Commission sought clarification on
conditioning extreme events on the loss of two generating stations.\66\
The Commission also sought clarification regarding whether the ``two
generation stations'' limitation would adequately capture a scenario
where an extreme event can impact more than two generation stations.
---------------------------------------------------------------------------

\65\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1834.
\66\ April 2012 NOPR, 139 FERC ] 61,059 at P 48.
---------------------------------------------------------------------------

Comments
91. NERC asserts that it addressed the Order No. 693 directive to
expand the range of events considered in the planning assessment by
adding a new category ``wide area events'' as extreme events. NERC
contends that it is raising the bar concerning extreme events by
requiring the planners to evaluate the loss of two generating stations
for a wide range of external events that could cause the loss of all
generating units at two generating stations. NERC adds that extreme
events in item 3b of Table 1 means that the planner will consider even
more extreme events (i.e., the loss of more facilities than the loss of
two generating stations) based upon operating experience and knowledge
of its system.
92. EEI agrees with the Commission that there are conditions that
provide far more serious impacts to the grid than that which is
described in item 3a of Table 1 of the proposed standard. However,
those conditions are largely area specific thereby making it impossible
to describe or address all possibilities in a Standard. EEI, therefore,
supports NERC's approach which obligates planners to consider, as
stated in Item 3b, ``[o]ther events based upon operating experience
that may result in wide area disturbances.'' EEI believes that Table 1,
Item No. 3b provides the necessary backstop to ensure that extreme
events are fully captured from a planning standpoint.\67\
---------------------------------------------------------------------------

\67\ EEI Comments at 14-15.
---------------------------------------------------------------------------

Commission Determination
93. The Commission is satisfied with the explanation of NERC and
EEI that Table 1, item No. 3b provides the necessary backstop to ensure
that extreme events are fully captured from a planning standpoint
including extreme events that can impact more than two generating
stations and that a planner will consider even more extreme events
based on operating experience and knowledge of its system.
d. Footnote `a'
NOPR Proposal
94. In Order No. 693, the Commission directed NERC to modify
footnote `a' of Table 1 with regard to ``applicability of emergency
ratings and consistency of normal ratings and voltages with values
obtained from other reliability standards.'' \68\ In its petition, NERC
noted that proposed Table 1, header note `e,' which provides that
planned system adjustments must be executable

[[Page 63049]]

within the time duration applicable to facility ratings. Further,
according to NERC, header note `f,' which states applicable facility
ratings shall not be exceeded, meets the Order No. 693 directive
pertaining to footnote `a' in the current standard.
---------------------------------------------------------------------------

\68\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1770.
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95. In the NOPR the Commission observed that the proposed standard
applies header note `e' to ``Steady State and Stability,'' while header
note `f' is excluded from ``Stability'' and only applies to ``Steady
State'' studies. Accordingly, the Commission sought clarification
regarding the rationale for excluding header note `f' from
``Stability'' studies. In addition, for Table 1, header notes `e' and
`f,' the Commission sought comment on whether the normal facility
ratings align with Reliability Standard FAC-008-1 and normal voltage
ratings align with Reliability Standard VAR-001-1. Furthermore, the
Commission sought clarification whether facility ratings used in
planning assessments align with other reliability standards such as
Reliability Standards NUC-001-2, BAL-001-0.1a and the PRC Reliability
Standards for UFLS and UVLS.
Comments
96. NERC states that it excluded header note `f' from stability
studies because facility ratings are defined for a finite period which
may be between a few minutes and several hours, or longer. According to
NERC, in stability studies the analysis is conducted over a few seconds
and because facility ratings are established based on the overheating
of elements, the few seconds in the stability timeframe is not
significant to the overheating of elements.\69\
---------------------------------------------------------------------------

\69\ See also BPA Comments at 5, EEI Comments at 15 and ISO/RTOs
Comments at 11.
---------------------------------------------------------------------------

97. ISO/RTO states that the observation of facility trip ratings
(i.e., relay trip ratings) are valid in the stability simulation time
frame, and should be considered if associated protective relay schemes
are sensitive to power swings (e.g., impedance relays with no out-of
step trip blocking for stable swings, etc.). Further, ISO/RTO believes
that there is no reason to include a requirement to observe thermal
facility ratings in stability studies, but also believes that facility
trip ratings should be observed in stability studies.
98. NERC and EEI also explain that the values used for facility
ratings within transmission planning models are developed in accordance
with standard FAC-008-1 ``Facility Ratings Methodology'' and
communicated to other functional entities as required by FAC-009-1
``Establish and Communicate Facility Ratings.''
99. In response to the Commission's request for clarification
whether facility ratings used in planning assessments align with other
Reliability Standards, commenters generally stated that facility
ratings used in the TPL standard are consistent throughout the NERC
standards. Further, commenters stated that Reliability Standard VAR-
001-2 is not a ratings standard but an operational (real-time) standard
to ensure voltage levels, reactive flows and reactive resources are
monitored, controlled and maintained within the limits of the
equipment.\70\
---------------------------------------------------------------------------

\70\ See NERC Comments at 16 and EEI Comments at 15.
---------------------------------------------------------------------------

Commission Determination
100. The Commission is satisfied with commenters' explanation and
agrees that it is not necessary to include a requirement to observe
thermal facility ratings in stability studies. The Commission agrees
with ISO/RTO that facility trip ratings (i.e., relay trip ratings) are
valid ratings in the stability simulation time frame, and should be
considered in the planning assessment if associated protective relay
schemes are sensitive to power swings (e.g., impedance relays with no
out-of step trip blocking for stable swings). Further, the Commission
accepts the explanation of NERC and others that facility ratings used
in planning assessments are determined in accordance with Reliability
Standard FAC-008-3,\71\ which states that a ``Facility Rating shall
respect the most limiting applicable Equipment Rating of the individual
equipment that comprises that Facility.''
---------------------------------------------------------------------------

\71\ In ``Order Approving Reliability Standard'' issued November
17, 2011 (Docket No. RD11-10-000), the Commission approved FAC-008-3
Reliability Standard and the retirement of FAC-008-1 and FAC-009-1
Reliability Standards.
---------------------------------------------------------------------------

C. Other Matters Raised by Commenters

101. Powerex states that additional clarification is needed with
respect to Footnote 9 to Table 1 in order to provide clarity and ensure
consistent interpretation as to when transmission planners may plan to
curtail firm transmission service. Powerex is concerned that the
revised TPL Standard may provide transmission planners with broad
discretion to plan for the curtailment of firm transmission service
without providing purchase-selling entities with the notice and
certainty they need to make appropriate alternate arrangements. Powerex
believes that the phrase in footnote 9 ``resources obligated to re-
dispatch'' should be clarified as referring to a formal agreement
between the transmission provider and a generation owner, located on
the load side of a transmission constraint, to resupply the load that
had been receiving energy from a remote source before the firm
transmission service was curtailed.
Commission Determination
102. We will not direct NERC to modify footnote 9. We find NERC's
explanation satisfactory that ``the planner must be able to show that
the curtailment is supported by a valid re-dispatch of generation that
would be `obligated to redispatch' . . . [t]herefore, the planner
cannot simply re-dispatch units outside the area of control for the
transmission system for which it is reviewing--the re-dispatch must be
valid and realistic.'' \72\
---------------------------------------------------------------------------

\72\ NERC Petition, Consideration of Comments on Assess
Transmission Future Needs and Develop Transmission Plans--Project
2006-02, draft 6, pp. 78-79.
---------------------------------------------------------------------------

III. Information Collection Statement

103. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\73\ Upon approval of a collection(s)
of information, OMB will assign an OMB control number and expiration
date. Respondents subject to the filing requirements of this rule will
not be penalized for failing to respond to these collections of
information unless the collections of information display a valid OMB
control number.
---------------------------------------------------------------------------

\73\ 5 CFR 1320.11.
---------------------------------------------------------------------------

104. The Commission is submitting these reporting and recordkeeping
requirements to OMB for its review and approval under section 3507(d)
of Paperwork Reduction Act of 1995. The Commission solicited comments
on the need for and the purpose of the information contained in
Reliability Standard TPL-001-4 and the corresponding burden to
implement the Reliability Standard. The Commission received comments on
specific requirements in the Reliability Standard, which we address in
this Final Rule. However, the Commission did not receive any comments
on our reporting burden estimates. The Final Rule approves Reliability
Standard TPL-001-4.
105. Public Reporting Burden: The burden and cost estimates below
are based on the increase in the reporting and recordkeeping burden
imposed by the proposed Reliability Standards. Our estimates are based
on the NERC Compliance Registry as of February 28, 2013, which indicate
that NERC has

[[Page 63050]]

registered 183 transmission planners and planning coordinators.

--------------------------------------------------------------------------------------------------------------------------------------------------------
Average number of
Improved requirement \74\ Year Number and type of Number of annual paperwork hours per Total burden hours
entity \75\ responses per entity response
...................... (1)................... (2).................. (3).................. (1)*(2)*(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Identification of Joint Year 1................ 183 Transmission 1 response........... 9 (5 engineer hours 1,647
Responsibilities and System Planners and Planning and 4 record keeping
Modeling Enhancements \76\. Coordinators. hours).
Year 2 and Year 3..... 183 Transmission 1 response........... 5 (3 engineer hours 915
Planners and Planning and 2 record keeping
Coordinators. hours).
New Assessments, Simulations, Year 2................ 183 Transmission 1 response........... 145 (84 engineer 26,535
Studies, Modeling Enhancements and Planners and Planning hours, 61 record
associated Documentation\77\. Coordinators. keeping hours).
Year 3................ 183 Transmission 1 response........... 84 (45 engineer 15,372
Planners and Planning hours, 39 record
Coordinators. keeping hours).
Attachment 1 stakeholder process... Year 3................ 1 Transmission Planner 12 responses to 63 (40 engineer 756
and Planning Attachment 1, hours, 17 record
Coordinator. sections I and II. keeping hours, 6
legal hours).
Year 3................ 1 Transmission Planner 4 responses to 68 (40 engineer 272
and Planning Attachment 1, hours, 20 record
Coordinator. Sections I, II, and keeping hours, 8
III. legal hours).
--------------------------------------------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------

\74\ Each requirement identifies a reliability improvement by
proposed Reliability Standard TPL-001-4.
\75\ NERC registered transmission planners and planning
coordinators responsible for the improved requirement. Further, if a
single entity is registered as both a transmission planner and
planning coordinator, that entity is counted as one unique entity.
\76\ The Commission estimates a reduction in burden hours from
year 1 to year 2 because year 1 represents a portion of one-time
tasks not repeated in subsequent years.
\77\ The Commission estimates a reduction in burden hours from
year 2 to year 3 because year 2 represents a portion of one-time
tasks not repeated in subsequent years.
---------------------------------------------------------------------------

Costs To Comply With Paperwork Requirements

Year 1: $77,592.
Year 2: $1,312,659.
Year 3 and ongoing: $820,149.
106. Year 1 costs include the implementation of those improved
requirements that become effective on the first day of the first
calendar quarter, 12 months after applicable regulatory approval, which
include requirements such as coordination between entities and
incremental system modeling enhancements. Year 2 costs include a
portion of year 1 reoccurring costs plus the implementation of the
remaining improved requirements that become effective on the first day
of the first calendar quarter, 24 months after applicable regulatory
approval, which include requirements such as sensitivity studies for
steady state and stability analysis, implementation of a spare
equipment strategy, short circuit studies, an expansion of
contingencies and extreme events, and all associated system modeling
enhancements and documentation. Year 3 costs include a portion of year
2 reoccurring costs plus an estimated cost for Attachment 1 stakeholder
process, if needed.
107. For the burden categories above, the loaded (salary plus
benefits) costs are: $60/hour for an engineer; $31/hour for
recordkeeping; and $128/hour for legal.\78\ The estimated breakdown of
annual cost is as follows:
---------------------------------------------------------------------------

\78\ Labor rates from Bureau of Labor Statistics (BLS) (https://bls.gov/oes/current/naics2_22.htm). Loaded costs are BLS rates
divided by 0.703 and rounded to the nearest dollar (https://www.bls.gov/news.release/ecec.nr0.htm).
---------------------------------------------------------------------------

Year 1
[cir] Identification of Joint Responsibilities and System Modeling
Enhancements: 183 entities * [(5 hours/response * $60/hour) + (4 hours/
response * $31/hour)] = $77,592.
Year 2
[cir] Identification of Joint Responsibilities and System Modeling
Enhancements: 183 entities * [(3 hours/response * $60/hour) + (2 hours/
response * $31/hour)] = $44,286.
[cir] New Assessments, Simulations, Studies, Modeling Enhancements
and associated Documentation: 183 entities * [(84 hours/response * $60/
hour) + (61 hours/response * $31/hour)] = $1,268,373.
Year 3
[cir] Identification of Joint Responsibilities and System Modeling
Enhancements: 183 entities * [(3 hours/response * $60/hour) + (2 hours/
response * $31/hour)] = $44,286.
[cir] New Assessments, Simulations, Studies, Modeling Enhancements
and associated Documentation: 183 entities * [(45 hours/response * $60/
hour) + (39 hours/response * $31/hour)] = $715,347.
[cir] Implementation of footnote 12 and the stakeholder process:
{12 responses * [(40 hours/response * $60/hour) + (17 hours/response *
$31/hour) + (6 hours/response * $128/hour)]{time} + {4 responses *
[(40 hours/response * $60/hr) + (20 hours/response * $31/hour) + (8
hours/response * $128/hour)]{time} = $60,516.
Title: 725N, Mandatory Reliability Standards: Reliability Standard
TPL-001-4.\79\
---------------------------------------------------------------------------

\79\ The Supplemental NOPR used the identifier FERC-725A (OMB
Control No. 1902-0244). However, for administrative purposes and to
submit the information collection requirements to OMB timely, the
requirements were labeled FERC-725N (OMB Control No. 1902-0264) in
the submittal to OMB associated with the NOPR. We are using FERC-
725N in this Final Rule and in the associated submittal to OMB.

---------------------------------------------------------------------------

[[Page 63051]]

Action: Proposed Collection FERC-725N.
OMB Control No: 1902-0264.
Respondents: Business or other for profit, and not for profit
institutions.
Frequency of Responses: Annually and one-time.
Necessity of the Information: The approved Reliability Standard
TPL-001-4 implements the Congressional mandate of the Energy Policy Act
of 2005 to develop mandatory and enforceable Reliability Standards to
better ensure the reliability of the nation's Bulk-Power System.
Specifically, the Reliability Standard ensures that planning
coordinators and transmission planners establish transmission system
planning performance requirements within the planning horizon to
develop a bulk electric system that will operate reliability and meet
specified performance requirements over a broad spectrum of system
conditions to meet present and future system needs.
Internal review: The Commission has reviewed the revised
Reliability Standard TPL-001-4 and made a determination that its action
is 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.
Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, email:
DataClearance@ferc.gov, phone: 202-502-8663, fax: 202-273-0873]. For
submitting comments concerning the collection(s) of information and the
associated burden estimate(s), please send your comments to the
Commission and to the Office of Management and Budget, Office of
Information and Regulatory Affairs, Washington, DC 20503 [Attention:
Desk Officer for the Federal Energy Regulatory Commission, phone: 202-
395-4638, fax: 202-395-7285]. For security reasons, comments to OMB
should be submitted by email to: oira_submission@omb.eop.gov. Comments
submitted to OMB should include FERC-725N and Docket Nos. RM12-1-000
and RM13-9-000.

IV. Environmental Analysis

108. 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.\80\ 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.\81\ The actions proposed
herein fall within this categorical exclusion in the Commission's
regulations.
---------------------------------------------------------------------------

\80\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
\81\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act Analysis

109. The Regulatory Flexibility Act of 1980 (RFA) \82\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a proposed rule and that minimize
any significant economic impact on a substantial number of small
entities. The Small Business Administration's (SBA) Office of Size
Standards develops the numerical definition of a small business.\83\
The SBA has established a size standard for electric utilities, stating
that a firm is small if, including its affiliates, it is primarily
engaged in the transmission, generation and/or distribution of electric
energy for sale and its total electric output for the preceding twelve
months did not exceed four million megawatt hours.\84\
---------------------------------------------------------------------------

\82\ 5 U.S.C. 601-12.
\83\ 13 CFR 121.101.
\84\ 13 CFR 121.201, Sector 22, Utilities & n.1.
---------------------------------------------------------------------------

110. As discussed above, Reliability Standard TPL-001-4 would apply
to 183 transmission planners and planning coordinators identified in
the NERC Compliance Registry. Comparison of the NERC Compliance
Registry with data submitted to the Energy Information Administration
on Form EIA-861 indicates that, of the 183 registered transmission
planners and planning coordinators registered by NERC, 41 may qualify
as small entities.
111. The Commission estimates that, on average, each of the 41
small entities affected will have an estimated cost of $1,324 in Year
1, $16,953 in Year 2 \85\ and $11,471 in Year 3 (without Attachment 1).
In addition, based on the results of NERC's data request approximately
10 percent of all registered transmission planners and planning
coordinators used planned non-consequential load loss under the
currently-effective TPL Reliability Standards. The Commission estimates
that approximately 4 of the 41 small entities would use the stakeholder
process set forth in Attachment 1. The total estimated cost per
response for each of these 4 small entities in Year 3 is approximately
$19,500 if Attachment 1, sections I and II are used, or $20,000 if
Attachment 1, sections I, II and III are used. These figures are based
on information collection costs plus additional costs for compliance.
Based on this estimate, the Commission certifies that Reliability
Standard TPL-001-4 will not have a significant economic impact on a
substantial number of small entities. Accordingly, no regulatory
flexibility analysis is required.
---------------------------------------------------------------------------

\85\ The increase in Year 2 costs include a portion of year 1
recurring costs plus the implementation of the remaining improved
requirements that become effective on the first day of the first
calendar quarter, 24 months after applicable regulatory approval.
---------------------------------------------------------------------------

VI. Document Availability

112. 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 (https://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.
113. 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.
114. 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

115. These regulations are effective December 23, 2013. The
Commission has determined that this rule is not a ``major rule'' as
defined in section 351 of the Small Business Regulatory Enforcement
Fairness Act of 1996.

[[Page 63052]]

By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2013-24828 Filed 10-22-13; 8:45 am]
BILLING CODE 6717-01-P

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