Document ID: FERC-2013-1401-0001
Agency: ferc
Document Type: Rule
Title: Transmission Planning Reliability Standards
Posted Date: 2013-10-23T04:00Z

[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.
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    \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.
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    \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).
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    \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, http://www.nerc.com.
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    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\
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    \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.
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    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\
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    \24\ NERC's February 2013 Petition at 11.
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    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\
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    \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.
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    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\
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    \28\ Id. P 20.
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    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.
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    \29\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1792.
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    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.''
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

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[[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.
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    \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).
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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\
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    \82\ 5 U.S.C. 601-12.
    \83\ 13 CFR 121.101.
    \84\ 13 CFR 121.201, Sector 22, Utilities & n.1.
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    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.
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    \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.
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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 (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5:00 
p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 
20426.
    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