145 FERC ¶ 61,051

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 40

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

Transmission Planning Reliability Standards

(Issued October 17, 2013)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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, and a 

more specifically defined, open and transparent, verifiable, and enforceable stakeholder 
Docket Nos. RM12-1-000 and RM13-9-000 - 2 -

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 [Insert date 60 days after publication in the 

FEDERAL REGISTER].

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

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

 Philip D. Moeller, John R. Norris,

Cheryl A. LaFleur, and Tony Clark.

Transmission Planning Reliability Standards Docket Nos. RM12-1-000 and 

RM13-9-000

Order No. 786

FINAL RULE

(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 Commissioncertified 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 

 1 16 U.S.C. 824o(d) (2006).
Docket Nos. RM12-1-000 and RM13-9-000 2

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. 

2. Further, in response to Order No. 762,3 Reliability Standard TPL-001-4 

includes a provision that allows a transmission planner to plan for nonconsequential load loss following a single contingency. While the Reliability 

Standard provides that “an objective of the planning process is to limit the 

likelihood and magnitude of Non-Consequential Load Loss following planning 

events,” the standard also recognizes that “[i]n limited circumstances, NonConsequential Load Loss may be needed throughout the planning horizon to 

ensure that BES performance requirements are met.”4

 Thus, for such limited 

circumstances, Reliability Standard TPL-001-4 provides a blend of specific 

quantitative and qualitative parameters for the permissible use of planned nonconsequential load loss to address bulk electric system performance issues, 

 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).

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.
Docket Nos. RM12-1-000 and RM13-9-000 3

including firm limitations on the maximum amount of load that an entity may plan 

to shed, safeguards to ensure against inconsistent results and arbitrary 

determinations that allow for the planned non-consequential load loss, and a more 

specifically defined, open and transparent, verifiable, and enforceable stakeholder 

process. 

3. For the reasons discussed in detail below, the Commission finds that 

Reliability Standard TPL-001-4 is just, reasonable, not unduly discriminatory or 

preferential, and in the public interest. Therefore, pursuant to section 215(d) of the 

FPA the Commission approves proposed Reliability Standard TPL-001-4. Thus, 

the Commission approves footnote 12 to Table 1 of the Reliability Standard 

(formerly referred to as footnote ‘b’). In addition, as discussed below, the 

Commission finds NERC’s explanation on protection system failures versus relay 

failures, assessment of backup or redundant protection systems, single line to 

ground faults and the Order No. 693 directives to be reasonable. However, the 

Commission has concerns about two issues and directs NERC to modify 

Reliability Standard TPL-001-4 to address the concern that the standard 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. 
Docket Nos. RM12-1-000 and RM13-9-000 4

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 

 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: TPL001-0.1, TPL-002-0b, TPL-003-0a, and TPL-004-0. 

6 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792.
Docket Nos. RM12-1-000 and RM13-9-000 5

in Order No. 693 by June 30, 2010.7 In a June 11, 2010 order, the Commission 

extended the compliance deadline until March 31, 2011.8 

Remand of Footnote b of the Version 1 TPL Reliability Standard 

(RM11-18-000)

5. On March 31, 2011, NERC submitted proposed Reliability Standard TPL002-1 (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. 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

 7 Mandatory Reliability Standards for the Bulk Power System, 130 FERC 

¶ 61,200 (2010).

8 Mandatory Reliability Standards for the Bulk Power System, 131 FERC 

¶ 61,231 (2010).

9 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1794. Nonconsequential 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.
Docket Nos. RM12-1-000 and RM13-9-000 6

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 

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 

 11 Id. P 20.

12 NERC’s October 2011 petition sought approval of Reliability Standard 

TPL-001-2, the associated implementation plan and Violation Risk Factors 

(VRFs) and Violation Severity Levels (VSLs), as well as five new definitions to 

(continued...)
Docket Nos. RM12-1-000 and RM13-9-000 7

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

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 

 

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.”

14 April 2012 NOPR, 139 FERC ¶ 61,059 at P 55. 
Docket Nos. RM12-1-000 and RM13-9-000 8

industry, NERC and the Commission to go forward with the consideration of other 

improvements contained in proposed Version 2.”

15 In addition, the April 2012 

NOPR asked for comment on various aspects of the consolidated Version 2 

Reliability Standard. Comments on the NOPR were due by July 20, 2012. The 

following entities submitted comments: NERC, the Edison Electric Institute 

(EEI), ISO/RTOs,16 ITC Companies,17 Midcontinent Independent System 

Operator Inc. (MISO),18 American Transmission Company LLC (ATCLLC), 

Powerex Corporation (Powerex), Bonneville Power Administration (BPA), and 

Hydro One Networks and the Independent Electricity System Operator (Hydro 

One and IESO). 

Proposed Reliability Standard TPL-001-4 – Version 4 (RM13-9-000)

8. On February 28, 2013, NERC submitted proposed Reliability Standard 

TPL-001-4 (Version 4) in response to the Commission’s remand in Order No. 762

 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.”
Docket Nos. RM12-1-000 and RM13-9-000 9

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

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 

 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 website, 

http://www.nerc.com.
Docket Nos. RM12-1-000 and RM13-9-000 10

system performance utilizing a current annual study or qualified past study for 

each known outage with a duration of at least six months for certain events. It also 

clarifies that qualified past studies can be utilized in the analysis while tightly 

defining the qualifications for those studies. Requirement R2 includes a new part 

2.7.3 that allows transmission planners and planning coordinators to utilize nonconsequential load loss to meet performance requirements if the applicable entities 

are unable to complete a corrective action plan due to circumstances beyond their 

control. 

Requirements R3 and R4: Requirement R3 describes the requirements for 

steady state studies and Requirement R4 explains the requirements for stability 

studies. Requirement R3 and Requirement R4 also require that simulations 

duplicate what will occur in an actual power system based on the expected 

performance of the protection systems. 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 
Docket Nos. RM12-1-000 and RM13-9-000 11

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 
Docket Nos. RM12-1-000 and RM13-9-000 12

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 nonconsequential load loss, and (3) a more specifically defined, open and transparent,

verifiable, and enforceable stakeholder process. Footnote 12 as modified 

provides:

An objective of the planning process is to minimize the likelihood and 

magnitude of Non-Consequential Load Loss following planning events. 

In limited circumstances, Non-Consequential Load Loss may be needed 

throughout the planning horizon to ensure that BES performance 

requirements are met. However, when Non-Consequential Load Loss is 

utilized under footnote 12 within the Near-Term Transmission Planning 

Horizon to address BES performance requirements, such interruption is 

limited to circumstances where the Non-Consequential Load Loss meets 

the conditions shown in Attachment 1. In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW for US 

registered entities. The amount of planned Non-Consequential Load 

Loss for a non-US Registered Entity should be implemented in a manner 

that is consistent with, or under the direction of, the applicable 

governmental authority or its agency in the non-US jurisdiction.
Docket Nos. RM12-1-000 and RM13-9-000 13

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 nonconsequential load loss greater than 25 MW. Specifically, planned nonconsequential load loss between 25 MW and 75 MW, or any planned nonconsequential load loss at the 300 kV level or above would receive greater 

scrutiny by regulatory authorities and the ERO. Where these parameters apply, 

“the Transmission Planner or Planning Coordinator must ensure that applicable 

regulatory authorities or governing bodies responsible for retail electric service
Docket Nos. RM12-1-000 and RM13-9-000 14

issues do not object to the use of Non-Consequential Load Loss under footnote 

12.”21 Further, “[o]nce assurance has been received that the applicable regulatory 

authorities ... responsible for retail electric service issues do not object ... the 

Planning Coordinator or Transmission Planner must submit the information [in 

Section II of Attachment 1] to the ERO for a determination of whether there are 

any Adverse Reliability Impacts” caused by the responsible entity’s request to use 

footnote 12.

22 According to NERC, this provision provides safeguards against 

arbitrary or inconsistent determinations, and also “preserves, to the extent 

practicable, the role of Retail Regulators,” while allowing ERO review for 

possible adverse reliability impacts.23 

13. NERC stated that the combination of numerical limitations and other 

considerations, such as costs and alternatives, guards against a determination 

based solely on a quantitative threshold becoming an acceptable de facto 

interpretation of planned non-consequential load loss. According to NERC, the 

procedures in footnote 12 would enable acceptable, but limited, circumstances of 

 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.
Docket Nos. RM12-1-000 and RM13-9-000 15

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 after the first two years of 

the footnote’s implementation.24

15. NERC requested that requirements R1 and R7 of the Version 4 Reliability 

Standard as well as the definitions become effective on the first day of the first 

calendar quarter twelve months after applicable regulatory approval. In addition, 

except as indicated below, NERC requested that Requirements R2 through R6 and 

Requirement R8 including Table 1 – Steady State & Stability Performance 

Planning Events, Table 1 – Steady State & Stability Performance Extreme Events, 

Table 1 – Steady State & Stability Performance Footnotes (Planning Events & 

Extreme Events) and Attachment 1 become effective and subject to compliance on 

the first day of the first calendar quarter, 24 months after applicable regulatory 

approval. 

 24 NERC’s February 2013 Petition at 11.
Docket Nos. RM12-1-000 and RM13-9-000 16

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 
Docket Nos. RM12-1-000 and RM13-9-000 17

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 nonconsequential load loss, NERC’s proposal adequately addresses the underlying 

reliability concerns raised in Order No. 693, Order No. 762 and the April 2012 

NOPR and, thus, is an equally effective and efficient alternative to address the 

Commission’s directives.

26 In the Supplemental NOPR, the Commission 

proposed to find that proposed footnote 12 would improve reliability by providing 

 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. 
Docket Nos. RM12-1-000 and RM13-9-000 18

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 nonconsequential load loss to meet Reliability Standard TPL-001-4 performance 

requirements for a single contingency event. Further, the Supplemental NOPR 

indicated that NERC’s proposal provides reasonable safeguards, including a 

review process by NERC, to protect against adverse reliability impacts that could 

otherwise result from planned non-consequential load loss.

27 

19. In the Supplemental NOPR, the Commission proposed to direct that NERC 

submit a report on the use of footnote 12, due at the end of the first calendar 

quarter after the first two years 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 nonconsequential load loss. The Commission proposed that the report should also

 27 Id. P 19. 
Docket Nos. RM12-1-000 and RM13-9-000 19

address the effectiveness of the stakeholder process and the use and effectiveness 

of the local regulatory review and NERC review.28 

20. Comments on the Supplemental NOPR were due on June 24, 2013. NERC, 

MISO and ITC Companies filed comments in response to the Supplemental 

NOPR. 

II. Discussion 

21. Pursuant to FPA section 215(d), we find that Reliability Standard TPL-001-

4 is just, reasonable, not unduly discriminatory or preferential, and in the public 

interest. While NERC’s proposal differs from the Commission directives, we find 

that NERC adequately addressed the directives and underlying reliability concerns 

of Order No. 693, Order No. 762 and the April 2012 NOPR and, thus, is an 

equally effective and efficient alternative to address the Commission’s concerns.

29 

We find that the revised TPL Reliability Standard improves uniformity and 

transparency in the transmission planning process and clarifies the instances where 

planners may utilize planned load loss in establishing transmission planning 

performance requirements for reliable bulk electric system operations across 

normal and contingency conditions. We also find that Reliability Standard TPL001-4 will serve as a foundation for annual planning assessments conducted by

 28 Id. P 20. 

29 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792.
Docket Nos. RM12-1-000 and RM13-9-000 20

planning coordinators and transmission planners to plan the bulk electric system

reliably in response to a range of potential contingencies. Further, we find that the 

Reliability Standard presents clear, measurable, and enforceable requirements that 

each planning coordinator and transmission planner must follow when planning its 

system. 

22. In the Supplemental NOPR, the Commission stated it would issue a final 

rule that addresses the consolidated transmission planning Reliability Standard, 

TPL-001-4. Therefore, this Final Rule addresses the modified footnote 12 and 

comments received in response to the Supplemental NOPR as 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 

 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.
Docket Nos. RM12-1-000 and RM13-9-000 21

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. 

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
Docket Nos. RM12-1-000 and RM13-9-000 22

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-
Docket Nos. RM12-1-000 and RM13-9-000 23

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 
Docket Nos. RM12-1-000 and RM13-9-000 24

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 –
Docket Nos. RM12-1-000 and RM13-9-000 25

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 magnitude of planned nonconsequential 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. 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 

 31 Order No. 762, 139 FERC ¶ 61,060 at P 55.
Docket Nos. RM12-1-000 and RM13-9-000 26

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.

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, 

 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.”
Docket Nos. RM12-1-000 and RM13-9-000 27

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 sixmonth 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. 

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 

 34 NERC’s October 2011 Petition at 35.
Docket Nos. RM12-1-000 and RM13-9-000 28

be unknown.35 The Commission sought comment on whether the proposed six 

month threshold would materially change the number of planned outages included 

in planning assessments compared to the number included in planning assessments 

under the currently-effective standard, and whether the threshold would exclude 

nuclear plant refueling, large fossil and hydro generating station maintenance, and 

spring and fall transmission construction projects from future planning 

assessments. The Commission also sought comment on possible alternatives.

35. In the NOPR, the Commission noted that, with respect to protection system 

maintenance, currently-effective Reliability Standard TPL-002-0, Requirement 

R1.3.12 requires the 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. 

 35 April 2012 NOPR, 139 FERC ¶ 61,059 at P 18.

36 Reliability Standard TPL-002-0, Requirement R1.3.12.
Docket Nos. RM12-1-000 and RM13-9-000 29

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.
Docket Nos. RM12-1-000 and RM13-9-000 30

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 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 
Docket Nos. RM12-1-000 and RM13-9-000 31

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 reschedule 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 offpeak 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 
Docket Nos. RM12-1-000 and RM13-9-000 32

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.
Docket Nos. RM12-1-000 and RM13-9-000 33

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 
Docket Nos. RM12-1-000 and RM13-9-000 34

contingencies and are required to be addressed in transmission planning for any 

bulk electric equipment at demand levels for which the planned outages are 

performed.”39 The Commission further stated that it “understands that planned 

maintenance outages tend to be for a relatively short duration and are routinely 

planned at a time that provides favorable system conditions, i.e., off-peak 

conditions. Given that all transmission and generation facilities require 

maintenance at some point during their service lives, these ‘potential’ planned 

outages must be addressed, so long as their planned start times and durations may 

be anticipated as occurring for some period of time during the planning time

[horizon]” required in the TPL Reliability Standards.40

45. With regard to BPA’s comment, we disagree that planned outages of less 

than one year in duration should be addressed operationally by determining new 

operating limits and taking other actions to mitigate the planned outage. The 

Commission understands that some planned outages such as planned generation 

outages are known more than one year in advance.41 As a result, the Commission 

believes the planning time horizon of the TPL Reliability Standards offers more 

 39 North American Electric Reliability Corp., 131 FERC ¶ 61,068, at P 39

(2010) (approving interpretation of Reliability Standards TPL-002-0 and TPL003-0).

40 Id. P 39.

41 See, e.g., Commissioner-Led Reliability Technical Conference, Docket 

Nos. AD13-6-000, RC11-6-004, RR13-2-000, July 9, 2013, Volume I at 242. 
Docket Nos. RM12-1-000 and RM13-9-000 35

flexibility to assess planned maintenance outages than the 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 nearterm and long-term transmission planning horizons and, for the near-term horizon, 

requires annual assessments for years one through five. Accordingly, known 

planned facility outages (i.e. generation, transmission or protection system 

facilities) of less than six months should be addressed so long as their planned start 

times and durations may be anticipated as occurring for some period of time 

during the planning time horizon.

2. Violation Risk Factors 

a. Requirement R1 

NERC Petition

46. NERC assigned a “medium” violation risk factor (VRF) for proposed 

Requirement R1. NERC maintains that Requirements R1.3.5, R1.3.7, R1.3.8, and 

R1.3.9 of the currently-effective Reliability Standard carry a VRF of “medium” 

and are similar in purpose and effect to proposed Reliability Standard, 
Docket Nos. RM12-1-000 and RM13-9-000 36

Requirement R1 because they refer to planning models that include firm transfers, 

existing and planned facilities, and reactive power requirements.42 

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 

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

43 April 2012 NOPR, 139 FERC ¶ 61,059 at P 21.
Docket Nos. RM12-1-000 and RM13-9-000 37

Requirement R1 of proposed Reliability Standard carries a VRF of “medium” 

while Requirement R1 of the currently-effective standard carries a VRF of “high.” 

Comments

48. NERC states that Requirement R1 of the currently-effective standard 

directly relates to Requirement R2 of the proposed standard, which has a High 

VRF. NERC states that Requirement R1 of the proposed standard is a new 

requirement that addresses the models needed for planning assessments and 

therefore can have a different VRF. NERC states that while the accuracy of the 

transmission system model plays a key role in the TPL Reliability Standards, it is 

“a model, an approximation constructed and built with multiple entity inputs 

within a controlled process (e.g., Multiregional Model Working Group).”44 NERC 

states the base model in proposed Requirement R1 must be modified by adjusting 

load forecasts and generation dispatch to better assess the range of probable 

outcomes that the transmission system may experience for various contingency 

scenarios. 

49. ISO/RTOs state that proposed Requirement R1 relates to model 

maintenance, a necessary condition to being able to perform an assessment, which 

is a different matter from the current Requirement R1. According to ISO/RTOs 

Requirement R1 of the currently-effective standard, relating to performing an 

 44 NERC Comments at 8.
Docket Nos. RM12-1-000 and RM13-9-000 38

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.” 

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 

 45 EEI Comments at 5. 
Docket Nos. RM12-1-000 and RM13-9-000 39

that if the baseline studies established in Requirement R1 are not adhered to, faulty 

studies could result, possibly leading to misoperation of the system.

52. The Commission is not persuaded by NERC’s argument that Reliability 

Standard TPL-001-4, Requirement R1 warrants a medium VRF because the base 

model in Requirement R1 must be modified by adjusting load forecasts and 

generation dispatch for various contingency scenarios. Rather, the Commission 

finds that Requirement R1 and its sub-parts require system models to represent 

projected system conditions including items such as resources required for load, 

and real and reactive load forecasts, all of which “establishes Category P0 as the 

normal condition in Table 1.”46 Although the Commission agrees with NERC that 

the accuracy of the system model plays a key role in the TPL Reliability Standards 

and that a system model is “a model, an approximation constructed and built with 

multiple entity inputs within a controlled process,” the Commission finds that the 

system model of Requirement R1 establishes a baseline (Category P0) for which 

all other studies are based and if not adhered to, faulty studies could result, 

possibly leading to misoperation of the system. 

53. Further, the Commission disagrees with ISO/RTOs that proposed 

Requirement R1 is a different matter from the current Requirement R1. The 

Commission stated in the April 2012 NOPR that Requirement R1 of the Version 0 

 46 NERC’s February 2013 Petition, Exhibit A, TPL-001-4, Requirement R1.
Docket Nos. RM12-1-000 and RM13-9-000 40

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 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 R647 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 

 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. 
Docket Nos. RM12-1-000 and RM13-9-000 41

expected to adversely affect the electrical state or capability of the bulk electric 

system. 

NOPR Proposal

55. In the NOPR, the Commission recognized that documenting criteria or 

methodology is an administrative act but stated that defining the criteria or 

methodology to be used is not an administrative act. The Commission sought 

clarification why the VRF level assigned to Requirement R6 is “low” since it 

appears that Requirement R6 requires more than a purely administrative task. 

Comments

56. NERC agrees that proposed TPL-001-2 Requirement R6 is not strictly an 

administrative task, and therefore the VRF should be adjusted to medium. In its 

February 28, 2013 Petition, NERC revised the VRF for Reliability Standard TPL001-4, 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 
Docket Nos. RM12-1-000 and RM13-9-000 42

medium VRF. The Commission disagrees with commenters that TPL-001-4 

Reliability Standard, Requirement R6 is purely an administrative task of 

documentation of criteria and methodologies. Requirement R6 goes beyond 

documentation by requiring planners to apply engineering judgment and analysis 

to “define...the criteria or methodology used in the analysis to identify system 

instability for conditions such as cascading, voltage instability or uncontrolled 

islanding.”49 

3. Protection System Failures versus Relay Failures

NERC Petition

59. NERC’s proposal includes modifications to the planning contingency 

categories in Table 1. NERC explains that the modifications are intended to add 

clarity and consistency regarding the modeling of a delayed fault clearing in a 

planning study. NERC stated that the basic elements of any protection system 

design involve inputs to protective relays and outputs from protective relays and 

that reliability issues associated with improper clearing of a fault on the bulk 

electric system can result from the failure of hundreds of individual protection 

system components in a substation. According to NERC, while the population of 

components that could fail and result in improper clearing is large, the population 

can be reduced dramatically by eliminating those components which share failure 

 49 Proposed TPL-001-4 Reliability Standard, Requirement R6.
Docket Nos. RM12-1-000 and RM13-9-000 43

modes with other components. NERC stated that the critical components in 

protection systems are the protective relays themselves, and a failure of a nonredundant protective relay will often result in undesired consequences during a 

fault. According to NERC, other protection system components related to the 

protective relay could fail and lead to a bulk electric system issue, but the event 

that would be studied is identical, from both transient and steady state 

perspectives, to the event resulting from a protective relay failure if an adequate 

population of protective relays is considered.50

NOPR Proposal

60. In the April 2012 NOPR, the Commission expressed that, based on various 

protection system designs, the planner will have to choose which protection 

system component failure would have the most significant impact on the BulkPower 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 

 50 NERC’s October 2011 Petition at 48.

51 April 2012 NOPR, 139 FERC ¶ 61,059 at P 31.
Docket Nos. RM12-1-000 and RM13-9-000 44

the larger contingency and how the loss of protection system components that is

integral to multiple protection systems impacts reliability. 

Comments

61. NERC states that the proposed Reliability Standard addresses the existing 

ambiguity requiring a study of a stuck breaker or protection system failure by 

specifying that both a stuck breaker and protection system failure must be 

evaluated. NERC states that its solution ensures that simulations of both 

categories are performed, reducing the probability of multiple contingency events 

leading to cascading and uncontrolled islanding. Similarly, Hydro One and EEI 

contend that a planner does not need to choose which protection system 

component failure would have the most significant impact on the Bulk-Power 

System in the planning assessment. According to Hydro One, the contingencies 

stipulated in Table 1, P5 of the proposed TPL Standard are appropriate for the 

conditions and events to be assessed in the P5 groups which focus on the 

combination of a single line to ground fault coupled with delayed clearing that 

may be caused by a protection system failing to open to clear the fault. Hydro 

One also states that what causes the protection system to fail is irrelevant in the 

context of delayed clearing by the backup protection system to clear the fault. 

EEI expresses concern that expanding planning studies to include all manner of 

protection system failures could create a scenario where planners would have to 

conduct unlimited and unbounded studies.
Docket Nos. RM12-1-000 and RM13-9-000 45

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 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
Docket Nos. RM12-1-000 and RM13-9-000 46

would more appropriately be considered or included in the extreme events 

category.

65. ISO/RTOs agree that the range of potential assessments should be 

expanded to include all components of a protection system including instrument 

transformers, protective relays, auxiliary relays and communications systems for 

the purpose of category P-5 contingencies, but because these devices are often in 

series, consideration of all of these components will not necessarily have any 

significant impact on analyses. 

66. With regard to the question of how does the loss of a protection system 

component integral to multiple protection systems impact reliability, NERC states 

that the loss of a relay that is integral to multiple protection systems would require 

simulation of the full impact of that relay’s failure on the system for the event 

being studied under the category P5 planning event. With respect to whether there 

is a reliability concern regarding single points of failure on protection systems, 

NERC indicates that it has a project underway to assess that question.52

67. Hydro One views the avoidance of having single component failure 

affecting more than one protection system as a protection system design issue. 

Hydro One states that some regional reliability organizations have in place criteria 

 52 NERC Comments at 10. 
Docket Nos. RM12-1-000 and RM13-9-000 47

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 StandardTPL-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 
Docket Nos. RM12-1-000 and RM13-9-000 48

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

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 

 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.
Docket Nos. RM12-1-000 and RM13-9-000 49

systems.55 According to NERC, these requirements ensure that, for a protection 

system designed “to remove multiple Elements from service for an event that the 

simulation will be run with all of those Elements removed from service.”56 In the 

NOPR, the Commission observed that these provisions do not explicitly refer to 

“backup or redundant systems” as in the currently-effective Reliability Standards 

and sought clarification whether the proposal includes backup and redundant 

protection systems. 

Comments

71. NERC clarifies that proposed Requirement R3, Part 3.3.1 and Requirement 

R4, Part 4.3.1 “require the consideration of all protection systems that are relevant 

to the contingency studied,” which includes “backup and redundant systems.”

57

EEI believes that the language is sufficiently clear to ensure a common 

understanding that backup and redundant protection system impacts needed to be 

studied regardless of whether the specific words as found in the currently active 

standard were used. ISO/RTOs and MISO believe that if a protection system is 

not fully redundant, contingencies should be studied to simulate both delayed 

clearing and operation of remote backup protection to trip additional facilities 

 55 NERC’s October 2011 Petition at 20.

56 Id.

57 NERC Comments at 11. 
Docket Nos. RM12-1-000 and RM13-9-000 50

when required. MISO states that if a protection system is fully redundant, that is, 

if a single failure of any component in the protection system (other than monitored 

DC voltage) would not result in delayed or failed tripping it should not be 

necessary to analyze the redundant protection system failure.

Commission Determination

72. The Commission agrees with NERC and finds that Requirement R3, Part 

3.3.1 and Requirement R4, Part 4.3.1 include the assessments of backup protection 

systems. The Commission 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. 

5. 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.
Docket Nos. RM12-1-000 and RM13-9-000 51

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-toground 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 
Docket Nos. RM12-1-000 and RM13-9-000 52

(e) controlled load interruption, dynamic load models and proxies to simulate 

cascade.

59 

77. The Commission is satisfied and agrees with the comments submitted by 

NERC, EEI and ISO/RTO on issues regarding controlled load interruption (i.e., 

third parties must have the same non-consequential load loss options as available 

to the planner), dynamic load models (i.e., documentation of dynamic load models 

used in system studies and the supporting rationale for their use is required) and 

proxies to simulate cascade (i.e., planners must define and document their criteria 

or methodology including proxies that are used in planning assessments due to 

modeling and simulation limitations). Below, we address in greater detail the

comments on peer review of planning assessments, spare equipment strategy, 

range of extreme events, and footnote ‘a.’

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 

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

60 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1750.
Docket Nos. RM12-1-000 and RM13-9-000 53

stated the proposed Reliability Standard does not include a “peer review” of 

planning assessments but instead includes an equally effective and efficient 

manner to provide for the appropriate sharing of information with neighboring 

systems in proposed Requirement R3, Part 3.4.1, Requirement R4, Part 4.4.1, and 

Requirement R8.61

79. In the April 2012 NOPR, the Commission sought clarification on how the 

NERC proposal ensures the early input of peers into the planning assessments or 

any type of coordination among peers will occur. The Commission also sought 

comment on whether and how neighboring systems can sufficiently evaluate and 

provide feedback to the planners on the development and result of assessments and 

whether it requires input on the comments to be included in the results or the 

development of the planning assessments.

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.

 61 NERC’s October 2011 Petition at 21.

 
Docket Nos. RM12-1-000 and RM13-9-000 54

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. BPA 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 
Docket Nos. RM12-1-000 and RM13-9-000 55

included in the planners’ steady state and stability analysis planning assessments.

62 

Coordination of contingency lists provides one aspect of early coordination among 

planners. 

84. We are satisfied with the explanation of NERC and EEI that TPL-001-4 

Reliability Standard, Requirement R8 allows planners to coordinate and distribute

conditions to adjacent planners as part of their planning assessment and to provide 

feedback to other planners. While we also agree with BPA that adjacent planners 

should be informed of and have a stake in the results of another planner’s 

assessment, we disagree with BPA’s characterization that a planner “should not be 

allowed to second guess” another planner’s studies or 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

 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. 

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.”
Docket Nos. RM12-1-000 and RM13-9-000 56

b. Spare Equipment Strategy

NOPR Proposal

85. In Order No. 693, the Commission directed NERC to develop a 

modification “to require assessments of outages of critical long lead-time 

equipment, consistent with the entity’s spare equipment strategy.”64 In response, 

NERC developed proposed Requirement 2, Part 2.1.5 which addresses steady state 

conditions to determine system response when equipment is unavailable for 

prolonged periods of time. 

86. In the NOPR, the Commission raised the concern that the proposed spare 

equipment strategy appears to be limited to “steady state analysis” and sought 

clarification why “stability analysis” conditions are not mentioned.

Comments

87. NERC, ISOs/RTOs, and EEI comment that the burden of additional 

stability analyses would not provide significant reliability benefits because 

stability analysis already required under “category P6” will produce more 

definitive tests of longer-term equipment unavailability. They also claim that any 

potential stability impacts related to an entity’s spare equipment strategy will be 

observed in the normal planning process driven by other requirements.

 64 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1786.
Docket Nos. RM12-1-000 and RM13-9-000 57

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., 
Docket Nos. RM12-1-000 and RM13-9-000 58

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.
Docket Nos. RM12-1-000 and RM13-9-000 59

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.
Docket Nos. RM12-1-000 and RM13-9-000 60

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 within the 

time duration applicable to facility ratings. Further, according to NERC, header 

note ‘f,’ which states applicable facility ratings shall not be exceeded, meets the 

Order No. 693 directive pertaining to footnote ‘a’ in the current standard. 

95. In the NOPR the Commission observed that the proposed standard applies 

header note ‘e’ to “Steady State and Stability,” while header note ‘f’ is excluded 

from “Stability” and only applies to “Steady State” studies. Accordingly, the 

 68 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1770.
Docket Nos. RM12-1-000 and RM13-9-000 61

Commission sought clarification regarding the rationale for excluding header note 

‘f’ from “Stability” studies. In addition, for Table 1, header notes ‘e’ and ‘f,’ the 

Commission sought comment on whether the normal facility ratings align with 

Reliability Standard FAC-008-1 and normal voltage ratings align with Reliability 

Standard VAR-001-1. Furthermore, the Commission sought clarification whether 

facility ratings used in planning assessments align with other reliability standards 

such as Reliability Standards NUC-001-2, BAL-001-0.1a and the PRC Reliability 

Standards for UFLS and UVLS. 

Comments

96. NERC states that it excluded header note ‘f’ from stability studies because 

facility ratings are defined for a finite period which may be between a few minutes 

and several hours, or longer. According to NERC, in stability studies the analysis 

is conducted over a few seconds and because facility ratings are established based

on the overheating of elements, the few seconds in the stability timeframe is not 

significant to the overheating of elements.69

97. ISO/RTO states that the observation of facility trip ratings (i.e., relay trip 

ratings) are valid in the stability simulation time frame, and should be considered 

if associated protective relay schemes are sensitive to power swings (e.g., 

impedance relays with no out-of step trip blocking for stable swings, etc.). 

 69 See also BPA Comments at 5, EEI Comments at 15 and ISO/RTOs 

Comments at 11. 
Docket Nos. RM12-1-000 and RM13-9-000 62

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 FAC008-1 “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 (realtime) standard to ensure voltage levels, reactive flows and reactive resources are 

monitored, controlled and maintained within the limits of the equipment.70

Commission Determination

100. The Commission is satisfied with commenters’ explanation and agrees that 

it is not necessary to include a requirement to observe thermal facility ratings in 

stability studies. The Commission agrees with ISO/RTO that facility trip ratings 

(i.e., relay trip ratings) are valid ratings in the stability simulation time frame, and 

 70 See NERC Comments at 16 and EEI Comments at 15.
Docket Nos. RM12-1-000 and RM13-9-000 63

should be considered in the planning assessment if associated protective relay 

schemes are sensitive to power swings (e.g., impedance relays with no out-of step 

trip blocking for stable swings). Further, the Commission accepts the explanation 

of NERC and others that facility ratings used in planning assessments are 

determined in accordance with Reliability Standard FAC-008-3,

71 which states 

that a “Facility Rating shall respect the most limiting applicable Equipment Rating 

of the individual equipment that comprises that Facility.”

C. Other Matters Raised by Commenters

101. Powerex states that additional clarification is needed with respect to 

Footnote 9 to Table 1 in order to provide clarity and ensure consistent 

interpretation as to when transmission planners may plan to curtail firm 

transmission service. Powerex is concerned that the revised TPL Standard may 

provide transmission planners with broad discretion to plan for the curtailment of 

firm transmission service without providing 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 redispatch” should be clarified as referring to a formal agreement between the 

transmission provider and a generation owner, located on the load side of a 

 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. 
Docket Nos. RM12-1-000 and RM13-9-000 64

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 redispatch 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.
Docket Nos. RM12-1-000 and RM13-9-000 65

III. Information Collection Statement

103. The Office of Management and Budget (OMB) regulations require that 

OMB approve certain reporting and recordkeeping (collections of information) 

imposed by an agency.73 Upon approval of a collection(s) of information, OMB 

will assign an OMB control number and expiration date. Respondents subject to 

the filing requirements of this rule will not be penalized for failing to respond to 

these collections of information unless the collections of information display a 

valid OMB control number. 

104. The Commission is submitting these reporting and recordkeeping 

requirements to OMB for its review and approval under section 3507(d) of 

Paperwork Reduction Act of 1995. The Commission solicited comments on the 

need for and the purpose of the information contained in Reliability Standard TPL001-4 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 

 73 5 CFR 1320.11.
Docket Nos. RM12-1-000 and RM13-9-000 66

proposed Reliability Standards. Our estimates are based on the NERC 

Compliance Registry as of February 28, 2013, which indicate that NERC has 

registered 183 transmission planners and planning coordinators. 

Improved 

Requirement74 Year

Number and 

Type of 

Entity75

(1)

Number of 

Annual 

Responses 

Per Entity 

(2)

Average

Number of 

Paperwork 

Hours per 

Response

(3)

Total 

Burden 

Hours

(1)*(2)*(3)

Identification of 

Joint 

Responsibilities 

and System 

Modeling 

Enhancements 76

Year 

1

183

Transmission 

Planners and 

Planning 

Coordinators

1 response 9 (5 

engineer 

hours and 4 

record 

keeping 

hours) 

1,647

hours 

Year 

2 and 

Year 

3

183

Transmission 

Planners and 

Planning 

Coordinators

1 response 5 (3

engineer 

hours and 2 

record 

keeping 

hours) 

915 hours 

New 

Assessments, 

Simulations, 

Studies, 

Year 

2 

183

Transmission 

Planners and 

Planning 

1 response 145 (84 

engineer 

hours, 61 

record 

26,535

hours

 74 Each requirement identifies a reliability improvement by proposed 

Reliability Standard TPL-001-4. 

75 NERC registered transmission planners and planning coordinators 

responsible for the improved requirement. Further, if a single entity is registered 

as both a transmission planner and planning coordinator, that entity is counted as 

one unique entity.

76 The Commission estimates a reduction in burden hours from year 1 to 

year 2 because year 1 represents a portion of one-time tasks not repeated in 

subsequent years.
Docket Nos. RM12-1-000 and RM13-9-000 67

Modeling 

Enhancements 

and associated 

Documentation77

Coordinators keeping 

hours) 

Year 

3

183

Transmission 

Planners and 

Planning 

Coordinators

1 response 84 (45 

engineer 

hours, 39

record 

keeping 

hours) 

15,372

hours 

Attachment 1 

stakeholder 

process 

Year 

3

1 

Transmission 

Planner and 

Planning 

Coordinator

12 

responses 

to 

Attachment 

1, sections 

I and II 

63 (40 

engineer 

hours, 17 

record 

keeping 

hours, 6 

legal hours)

756 hours 

Year 

3

1 

Transmission 

Planner and 

Planning 

Coordinator

4 responses 

to 

Attachment 

1, Sections 

I, II, and 

III 

68 (40 

engineer 

hours, 20 

record 

keeping 

hours, 8 

legal hours)

272 hours 

Costs to Comply with Paperwork Requirements:

• Year 1: $77,592.

• Year 2: $1,312,659. 

• Year 3 and ongoing: $820,149.

 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.
Docket Nos. RM12-1-000 and RM13-9-000 68

106. Year 1 costs include the implementation of those improved requirements 

that become effective on the first day of the first calendar quarter, 12 months after 

applicable regulatory approval, which include requirements such as coordination 

between entities and incremental system modeling enhancements. Year 2 costs 

include a portion of year 1 reoccurring costs plus the implementation of the 

remaining improved requirements that become effective on the first day of the first 

calendar quarter, 24 months after applicable regulatory approval, which include 

requirements such as sensitivity studies for steady state and stability analysis, 

implementation of a spare equipment strategy, short circuit studies, an expansion 

of contingencies and extreme events, and all associated system modeling 

enhancements and documentation. Year 3 costs include a portion of year 2 

reoccurring costs plus an estimated cost for Attachment 1 stakeholder process, if 

needed. 

107. For the burden categories above, the loaded (salary plus benefits) costs are: 

$60/hour for an engineer; $31/hour for recordkeeping; and $128/hour for legal.78 

The estimated breakdown of annual cost is as follows:

 78 Labor rates from Bureau of Labor Statistics (BLS) 

(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).
Docket Nos. RM12-1-000 and RM13-9-000 69

• Year 1

o Identification of Joint Responsibilities and System Modeling 

Enhancements: 183 entities * [(5 hours/response * $60/hour) + 

(4 hours/response * $31/hour)] = $77,592.

• Year 2

o Identification of Joint Responsibilities and System Modeling 

Enhancements: 183 entities * [(3 hours/response * $60/hour) + 

o (2 hours/response * $31/hour)] = $44,286. 

o 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

o Identification of Joint Responsibilities and System Modeling 

Enhancements: 183 entities * [(3 hours/response * $60/hour) + 

o (2 hours/response * $31/hour)] = $44,286.

o New Assessments, Simulations, Studies, Modeling Enhancements 

and associated Documentation: 183 entities * [(45 hours/response 

* $60/hour) + (39 hours/response * $31/hour)] = $715,347.

o Implementation of footnote 12 and the stakeholder process: 

{12 responses * [(40 hours/response * $60/hour) + (17 

hours/response * $31/hour) + (6 hours/response * $128/hour)]} + {4 

responses * [(40 hours/response * $60/hr) + (20 hours/response * 

$31/hour) + (8 hours/response * $128/hour)]} = $60,516.
Docket Nos. RM12-1-000 and RM13-9-000 70

Title: 725N, Mandatory Reliability Standards: Reliability Standard TPL-001-4.

79

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 

 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.
Docket Nos. RM12-1-000 and RM13-9-000 71

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, e-mail: 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 e-mail 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 

 80 Regulations Implementing the National Environmental Policy Act of 

1969, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).
Docket Nos. RM12-1-000 and RM13-9-000 72

the human environment. Included in the exclusion are rules that are clarifying, 

corrective, or procedural or that do not substantially change the effect of the 

regulations being amended.81 The actions proposed herein fall within this 

categorical exclusion in the Commission’s regulations.

V. Regulatory Flexibility Act Analysis

109. The Regulatory Flexibility Act of 1980 (RFA)82generally 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 

 81 18 CFR 380.4(a)(2)(ii).

82 5 U.S.C. 601-12.

83 13 CFR 121.101.

84 13 CFR 121.201, Sector 22, Utilities & n.1. 
Docket Nos. RM12-1-000 and RM13-9-000 73

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 285 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 

 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.
Docket Nos. RM12-1-000 and RM13-9-000 74

Standard TPL-001-4 will not have a significant economic impact on a substantial 

number of small entities. Accordingly, no regulatory flexibility analysis is 

required. 

VI. Document Availability

112. In addition to publishing the full text of this document in the Federal 

Register, the Commission provides all interested persons an opportunity to view 

and/or print the contents of this document via the Internet through FERC's Home 

Page (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 website 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. E-mail the Public Reference 

Room at public.referenceroom@ferc.gov.
Docket Nos. RM12-1-000 and RM13-9-000 75

VII. Effective Date and Congressional Notification

115. These regulations are effective [insert date 60 days from publication in 

Federal Register]. 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.

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.