153 FERC ¶ 61,178

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 40

[Docket No. RM15-16-000, Order No. 817]

Transmission Operations Reliability Standards and

Interconnection Reliability Operations and Coordination Reliability Standards

(Issued November 19, 2015)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

SUMMARY: The Commission approves revisions to the Transmission Operations and 

Interconnection Reliability Operations and Coordination Reliability Standards, developed 

by the North American Electric Reliability Corporation, which the Commission has 

certified as the Electric Reliability Organization responsible for developing and enforcing 

mandatory Reliability Standards. The Commission also directs NERC to make three 

modifications to the standards within 18 months of the effective date of the final rule. 

EFFECTIVE DATE: This rule will become effective [60 days after publication in the 

FEDERAL REGISTER].
Docket No. RM15-16-000 - 2 -

FOR FURTHER INFORMATION CONTACT:

Robert T. Stroh (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

Telephone: (202) 502-8473

Robert.Stroh@ferc.gov

Eugene Blick (Technical Information)

Office of Electric Reliability

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

Telephone: (301) 665-1759

Eugene.Blick@ferc.gov

Darrell G. Piatt, PE (Technical Information)

Office of Electric Reliability

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

Telephone: (205) 332-3792

Darrell.Piatt@ferc.gov

SUPPLEMENTARY INFORMATION:
153 FERC ¶ 61,178

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Cheryl A. LaFleur, Tony Clark,

 and Colette D. Honorable.

Transmission Operations Reliability Standards and 

Interconnection Reliability Operations and Coordination 

Reliability Standards

Docket No. RM15-16-000

ORDER NO. 817

FINAL RULE

(Issued November 19, 2015)

1. Pursuant to section 215 of the Federal Power Act (FPA),1 the Commission

approves revisions to the Transmission Operations (TOP) and Interconnection Reliability 

Operations and Coordination (IRO) Reliability Standards, developed by the North 

American Electric Reliability Corporation (NERC), the Commission-certified Electric 

Reliability Organization (ERO). The TOP and IRO Reliability Standards improve on the 

currently-effective standards by providing a more precise set of Reliability Standards 

addressing operating responsibilities and improving the delineation of responsibilities 

between applicable entities. The revised TOP Reliability Standards eliminate gaps and 

ambiguities in the currently-effective TOP requirements and improve efficiency by 

 1 16 U.S.C. 824o (2012). 
Docket No. RM15-16-000 - 2 -

incorporating the necessary requirements from the eight currently-effective TOP 

Reliability Standards into three comprehensive Reliability Standards. Further, the 

standards clarify and improve upon the currently-effective TOP and IRO Reliability 

Standards by designating requirements in the proposed standards that apply to 

transmission operators for the TOP standards and reliability coordinators for the IRO 

standards. Thus, we conclude that there are benefits to clarifying and bringing 

efficiencies to the TOP and IRO Reliability Standards, consistent with the Commission’s 

policy promoting increased efficiencies in Reliability Standards and reducing 

requirements that are either redundant with other currently-effective requirements or have 

little reliability benefit.

2

2. The Commission also finds that NERC has adequately addressed the concerns 

raised by the Commission in the Notice of Proposed Rulemaking issued in November

2013 concerning the proposed treatment of system operating limits (SOLs) and 

interconnection reliability operating limits (IROLs) and concerns about outage 

coordination.3 Further, the Commission approves the definitions for operational 

 2

 Electric Reliability Organization Proposal to Retire Requirements in Reliability 

Standards, Order No. 788, 145 FERC ¶ 61,147 (2013). 

3 Monitoring System Conditions - Transmission Operations Reliability Standard, 

Transmission Operations Reliability Standards, Interconnection Reliability Operations 

and Coordination Reliability Standards, Notice of Proposed Rulemaking, 145 FERC 

¶ 61,158 (2013) (Remand NOPR). Concurrent with filing the proposed TOP/IRO 

standards in the immediate proceeding, NERC submitted a motion to withdraw the earlier 

petition that was the subject of the Remand NOPR. No protests to the motion were filed 

and the petition was withdrawn pursuant to 18 CFR 385.216(b).
Docket No. RM15-16-000 - 3 -

planning analysis and real-time assessment, the implementation plans and the violation 

severity level and violation risk factor assignments. However, the Commission directs 

NERC to make three modifications to the standards as discussed below within 18 months 

of the effective date of this Final Rule. 

3. We also address below the four issues for which we sought clarifying comments in 

the June 18, 2015, Notice of Proposed Rulemaking (NOPR) proposing to approve the 

TOP and IRO Reliability Standards: (A) possible inconsistencies in identifying IROLs; 

(B) monitoring of non-bulk electric system facilities; (C) removal of the load-serving 

entity as an applicable entity for proposed Reliability Standard TOP-001-3; and (D) data 

exchange capabilities. In addition we address other issues raised by commenters. 

I. Background

A. Regulatory Background

4. Section 215 of the FPA requires a Commission-certified ERO to develop 

mandatory and enforceable Reliability Standards, subject to Commission review and 

approval.4

 Once approved, the Reliability Standards may be enforced by the ERO 

 4 16 U.S.C. 824o(c) and (d). 
Docket No. RM15-16-000 - 4 -

subject to Commission oversight, or by the Commission independently.5

 In 2006, the 

Commission certified NERC as the ERO pursuant to FPA section 215.6

5. The Commission approved the initial TOP and IRO Reliability Standards in 

Order No. 693.7

 On April 16, 2013, in Docket No. RM13-14-000, NERC submitted 

for Commission approval three revised TOP Reliability Standards to replace the 

eight currently-effective TOP standards.8 Additionally, on April 16, 2013, in Docket 

No. RM13-15-000, NERC submitted for Commission approval four revised IRO 

Reliability Standards to replace six currently-effective IRO Reliability Standards. On 

November 21, 2013, the Commission issued the Remand NOPR in which the 

Commission expressed concern that NERC had “removed critical reliability aspects that 

are included in the currently-effective standards without adequately addressing these 

 5 See id. 16 U.S.C. 824o(e). 

6 North American Electric Reliability Corp., 116 FERC ¶ 61,062, order on 

reh’g and compliance, 117 FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa Inc. v. FERC, 

564 F.3d 1342 (D.C. Cir. 2009). 

7 See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 

FERC Stats. & Regs. ¶ 31,242, at P 508, order on reh’g, Order No. 693-A, 120 FERC 

¶ 61,053 (2007). In addition, in Order No. 748, the Commission approved revisions to 

the IRO Reliability Standards. Mandatory Reliability Standards for Interconnection 

Reliability Operating Limits, Order No. 748, 134 FERC ¶ 61,213 (2011).

8 On April 5, 2013, in Docket No. RM13-12-000, NERC proposed revisions to 

Reliability Standard TOP-006-3 to clarify that transmission operators are responsible for 

monitoring and reporting available transmission resources and that balancing authorities 

are responsible for monitoring and reporting available generation resources.
Docket No. RM15-16-000 - 5 -

aspects in the proposed standards.”9

 The Commission identified two main concerns and 

asked for clarification and comment on a number of other issues. Among other things, 

the Commission expressed concern that the proposed TOP Reliability Standards did not 

require transmission operators to plan and operate within all SOLs, which is a 

requirement in the currently-effective standards. In addition, the Commission expressed 

concern that the proposed IRO Reliability Standards did not require outage coordination.

B. NERC Petition

6. On March 18, 2015, NERC filed a petition with the Commission for approval of 

the proposed TOP and IRO Reliability Standards.10 As explained in the Petition, the 

proposed Reliability Standards consolidate many of the currently-effective TOP and IRO 

Reliability Standards and also replace the TOP and IRO Reliability Standards that were 

the subject of the Remand NOPR. NERC stated that the proposed Reliability Standards 

include improvements over the currently-effective TOP and IRO Reliability Standards in 

(1) operating within SOLs and IROLs; (2) outage coordination; (3) situational awareness; 

(4) improved clarity and content in foundational definitions; and (5) requirements for 

operational reliability data. NERC stated that the proposed TOP and IRO Reliability 

Standards address outstanding Commission directives relevant to the proposed TOP and 

 9 Remand NOPR, 145 FERC ¶ 61,158 at P 4. 

10 The TOP and IRO Reliability Standards are not attached to the Final Rule. The 

complete text of the Reliability Standards is available on the Commission’s eLibrary 

document retrieval system in Docket No. RM15-16 and is posted on the ERO’s web site, 

available at: http://www.nerc.com.
Docket No. RM15-16-000 - 6 -

IRO Reliability Standards. NERC stated that the proposed Reliability Standards provide 

a comprehensive framework for reliable operations, with important improvements to 

ensure the bulk electric system is operated within pre-established limits while enhancing 

situational awareness and strengthening operations planning. NERC explained that the 

proposed Reliability Standards establish or revise requirements for operations planning, 

system monitoring, real-time actions, coordination between applicable entities, and 

operational reliability data. NERC contended that the proposed Reliability Standards 

help to ensure that reliability coordinators and transmission operators work together, and 

with other functional entities, to operate the bulk electric system within SOLs and 

IROLs.11 NERC also provided explanations of how the proposed Reliability Standards 

address the reliability issues identified in the report on the Arizona-Southern California 

Outages on September 8, 2011, Causes and Recommendations (“2011 Southwest Outage 

Blackout Report”). 

7. NERC proposed three TOP Reliability Standards to replace the existing suite of 

TOP standards. The proposed TOP Reliability Standards generally address real-time 

operations and planning for next-day operations, and apply primarily to the 

responsibilities and authorities of transmission operators, with certain requirements 

 11 The NERC Glossary of Terms defines IROL as “[a] System Operating Limit 

that, if violated, could lead to instability, uncontrolled separation, or Cascading outages 

that adversely impact the reliability of the Bulk Electric System.” In turn, NERC defines 

SOL as “[t]he value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the 

most limiting of the prescribed operating criteria for a specified system configuration to 

ensure operation within acceptable reliability criteria....”
Docket No. RM15-16-000 - 7 -

applying to the roles and responsibilities of the balancing authority. Among other things, 

NERC stated that the proposed revisions to the TOP Reliability Standards help ensure 

that transmission operators plan and operate within all SOLs. The proposed IRO 

Reliability Standards, which complement the proposed TOP Standards, are designed to 

ensure that the bulk electric system is planned and operated in a coordinated manner to 

perform reliably under normal and abnormal conditions. The proposed IRO Reliability 

Standards set forth the responsibility and authority of reliability coordinators to provide 

for reliable operations. NERC stated that, in the proposed IRO Reliability Standards,

reliability coordinators must continue to monitor SOLs in addition to their obligation in 

the currently effective Reliability Standards to monitor and analyze IROLs. These 

obligations require reliability coordinators to have the wide-area view necessary for 

situational awareness and provide them the ability to respond to system conditions that 

have the potential to negatively affect reliable operations.

8. NERC also proposed revised definitions for “operational planning analysis” and 

“real-time assessment.” For all standards except proposed Reliability Standards TOP003-3 and IRO-010-2, NERC proposed the effective date to be the first day of the first 

calendar quarter twelve months after Commission approval. According to NERC’s 

implementation plan, for proposed TOP-003-3, all requirements except Requirement R5

will become effective on the first day of the first calendar quarter nine months after the 

date that the standard is approved. For proposed IRO-010-2, Requirements R1 and R2 

would become effective on the first day of the first calendar quarter that is nine months 

after the date that the standard is approved. Proposed TOP-003-3, Requirement R5 and 
Docket No. RM15-16-000 - 8 -

IRO-010-2, Requirement R3 would become effective on the first day of the first calendar 

quarter twelve months after the date that the standard is approved. The reason for the 

difference in effective dates for proposed TOP-003-3 and IRO-010-2 is to allow 

applicable entities to have time to properly respond to the data specification requests

from their reliability coordinators, transmission operators, and/or balancing authorities. 

C. Notice of Proposed Rulemaking

9. On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking 

proposing to approve the TOP and IRO Reliability Standards pursuant to FPA 

section 215(d)(2), along with the two new definitions referenced in the proposed 

standards, the assigned violation risk factors and violation severity levels, and the 

proposed implementation plan for each standard.

12

10. In the NOPR, the Commission explained that the proposed TOP and IRO 

Reliability Standards improve on the currently-effective standards by providing a more 

precise set of Reliability Standards addressing operating responsibilities and improving 

the delineation of responsibilities between applicable entities. The Commission also 

proposed to find that NERC has adequately addressed the concerns raised by the Remand 

NOPR issued in November 2013. 

 12 Transmission Operations Reliability Standards and Interconnection Reliability 

Operations and Coordination Reliability Standards, 151 FERC ¶ 61,236 (2015) (NOPR). 
Docket No. RM15-16-000 - 9 -

11. In the NOPR, the Commission also discussed the following specific matters and 

asked for further comment: (A) possible inconsistencies in identifying IROLs; 

(B) monitoring of non-bulk electric system facilities; (C) removal of the load-serving 

entity as an applicable entity for proposed Reliability Standard TOP-001-3; and (D) data 

exchange capabilities. 

12. Timely comments on the NOPR were filed by: NERC; Arizona Public Service 

Company (APS), Bonneville Power Administration (BPA), Dominion Resources 

Services, Inc. (Dominion), the Edison Electric Institute (EEI); Electric Reliability 

Council of Texas, Inc. (ERCOT), Independent Electricity System Operator (IESO), 

ISO/RTOs,13 International Transmission Company (ITC); Midcontinent Independent 

System Operator, Inc., Northern Indiana Public Service Company (NIPSCO), Occidental 

Energy Ventures, LLC (Occidental), Peak Reliability (Peak), and Transmission Access 

Policy Study Group (TAPS). 

II. Discussion

13. Pursuant to section 215(d) of the FPA, we adopt our NOPR proposal and approve 

NERC’s revisions to the TOP and IRO Reliability Standards, including the associated 

definitions, violation risk factors, violation severity levels, and implementation plans, as 

just, reasonable, not unduly discriminatory or preferential and in the public interest. We 

 13 ISO/RTOs include Independent Electricity System Operator, ISO New England 

Inc., Midcontinent Independent System Operator, New York Independent System 

Operator, Inc., PJM Interconnection LLC, and Southwest Power Pool, Inc. 
Docket No. RM15-16-000 - 10 -

note that all of the commenters that address the matter support, or do not oppose, 

approval of the revised suite of TOP and IRO Reliability Standards. We determine that 

NERC’s approach of consolidating requirements and removing redundancies generally 

has merit and is consistent with Commission policy promoting increased efficiencies in 

Reliability Standards and reducing requirements that are either redundant with other 

currently-effective requirements or have little reliability benefit.14

14. We also determine that the proposed TOP and IRO Reliability Standards should

improve reliability by defining an appropriate division of responsibilities between 

reliability coordinators and transmission operators.15 The proposed TOP Reliability 

Standards will eliminate multiple TOP standards, resulting in a more concise set of 

standards, reducing redundancy and more clearly delineating responsibilities between 

applicable entities. In addition, we find that the proposed Reliability Standards provide a 

comprehensive framework as well as important improvements to ensure that the bulk 

electric system is operated within pre-established limits while enhancing situational 

awareness and strengthening operations planning. The TOP and IRO Reliability 

Standards address the coordinated efforts to plan and reliably operate the bulk electric 

system under both normal and abnormal conditions. 

 14 See Order No. 788, 145 FERC ¶ 61,147. 

15 See, e.g., Order No. 748, 134 FERC ¶ 61,213, at PP 39-40. 
Docket No. RM15-16-000 - 11 -

15. In the NOPR, the Commission proposed to find that NERC adequately addressed 

the concerns raised by the Commission in the Remand NOPR with respect to (1) the 

treatment of SOLs in the proposed TOP Reliability Standards, and (2) the IRO standards 

regarding planned outage coordination, both of which we address below. 

Operational Responsibilities and Actions of SOLs and IROLs

16. In the Remand NOPR, the Commission expressed concern that the initially 

proposed (now withdrawn) TOP standards did not have a requirement for transmission 

operators to plan and operate within all SOLs. The Commission finds that the TOP 

Reliability Standards that NERC subsequently proposed address the Commission’s 

Remand NOPR concerns by requiring transmission operators to plan and operate within 

all SOLs, and to monitor and assess SOL conditions within and outside a transmission 

operator’s area. Further, the TOP/IRO Standards approved herein address the possibility 

that additional SOLs could develop or occur in the same-day or real-time operational 

time horizon and, therefore, would pose an operational risk to the interconnected 

transmission network if not addressed. Likewise, the Reliability Standards give 

reliability coordinators the authority to direct actions to prevent or mitigate instances of 

exceeding IROLs because the primary decision-making authority for mitigating IROL 

exceedances is assigned to reliability coordinators while transmission operators have the 

primary responsibility for mitigating SOL exceedances.16 

 16 See Remand NOPR, 145 FERC ¶ 61,158 at P 85. Further, currently-effective 

Reliability Standard IRO-009-1, Requirement R4 states that “[w]hen actual system 

(continued ...)
Docket No. RM15-16-000 - 12 -

17. Furthermore, the revised definitions of operational planning analysis and real-time 

assessment are critical components of the proposed TOP and IRO Reliability Standards 

and, together with the definitions of SOLs, IROLs and operating plans, work to ensure 

that reliability coordinators, transmission operators and balancing authorities plan and 

operate the bulk electric system within all SOLs and IROLs to prevent instability, 

uncontrolled separation, or cascading. In addition, the revised definitions of operational 

planning analysis and real-time assessment address other concerns raised in the Remand 

NOPR as well as multiple recommendations in the 2011 Southwest Outage Blackout 

Report.

17 

Outage Coordination

18. In the NOPR, the Commission explained that NERC had addressed concerns 

raised in the Remand NOPR with respect to the IRO standards regarding planned outage 

coordination. In the Remand NOPR, the Commission expressed concern with NERC’s 

proposal because Reliability Standards IRO-008-1, Requirement R3 and IRO-010-1a 

(subjects of the proposed remand and now withdrawn by NERC) did not require the 

 

conditions show that there is an instance of exceeding an IROL in its Reliability 

Coordinator Area, the Reliability Coordinator shall, without delay, act or direct others to 

act to mitigate the magnitude and duration of the instance of exceeding that IROL within 

the IROL’s Tv.”

17 NERC Petition at 17-18.
Docket No. RM15-16-000 - 13 -

coordination of outages, noting that outage coordination is a critical reliability function 

that should be performed by the reliability coordinator.18 

19. In the NOPR, the Commission noted that Reliability Standard IRO-017-1, 

Requirement R1 requires each reliability coordinator to develop, implement and maintain 

an outage coordination process for generation and transmission outages within its 

reliability coordinator area. Additionally, Reliability Standard IRO-014-3, Requirement 

R1, Part 1.4 requires reliability coordinators to include the exchange of planned and 

unplanned outage information to support operational planning analyses and real-time 

assessments in the operating procedures, processes, and plans for activities that require 

coordination with adjacent reliability coordinators. We believe that these proposed 

standards adequately address our concerns with respect to outage coordination as outlined 

in the Remand NOPR. However, as we discuss below we direct NERC to modify the 

standards to include transmission operator monitoring of non-BES facilities, and to 

specify that data exchange capabilities include redundancy and diverse routing; as well as 

testing of the alternate or less frequently used data exchange capability, within 18 months 

of the effective date of this Final Rule. 

20. Below we discuss the following matters: (A) possible inconsistencies of 

identifying IROLs; (B) monitoring of non-bulk electric system facilities; (C) removal of 

 18 Remand NOPR, 145 FERC ¶ 61,158 at P 90. 
Docket No. RM15-16-000 - 14 -

the load-serving entity function from proposed Reliability Standard TOP-001-3; (D) data 

exchange capabilities, and (E) other issues raised by commenters.

A. Possible Inconsistences in IROLs Across Regions

NOPR

21. In the NOPR, the Commission noted that in Exhibit E (SOL White Paper) of 

NERC’s petition, NERC stated that, with regard to the SOL concept, the SOL White 

Paper brings “clarity and consistency to the notion of establishing SOLs, exceeding 

SOLs, and implementing Operating Plans to mitigate SOL exceedances.”19 The 

Commission further noted that IROLs, as defined by NERC, are a subset of SOLs that, if

violated, could lead to instability, uncontrolled separation, or cascading outages that 

adversely impact the reliability of the bulk electric system. The Commission agreed with 

NERC that clarity and consistency are important with respect to establishing and 

implementing operating plans to mitigate SOL and IROL exceedances. However, the 

Commission noted that NERC, in its 2015 State of Reliability report, had stated that the 

Western Interconnection reliability coordinator definition of an IROL has additional 

criteria that may not exist in other reliability coordinator areas.20 The Commission stated 

 19 NERC Petition, Exhibit E, “White Paper on System Operating Limit Definition 

and Exceedance Clarification” at 1.

20 NOPR, 151 FERC ¶ 61,236 at P 51, citing NERC 2015 State of Reliability 

report at 44, available at www.nerc.com. See also WECC Reliability Coordination 

System Operating Limits Methodology for the Operations Horizon, Rev. 7.0 (effective 

March 3, 2014) at 18 (stating that “SOLs qualify as IROLs when ... studies indicate that 

instability, Cascading, or uncontrolled separation may occur resulting in uncontrolled 

(continued ...)
Docket No. RM15-16-000 - 15 -

that it is unclear whether NERC regions apply a consistent approach to identifying 

IROLs. The Commission, therefore, sought comment on (1) identification of all regional 

differences or variances in the formulation of IROLs; (2) the potential reliability impacts 

of such differences or variations, and (3) the value of providing a uniform approach or 

methodology to defining and identifying IROLs.

Comments

22. Commenters generally agree that there are variations in IROL formulation but 

maintain that the flexibility is needed due to different system topographies and 

configurations. EEI and other commenters, also suggest that, to the extent there are 

variations, such resolution should be addressed by NERC and the Regional Entities in a 

standard development process rather than by a Commission directive. NERC requests 

that the Commission refrain from addressing these issues in this proceeding. NERC 

contends that the TOP and IRO Reliability Standards do not address the methods for the 

development and identification of SOLs and IROLs and that requirements governing the 

development and identification of SOLs and IROLs are included in the Facilities Design, 

Connections and Maintenance (FAC) Reliability Standards. NERC states that the current 

FAC Reliability Standards provide reliability coordinators flexibility in the manner in 

 

interruption of load equal to or greater than 1000 MW”), available at

https://www.wecc.biz/Reliability/PhaseII%20WECC%20RC%20SOL%20Methodology

%20FINAL.pdf.
Docket No. RM15-16-000 - 16 -

which they identify IROLs.21 NERC adds that it recently initiated a standards 

development project (Project 2015-09 Establish and Communicate System Operating 

Limits) to evaluate and modify the FAC Reliability Standards that address the 

development and identification of SOLs and IROLs. NERC explains that the Project 

2015-09 standard drafting team will address the clarity and consistency of the 

requirements for establishing both SOLs and IROLs. According to NERC, it would be 

premature for NERC or the Commission to address issues regarding the identification of 

IROLs in this proceeding without the benefit of the complete analysis of the Project 

2015-09 standard drafting team. NERC commits to working with stakeholders and 

Commission staff during the Project 2015-09 standards development process to address 

the issues raised in the NOPR. 

23. ERCOT comments that the existing Reliability Standards provide a consistent but 

flexible structure for IROL identification that provides maximum benefit to 

interconnected transmission network. ERCOT believes that the Reliability Standards 

should continue to permit regional variations that will encourage flexibility for 

consideration of system-specific topology and characteristics as well as the application of 

operational experience and engineering judgment. ERCOT states that regional 

differences exist in terms of the specific processes and methodologies utilized to identify 

IROLs. However, according to ERCOT, appropriate consistency in IROL identification 

 21 See also Peak Comments at 4-5. Peak points to Reliability Standards FAC-011-

2 and FAC-014-2 as support for regional variation in establishing IROLs. 
Docket No. RM15-16-000 - 17 -

is driven by the definition of an IROL, the Reliability Standards associated with the 

identification of SOLs, and the communication and coordination among responsible 

entities. Further, ERCOT argues that allowing regional IROL differences benefits the 

bulk electric system by allowing the entities with the most operating experience to 

recognize the topology and operating characteristics of their areas, and to incorporate 

their experience and judgment into IROL identification.

24. Peak supports allowing regions to vary in their interpretation and identification of 

IROLs based on the level of risk determined by that region, as long as that interpretation 

is transparent and consistent within that region. Peak understands the definition of IROL 

to recognize regional differences and variances in the formulation of IROLs. Peak 

contends that such regional variation is necessary due to certain physical system 

differences. Thus, according to Peak, a consistent approach from region to region is not 

required, and may not enhance the overall reliability of the system. Peak explains that, in

the Western United States, the evaluation of operating limits and stability must take into 

account the long transmission lines and greater distance between population centers, a 

situation quite different than the dense, interwoven systems found in much of the Eastern 

Interconnection. Peak adds that the Western Interconnection more frequently encounters 

localized instability because of the sparsity of the transmission system and the numerous 

small load centers supplied by few transmission lines, and these localized instances of 

instability have little to no impact on the overall reliability of the bulk electric system. 

Peak encourages the Commission to recognize that differences among the regions may 
Docket No. RM15-16-000 - 18 -

require flexibility to determine, through its SOL methodology, the extent and severity of 

instability and cascading that warrant the establishment of an IROL. 

25. While Peak supports retaining the flexibility of a region by region application of 

the IROL definition, Peak notes that the current definition is not without some confusing 

ambiguity in the application of IROL that should be addressed, including ambiguity and 

confusion around the term “instability,” the phrase “that adversely impact the reliability 

of the Bulk Electric System” and “cascading.” Peak suggests that one method to 

eliminate confusion on the definition and application of IROLs would be to expand 

NERC’s whitepaper to address concerns more specific to IROLs. Peak contends that 

further guidance from NERC in the whitepaper may remedy the confusion on the limits 

on the application of IROLs for widespread versus localized instability. 

26. Peak requests that, if the Commission or NERC determines that a one-size-fits all 

approach is necessary for the identification of IROLs and eliminates the current 

flexibility for regional differences, that the Commission recognizes the limitations this 

will place on reliability coordinators to evaluate the specific conditions within their 

reliability coordinator area. The Commission should require that any standardized 

application of the IROL definition would need to address specific thresholds and 

implementation triggers for IROLs based on the risk profile and challenges facing 

specific regions, to avoid the downfalls of inaccurate or overbroad application, as 

discussed above.
Docket No. RM15-16-000 - 19 -

Commission Determination

27. While it appears that regional discrepancies exist regarding the manner for 

calculating IROLs, we accept NERC’s explanation that this issue is more appropriately 

addressed in NERC’s Facilities Design, Connections and Maintenance or “FAC”

Reliability Standards. NERC indicates that an ongoing FAC-related standards 

development project - NERC Project 2015-09 (Establish and Communicate System 

Operating Limits) - will address the development and identification of SOLs and IROLs. 

We conclude that NERC’s explanation, that the Project 2015-09 standard drafting team 

will address the clarity and consistency of the requirements for establishing both SOLs 

and IROLs, is reasonable. Therefore, we will not direct further action on IROLs in the 

immediate TOP and IRO standard-related rulemaking. However, when this issue is 

considered in Project 2015-19, the specific regional difference of WECC’s 1,000 MW 

threshold in IROLs should be evaluated in light of the Commission’s directive in Order 

No. 802 (approving Reliability Standard CIP-014) to eliminate or clarify the 

“widespread” qualifier on “instability” as well as our statement in the Remand NOPR 

that “operators do not always foresee the consequences of exceeding such SOLs and thus 

cannot be sure of preventing harm to reliability.”22

 22 Physical Security Reliability Standard, Order No. 802, 149 FERC ¶ 61,140 

(2014) and Remand NOPR, 145 FERC ¶ 61,158 at P 52. See also FPA section 215(a)(4) 

defining Reliable Operation as “operating the elements of the bulk-power system within 

equipment and electric system thermal, voltage, and stability limits so that instability, 

uncontrolled separation, or cascading failures of such system will not occur as a result of 

(continued ...)
Docket No. RM15-16-000 - 20 -

B. Monitoring of Non-Bulk Electric System Facilities

NOPR

28. In the NOPR the Commission proposed to find that the proposed Reliability 

Standards adequately address the 2011 Southwest Outage Blackout Report 

recommendation regarding monitoring sub-100 kV facilities, primarily because of the 

responsibility of the reliability coordinator under proposed Reliability Standard IRO-002-

4, Requirement R3 to monitor non-bulk electric system facilities to the extent necessary. 

The Commission noted, however, that “the transmission operator may have a more 

granular perspective than the reliability coordinator of its necessary non-bulk electric 

system facilities to monitor,” and it is not clear whether or how the transmission operator 

would provide information to the reliability coordinator regarding which non-BES 

facilities should be monitored.23 The Commission sought comment on how NERC will 

ensure that the reliability coordinator will receive such information.

29. The Commission stated that including such non-bulk electric system facilities in 

the definition of bulk electric system through the NERC Rules of Procedure exception 

process could be an option to address any potential gaps for monitoring facilities but 

notes that there may be potential efficiencies gained by using a more expedited method to 

include non-bulk electric system facilities that requires monitoring. The Commission 

 

a sudden disturbance, including a cybersecurity incident, or unanticipated failure of 

system elements.”

23 NOPR, 151 FERC ¶ 61,236 at P 58. 
Docket No. RM15-16-000 - 21 -

sought comment on whether the BES exception process should be used exclusively in all 

cases. Alternatively, the Commission sought comment on whether this concern can be 

addressed through a review process of the transmission operators’ systems to determine if 

there are important non-bulk electric system facilities that require monitoring. 

Comments

30. Nearly all commenters support the Reliability Standards as proposed as sufficient 

for identifying and monitoring non-bulk electric system facilities, and do not support the 

alternatives offered by the Commission in the NOPR.24 NERC submits that the proposed 

data specification and collection Reliability Standards IRO-010-2 and TOP-003-3, in 

addition to the exceptions process will help ensure that the reliability coordinator can 

work with transmission operators, and other functional entities, to obtain sufficient 

information to identify the necessary non-bulk electric system facilities to monitor. In 

support, NERC points to Reliability Standard IRO-010-2, which provides a mechanism 

for the reliability coordinator to obtain the information and data it needs for reliable 

operations and to help prevent instability, uncontrolled separation, or cascading outages. 

Further, NERC cites Reliability Standard TOP-003-3, which allows transmission 

operators to obtain data on non-bulk electric system facilities, necessary to perform their 

operational planning analyses, real‐time monitoring, and real‐time assessments from 

applicable entities. NERC explains that any data that the transmission operator obtains 

 24 E.g. NERC, EEI, TAPS, Occidental, and NIPSCO. 
Docket No. RM15-16-000 - 22 -

regarding non-bulk electric system facilities under Reliability Standard TOP-003-3 can 

be passed on to the reliability coordinator pursuant to a request under proposed 

Reliability Standard IRO-010-2. Accordingly, NERC states that it would be premature 

to develop an alternative process before the data specification and bulk electric system

exception process are allowed to work. 

31. EEI states that this issue has been thoroughly studied by NERC through Project 

2010-17 Phase 2 (Revisions to the Definition of Bulk Electric System) that led to 

modification of the definition of bulk electric system. EEI believes that the current 

process provides all of the necessary tools and processes to ensure that insights by TOPs 

are fully captured and integrated into existing monitoring systems that would ensure that 

all non-BES elements that might impact BES reliability are fully monitored. EEI does 

not support the alternative process proposed by the Commission. EEI warns that an 

alternative, parallel review process of the transmission operators’ systems to determine if 

there are important non-bulk electric system facilities that require monitoring would 

either circumvent the revised bulk electric system definition process or arbitrarily impose 

NERC requirements (i.e., monitoring) onto non-bulk electric system elements. 

32. APS agrees with the Commission that there would be a reliability benefit for the 

reliability coordinator to be able to identify facilities within the transmission operators’ 

areas that may have a material impact on reliability. APS believes this benefit can be 

achieved using the method deployed in the Western Interconnection by the Western 

Electricity Coordinating Council (WECC). APS explains that the WECC planning 

coordination committee has published a bulk electric system inclusion guideline that 
Docket No. RM15-16-000 - 23 -

categorizes non-bulk electric system facilities that are to be identified by each planning 

authority and transmission planner when performing their system planning and operations 

reliability assessments, and the identified facilities are then reported to NERC. APS 

proposes a similar exception process be used in all cases. According to APS, each 

reliability coordinator would publish a guideline on how to identify non-bulk electric 

system facilities critical to reliability appropriate for their reliability coordinator area, and 

each planning coordinator and transmission planner would run studies according to the 

reliability coordinator guideline at least once every three years. 

33. ERCOT states that performance of sufficient studies and evaluations of reliability 

coordinator areas occurs in cooperation and coordination with associated transmission 

operators, rending an additional review process unnecessary. However, to avoid any 

potential gaps in monitoring non-bulk electric system facilities and ensure that existing 

agreements and monitoring processes are respected, ERCOT states that the Commission 

should direct NERC to modify the TOP and IRO Reliability Standards to refer not only to 

sub-100 kV facilities identified as part of the bulk electric system through the Rules of 

Procedure exception process, but also to other sub-100 kV facilities as requested or 

agreed by the responsible entities.25 ERCOT also states that because “non-bulk electric 

system facilities” fall outside the scope of the NERC Reliability Standards, use of this 

terminology should be avoided. ERCOT advocates for the Commission to permit 

 25 See also ISO/RTOs Comments at 3. 
Docket No. RM15-16-000 - 24 -

monitoring of other sub-100 kV facilities to be undertaken as agreed to between the 

reliability coordinator and the transmission operator. ERCOT and ISO/RTOs suggest 

that the phrase “non-BES facilities” in Reliability Standard IRO-002-4, Requirement R3 

should be replaced with “sub-100 kV facilities identified as part of the BES through the 

BES exception process or as otherwise agreed to between the Reliability Coordinator and 

Transmission Operator” and the phrase “non-BES data” in Reliability Standards IRO010-2 (Requirement R1.1) and TOP-003-3 (Requirement R1.1) should be replaced with 

“data from sub-100 kV facilities identified as part of the BES through the BES exception 

process, as otherwise requested by the Responsible Entity, or as agreed to between the 

Transmission Operator and the Responsible Entity.”26

34. ITC does not support the Commission’s proposal. ITC states that transmission 

operators are required to incorporate any non-bulk electric system data into operational 

planning analysis and real-time assessments and monitoring, which therefore requires 

transmission operators to regularly review their models to identify impacting non-bulk

electric system facilities. Conversely, ITC explains that conducting a one-time or 

periodic review and analysis of a transmission operator’s model ignores the fact that 

changes in system conditions can cause the list of impacting non-bulk electric system

facilities to change frequently. 

 26 See also ISO/RTOs Comments at 4-6. 
Docket No. RM15-16-000 - 25 -

Commission Determination

35. We agree with NERC, TAPS, and EEI that the BES exception process can be a 

mechanism for identifying non-BES facilities to be included in the BES definition.27 

Indeed, once a non-BES facility is included in the BES definition under the BES 

exception process, the “non-BES facility” becomes a BES “Facility” under TOP-001-3, 

Requirement R10, and real-time monitoring is required of “Facilities.”28 However, we 

are concerned that in some instances the absence of real-time monitoring of non-BES 

facilities by the transmission operator within and outside its TOP area as necessary for 

determining SOL exceedances in proposed TOP-001-3, Requirement R10 creates a 

reliability gap. As the 2011 Southwest Outage Report indicates, the Regional Entity 

“should lead other entities, including TOPs and BAs, to ensure that all facilities that can 

adversely impact BPS reliability are either designated as part of the BES or otherwise 

incorporated into planning and operations studies and actively monitored and alarmed in 

 27 NERC TOP/IRO Petition, Exh. G at 9 states in response to the 2011 Southwest 

Outage Recommendation #17, “If a non-BES facility impacts the BES, such as by 

contributing to an SOL or IROL, then the SDT expects that facility to be incorporated 

into the BES through the official BES Exception Process and it would be covered in

proposed TOP-001-3, Requirement R10, Parts 10.1 and 10.2 by use of the defined term 

‘Facilities.’”

28 NERC Glossary of Terms defines Facility as: “A set of electrical equipment that 

operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt 

compensator, transformer, etc.)”
Docket No. RM15-16-000 - 26 -

[real-time contingency analysis] systems.”29 Such monitoring of non-BES facilities 

could provide a “stop gap” during the period where a sub-100 kV facility undergoes 

analysis as a possible BES facility, allowing for monitoring in the interim until such time 

the non-bulk electric system facilities become “BES Facilities” or the transmission 

operator determines that a non-bulk electric system facility is no longer needed for 

monitoring to determine a system operating limit exceedance in its area.

30 We believe 

that the operational planning analyses and real-time assessments performed by the 

transmission operators as well as the reliability coordinators will serve as the basis for 

determining which “non-BES facilities” require monitoring to determine system 

operating limit and interconnection reliability operating limit exceedances. In addition, 

we believe that monitoring of certain non-BES facilities that are occasional system 

operating limit exceedance performers may not qualify as a candidate for inclusion in the 

 29 NOPR, 151 FERC ¶ 61,236 at P 55, citing Recommendation 17 of the 2011 

Southwest Outage Blackout Report (emphasis added).

30 NERC’s BES Frequently Asked Questions, Version 1.6, February 25, 2015, 

Section 5.6. “How long will the process take?” at page 14 states: “In general, assuming a 

complete application, no appeals, and taking the allotted time for each subtask, the 

process could take up to 11.5 months, but is anticipated to be shorter for less complicated 

Exception Requests. If the Exception Request is appealed to the NERC Board of 

Trustees Compliance Committee pursuant to Section 1703 of the NERC Rules of 

Procedure, the process could take an additional 8.5 months, totaling 20 months. This 

does not include timing related to an appeal to the applicable legal authority or 

Applicable Governmental Authority. A Regional Entity, upon consultation with NERC, 

may extend the time frame of the substantive review process....” 

http://www.nerc.com/pa/RAPA/BES%20DL/BES%20FAQs.pdf.
Docket No. RM15-16-000 - 27 -

BES definition, yet should be monitored for reliability purposes.

31 Accordingly, pursuant 

to section 215(d)(5) of the FPA, we direct NERC to revise Reliability Standard TOP-001-

3, Requirement R10 to require real-time monitoring of non-BES facilities. We believe 

this is best accomplished by adopting language similar to Reliability Standard IRO-002-

4, Requirement R3, which requires reliability coordinators to monitor non-bulk electric 

system facilities to the extent necessary. NERC can develop an equally efficient and 

effective alternative that addresses our concerns.

32

36. To be clear, we are not directing that all current “non-BES” facilities that a 

transmission operator considers worthy of monitoring also be included in the bulk electric 

system. We believe that such monitoring may result in some facilities becoming part of 

the bulk electric system through the exception process; however it is conceivable that 

others may remain non-BES because they are occasional system operating limit 

exceedance performers that may not qualify as a candidate for inclusion in the BES 

definition. 

 31 See, e.g., NERC TOP/IRO Petition at 18 and 27-28. 

32 Reliability Standard IRO-002-4, Requirement R3 states: Each Reliability 

Coordinator shall monitor Facilities, the status of Special Protection Systems, and nonBES facilities identified as necessary by the Reliability Coordinator, within its Reliability 

Coordinator Area and neighboring Reliability Coordinator Areas to identify any System 

Operating Limit exceedances and to determine any Interconnection Reliability Operating 

Limit exceedances within its Reliability Coordinator Area.
Docket No. RM15-16-000 - 28 -

C. Removal of Load-Serving Entity Function from TOP-001-3

NOPR

37. NERC proposed the removal of the load-serving entity function from proposed 

Reliability Standard, TOP-001-3, Requirements R3 through R6, as a recipient of an 

operating instruction from a transmission operator or balancing authority. NERC 

supplemented its initial petition with additional explanation for the removal of the loadserving entity function from proposed Reliability Standard TOP-001-3.33 NERC 

explained that the proposed standard gives transmission operators and balancing 

authorities the authority to direct the actions of certain other functional entities by issuing 

an operating instruction to maintain reliability during real-time operations. 

38. In the NOPR, the Commission noted that NERC was required to make a 

compliance filing in Docket No. RR15-4-000, regarding NERC’s Risk-Based 

Registration initiative, and that the Commission’s decision on that filing will guide any 

action in this proceeding. On March 19, 2015, the Commission approved, in part, 

NERC’s Risk-Based Registration initiative, but denied, without prejudice, NERC’s 

proposal to eliminate the load-serving entity function from the registry process, finding 

that NERC had not adequately justified its proposal.34 In doing so, the Commission 

 33 The Commission also notes that Reliability Standards TOP-003-3 and IRO-010-

2 also include “load-serving entity” as an applicable entity. 

34 North American Electric Reliability Corp. 150 FERC ¶ 61,213 (2015) 

(March 19 Order). 
Docket No. RM15-16-000 - 29 -

directed NERC to provide additional information to support this aspect of its proposal to 

address the Commission’s concerns. On July 17, 2015, NERC submitted a compliance 

filing in response to the March 19 Order. 

Comments

39. NERC states that while load-serving entities play a role in facilitating interruptible 

(or voluntary) load curtailments, that role is to simply communicate requests for 

voluntary load curtailments and does not necessitate requiring load-serving entities to 

comply with a transmission operator’s or balancing authority’s operating instructions 

issued pursuant to Reliability Standard TOP-001-3. In short, the load-serving entity’s 

role in carrying out interruptible load curtailment is not the type of activity that rises to 

the level of requiring an operating instruction. EEI and TAPS contend it is appropriate to 

omit the load-serving entity function from TOP-001-3 applicability. TAPS explains that 

because the load-serving entity function does not own or operate equipment, the loadserving entity function cannot curtail load or perform other corrective actions subject to 

reliability standards. Dominion asserts that a load-serving entity does not own or operate 

bulk electric system facilities or equipment or the facilities or equipment used to serve 

end-use customers and is not aware of any entity, registered solely as a load-serving 

entity, which is responsible for operating one or more elements or facilities. 

Commission Determination

40. In an October 15, 2015 order in Docket No. RR15-4-001, the Commission 

accepted a NERC compliance filing, finding that NERC complied with the March 17

Order with respect to providing additional information justifying the removal of the load-
Docket No. RM15-16-000 - 30 -

serving entity function.35 The Commission also found that NERC addressed the concerns 

expressed regarding an accurate estimate of the load-serving entities to be deregistered 

and the reliability impact of doing so, and how load data will continue to be available and 

reliability activities will continue to be performed even after load-serving entities would 

no longer be registered.36 Because the load-serving entity category is no longer a NERC 

registration function, no further action is required in this proceeding.

37 

D. Data Exchange Capabilities

41. The Commission approved Reliability Standards COM-001-2 (Communications) 

and COM-002-4 (Operating Personnel Communications Protocols) in Order No. 808, and 

noted that in the NOPR underlying that order (COM NOPR) it had raised concerns as to

whether Reliability Standard COM-001-2 addresses facilities that directly exchange or 

transfer data.38 In response to that concern in the COM NOPR, NERC clarified that 

Reliability Standard COM-001-2 did not need to include requirements regarding data 

exchange capability because such capability is covered under other existing and proposed 

 35 North American Electric Reliability Corp, 153 FERC ¶ 61,024 (2015).

36 Id.

37 In its response to comments in Docket No. RR15-4-000, NERC stated that, once 

the Commission approved the proposed deactivation of the load-serving entity 

registration function, it would make any needed changes to the Reliability Standards 

through the Reliability Standard Development Process. See January 26, 2016, NERC 

Motion to File Limited Answer at 6 in Docket No. RR15-4-000. 

38 See NOPR, 151 FERC ¶ 61,236 at P 67, citing Communications Reliability 

Standards, Order No. 808, 151 FERC ¶ 61,039 (2015).
Docket No. RM15-16-000 - 31 -

standards. Based on that explanation, the Commission decided not to make any 

determinations in Order No. 808 and stated that it would address the issue in this TOP 

and IRO rulemaking proceeding.39

NOPR

42. In the NOPR, the Commission stated that facilities for data exchange capabilities 

appear to be addressed in NERC’s TOP/IRO petition. However, the Commission sought 

additional explanation from NERC regarding how it addresses data exchange capabilities 

in the TOP and IRO Standards in the following areas: (a) redundancy and diverse 

routing; and (b) testing of the alternate or less frequently used data exchange capability.

1. Redundancy and Diverse Routing of Data Exchange Capabilities

NOPR

43. In the NOPR, the Commission agreed that proposed Reliability Standard TOP001-3, Requirements R19 and R20 require some form of “data exchange capabilities” for 

the transmission operator and balancing authority and that proposed Reliability Standard 

TOP-003-3 addresses the operational data itself needed by the transmission operator and 

balancing authority. In addition, the Commission agreed that Reliability Standard IRO002-4, Requirement R1 requires “data exchange capabilities” for the reliability 

coordinator and that proposed Reliability Standard IRO-010-2 addresses the operational 

data needed by the reliability coordinator and that proposed Reliability Standard IRO-

 39 Id. citing Order No. 808, 151 FERC ¶ 61,039 at P 54. 
Docket No. RM15-16-000 - 32 -

002-4 Requirement R4 requires a redundant infrastructure for system monitoring. 

However, the Commission was concerned that it is not clear whether redundancy and 

diverse routing of data exchange capabilities were adequately addressed in proposed 

Reliability Standards TOP-001-3 and IRO-002-4 for the reliability coordinator, 

transmission operator, and balancing authority and sought explanation or clarification on 

how the standards address redundancy and diverse routing or an equally effective 

alternative. The Commission also stated that, if NERC or others believe that redundancy 

and diverse routing are not addressed, they should address whether there are associated 

reliability risks of the interconnected transmission network for any failure of data 

exchange capabilities that are not redundant and diversely routed. 

Comments

44. NERC and EEI state that the requirements in the TOP and IRO Reliability 

Standards covering data exchange are results-based, articulating a performance objective 

without dictating the manner in which it is met. NERC adds that, in connection with their 

compliance monitoring activities, NERC and the Regional Entities will review whether 

applicable entities have met that objective, and will consider whether the applicable 

entity has redundancy and diverse routing, and whether the applicable entity tests these 

capabilities. EEI also argues that Reliability Standard EOP-008-1, Requirements R1, 

R1.2, R1.2.2, R7, and EOP-001-2.1b, Requirements R6 and R6.1 provide specific 

requirements for maintaining or specifying reliable back-up data exchange capability 

necessary to ensure BES Reliability and the testing of those capabilities. 
Docket No. RM15-16-000 - 33 -

45. ERCOT asserts that the Reliability Standards already appropriately provide for 

redundancy and diversity of routing of data exchange capabilities, as both the existing 

and proposed standards either explicitly or implicitly require responsible entities to 

ensure availability of data and data exchange capabilities. ERCOT states that, should the 

Commission seek to provide further clarification on this issue, such clarification should 

be consistent with existing explicit requirements regarding the redundancy of data 

exchange capabilities, such as Requirement R4 of Reliability Standard IRO-002-4.

46. ISOs/RTOs and ERCOT explain the suite of currently-effective standards and the 

proposed TOP and IRO standards establish performance-based requirements for 

reliability coordinators, balancing authorities, and transmission operators, that create the 

need for those entities to have diverse and redundantly routed data communication 

systems. In the event of a failure of data communications, ISOs/RTOs explain that the 

functional entity should be able to rely on the redundant and diversely routed voice 

capabilities required in the COM standards.

Commission Determination

47. We agree with NERC and other commenters that there is a reliability need for the 

reliability coordinator, transmission operator and balancing authority to have data 

exchange capabilities that are redundant and diversely routed. However, we are 

concerned that the TOP and IRO Standards do not clearly address redundancy and 

diverse routing so that registered entities will unambiguously recognize that they have an 

obligation to address redundancy and diverse routing as part of their TOP and IRO 

compliance obligations. NERC’s comprehensive approach to establishing 
Docket No. RM15-16-000 - 34 -

communications capabilities necessary to maintain reliability in the COM standards is 

applicable to data exchange capabilities at issue here.

40 Therefore, pursuant to 

section 215(d)(5) of the FPA, we direct NERC to modify Reliability Standards TOP-001-

3, Requirements R19 and R20 to include the requirement that the data exchange 

capabilities of the transmission operators and balancing authorities require redundancy 

and diverse routing. In addition, we direct NERC to clarify that “redundant 

infrastructure” for system monitoring in Reliability Standards IRO-002-4, Requirement 

R4 is equivalent to redundant and diversely routed data exchange capabilities. 

48. Further, we disagree with commenter arguments that Reliability Standard EOP008-1 provides alternatives to data exchange redundancy and diverse routing. The NERC 

standard drafting team that developed the COM standards addressed this issue in the 

standards development process, responding to a commenter seeking clarification on the 

relationship between communication capabilities, alternative communication capabilities, 

primary control center functionality and backup control center functionality. The 

standard drafting team responded that “Interpersonal Communication and Alternative 

Interpersonal Communication are not related to EOP-008,” even though Reliability 

 40 See, e.g, Order No. 808, 151 FERC ¶ 61,039 at P 8: “NERC stated in its [COM] 

petition that Reliability Standard COM-001-2 establishes requirements for Interpersonal 

Communication capabilities necessary to maintain reliability. NERC explained that 

proposed Reliability Standard COM-001-2 applies to reliability coordinators, balancing 

authorities, transmission operators, generator operators, and distribution providers. The 

proposed Reliability Standard includes eleven requirements and two new defined terms, 

“Interpersonal Communication” and “Alternative Interpersonal Communication,” that, 

according to NERC, collectively provide a comprehensive approach to establishing 

communications capabilities necessary to maintain reliability.”
Docket No. RM15-16-000 - 35 -

Standard EOP-008-1 Requirement R1 applies equally to data communications and voice 

communications.41 To the extent the standard drafting team asserted that Reliability 

Standard EOP-008 did not supplant the redundancy requirements of the COM Reliability 

Standards, we believe the same is true for data communications. Redundancy for data 

communications is no less important than the redundancy explicitly required in the COM

standards for voice communications. 

2. Testing of the Alternate or Less Frequently Used Data Exchange 

Capability

NOPR

49. In the NOPR, the Commission expressed concern that the proposed TOP and IRO 

Reliability Standards do not appear to address testing requirements for alternative or less 

frequently used mediums for data exchange to ensure they would properly function in the 

event that the primary or more frequently used data exchange capabilities failed. 

Accordingly, the Commission sought comment on whether and how the TOP and IRO 

Reliability Standards address the testing of alternative or less frequently used data 

exchange capabilities for the transmission operator, balancing authority and reliability 

coordinator. 

 41 See NERC COM Petition, Exh. M, (Consideration of Comments on Initial 

Ballot, February 25 - March 7, 2011) at 30 (emphasis added).
Docket No. RM15-16-000 - 36 -

Comments

50. Commenters assert that the existing standards have sufficient testing requirements. 

NERC points to Reliability Standard EOP-008-1, Requirement R7, which requires that 

applicable entities conduct annual tests of their operating plan that demonstrates, among 

other things, backup functionality. Similarly, EEI cites EOP-008-1 Requirements R1, 

R1.2, R1.2.2, R7 and EOP-001-2.1b Requirements R6 and R6.1 as providing specific 

requirements for maintaining and testing of data exchange capabilities. ITC suggests that 

NERC’s proposed Standard TOP-001-3 provides ample assurance that the data exchange 

capabilities are regularly tested and also points to Reliability Standards EOP-001-2.1b 

and EOP-008-1 which require entities, including those covered by TOP-001-3, to 

maintain reliable back-up data exchange capability as necessary to ensure reliable BES 

operations, and require that such capabilities be thoroughly and regularly tested. 

Commission Determination

51. We agree with NERC and other commenters that there is a reliability need for the 

reliability coordinator, transmission operator and balancing authority to test alternate data 

exchange capabilities. However, we are not persuaded by the commenters’ assertions

that the need to test is implied in the TOP and IRO Standards. Rather, we determine that 

testing of alternative data exchange capabilities is important to reliability and should not 

be left to what may or may not be implied in the standards.42 Therefore, pursuant to 

 42 In NERC’s COM Petition, Exh. M, (Consideration of Comments, Index to 

Questions, Comments and Responses) at 35, the standard drafting team stated that the 

(continued ...)
Docket No. RM15-16-000 - 37 -

section 215(d)(5) of the FPA, we direct NERC to develop a modification to the TOP and 

IRO standards that addresses a data exchange capability testing framework for the data 

exchange capabilities used in the primary control centers to test the alternate or less 

frequently used data exchange capabilities of the reliability coordinator, transmission 

operator and balancing authority. We believe that the structure of Reliability Standard 

COM-001-2, Requirement R9 could be a model for use in the TOP and IRO Standards.

43

E. Other Issues Raised by Commenters

1. Emergencies and Emergency Assistance Under Reliability 

Standard TOP-001-3 

52. Reliability Standard TOP-001-3, Requirement R7 requires each transmission 

operator to assist other transmission operators within its reliability coordinator area, if 

requested and able, provided that the requesting transmission operator has implemented 

its comparable emergency procedures. NIPSCO contends that this requirement limits the 

ability of an adjacent transmission operator that is located along the seam in another

reliability coordinator area from rendering assistance in an emergency because 

Requirement R7 only requires each transmission operator to assist other transmission 

 

“requirement [COM-001-2, Requirement R9 which addresses testing of alternative 

interpersonal communication] applies to the primary control center” and “EOP-008 

applies to the back up control center.”

43 COM-001-2, Requirement R9 states: “Each Reliability Coordinator, 

Transmission Operator, and Balancing Authority shall test its Alternative Interpersonal 

Communication capability at least once each calendar month. If the test is unsuccessful, 

the responsible entity shall initiate action to repair or designate a replacement Alternative 

Interpersonal Communication capability within 2 hours.” 
Docket No. RM15-16-000 - 38 -

operators within its reliability coordinator area. NIPSCO points to Reliability Standard 

IRO-014-3, Requirement R7 which requires each reliability coordinator to assist other 

reliability coordinators and, according to NIPSCO, a similar requirement in Reliability 

Standard TOP-001-3 will make the two sets of requirements consistent with each other. 

53. In addition, Reliability Standard TOP-001-3, Requirement R8 states: 

Each Transmission Operator shall inform its Reliability Coordinator, 

known impacted Balancing Authorities, and known impacted 

Transmission Operators of its actual or expected operations that 

result in, or could result in, an Emergency.

BPA contends that the phrase “could result in” in Requirement R8 of TOP-001-3 is 

overly broad and suggests corrective language underscored below: 

Each Transmission Operator shall inform its Reliability Coordinator, 

known impacted Balancing Authorities, and known impacted 

Transmission Operators of its actual or expected operations that 

result in an Emergency, or could result in an Emergency if a credible 

Contingency were to occur. 

As an alternative to changing the language of the requirement, BPA asks the Commission 

to clarify that it is in the transmission operator’s discretion to determine what “could 

result” in an emergency, based on the transmission operator’s experience and judgment. 

Commission Determination

54. With regard to NIPSCO’s concern, we do not believe that the requirements as 

written limit the ability of an adjacent transmission operator located along the seam in 

another reliability coordinator area from rendering assistance in an emergency. We agree 

with NIPSCO that proposed Reliability Standard TOP-001-3, Requirement R7 requires 
Docket No. RM15-16-000 - 39 -

each transmission operator to assist other transmission operators within its reliability 

coordinator area and further agree with NIPSCO that proposed Reliability Standard IRO014-3, Requirement R7 requires each reliability coordinator to assist other reliability 

coordinators.

44 In addition, we understand that an adjacent transmission operator in 

another reliability coordinator area can render assistance when directed to do so by its 

own reliability coordinator.

45 Having a similar requirement in Reliability Standard TOP001-3 compared to Reliability Standard IRO-014-3, Requirement R7 is unnecessary and 

could complicate the clear decision-making authority NERC developed in the TOP and 

IRO Reliability Standards. Thus, we determine that no further action is required. 

55. With regard to clarification of emergencies in Reliability Standard TOP-001-3, 

Requirement R8, we do not see a need to modify the language as suggested by BPA. The 

requirement as written implies that the transmission operator has discretion to determine 

what could result in an emergency, based on its experience and judgment. In addition, 

we note that the transmission operators’ required next-day operational planning analysis, 

real-time assessments and real-time monitoring under the TOP Reliability Standards 

provide evaluation, assessment and input in determining what “could result” in an 

emergency.

 44 See Reliability Standards TOP-001-3 and IRO-014-3.

45 See Reliability Standard IRO-001-4, Requirement R2. 
Docket No. RM15-16-000 - 40 -

2. Reliability Coordinator Authority in Next-Day Operating Plans

56. Reliability Standard TOP-002-4, Requirements R2 and R4 require transmission 

operators and balancing authorities to have operating plans. Reliability Standard TOP002-4, Requirements R6 and R7 require transmission operators and balancing authorities 

to provide their operating plans to their reliability coordinators and Reliability Standard 

IRO-008-2, Requirement R2 requires reliability coordinators to develop a coordinated 

operating plan that considers the operating plans provided by the transmission operators 

and balancing authorities. 

57. NIPSCO is concerned about the absence of any required direct coordination 

between transmission operators and balancing authorities as well as the absence of any 

guidance regarding the resolution of potential conflicts between the transmission operator 

and balancing authority operating plans. NIPSCO contends that the Reliability Standards 

provide only a limited coordination process in which reliability coordinators are required 

to notify those entities identified with its coordinated operating plan of their roles. 

NIPSCO argues that there is no provision for modifications to operating plans based on 

the reliability coordinator’s coordinated operating plan or based on potential conflicts

between the transmission operator and balancing authority operating plans. NIPSCO is 

concerned that a potential disconnect between operating plans could lead to confusion or 

a failure of coordination of reliable operations.
Docket No. RM15-16-000 - 41 -

Commission Determination

58. We believe that proposed Reliability Standards TOP-002-4 and IRO-008-2 along 

with NERC’s definition of reliability coordinator address NIPSCO’s concern.46 

Although the transmission operator and balancing authority develop their own operating 

plans for next-day operations, both the transmission operator and balancing authority 

notify entities identified in the operating plans as to their role in those plans. Further, 

each transmission operator and balancing authority must provide its operating plan for 

next-day operations to its reliability coordinator.

47 In Reliability Standard IRO-008-2, 

Requirement R2, the reliability coordinator must have a coordinated operating plan for 

next-day operations to address potential SOL and IROL exceedances while considering 

the operating plans for the next-day provided by its transmission operators and balancing 

authorities. Also, Reliability Standard IRO-008-2, Requirement R3 requires that the 

reliability coordinator notify impacted entities identified in its operating plan as to their 

role in such plan. Based on the notification and coordination processes of Reliability 

Standards TOP-002-4 (for the transmission operator and balancing authority) and IRO-

 46 NERC Glossary of Terms defines the Reliability Coordinator as “The entity that 

is the highest level of authority who is responsible for the reliable operation of the Bulk 

Electric System, has the Wide Area view of the Bulk Electric System, and has the 

operating tools, processes and procedures, including the authority to prevent or mitigate 

emergency operating situations in both next-day analysis and real-time operations. The 

Reliability Coordinator has the purview that is broad enough to enable the calculation of 

Interconnection Reliability Operating Limits, which may be based on the operating 

parameters of transmission systems beyond any Transmission Operator’s vision.” 

47 Reliability Standard TOP-002-4 (Operations Planning).
Docket No. RM15-16-000 - 42 -

008-2 (for the reliability coordinator) for next-day operating plans, as well as the fact that 

the reliability coordinator is the entity that is the highest level of authority who is 

responsible for the reliable operation of the bulk electric system, we believe that the 

reliability coordinator has the authority and necessary next-day operational information to 

resolve any next-day operational issues within its reliability coordinator area.

Accordingly, we deny NIPSCO’s request.

3. Reliability Coordinator Authority in Next-Day Operations and 

the Issuance of Operating Instructions 

59. NIPSCO is concerned with the elimination of the explicit requirement in

currently-effective Reliability Standard IRO-004-2 that each transmission operator, 

balancing authority, and transmission provider comply with the directives of a reliability 

coordinator based on next-day assessment in the same manner as would be required in 

real-time operating conditions. NIPSCO claims that, while the Reliability Standards 

appear to address the Commission’s concerns regarding directives issued in other than 

emergency conditions through the integration of the term “operating instruction,” the 

standards only allow for the issuance of directives in real-time. NIPSCO points to 

Reliability Standard TOP-001-3, Requirements R1 and R2, and IRO-001-4, Requirement 

R1, where transmission operators, balancing authorities, and reliability coordinators are 

explicitly given authority and responsibility to issue operating instructions to address 

reliability in their respective areas. NIPSCO states that “operating instruction” is “clearly 

limited to real-time operations” as it underscored below: 

A command by operating personnel responsible for the Real-time 

operation of the interconnected Bulk Electric System to change or 
Docket No. RM15-16-000 - 43 -

preserve the state, status, output, or input of an Element of the 

Bulk Electric System or Facility of the Bulk Electric System. 

(A discussion of general information and of potential options or 

alternatives to resolve Bulk Electric System operating concerns is 

not a command and is not considered an Operating Instruction.)

NIPSCO contends that there are no clear requirements addressing potential conflicts 

between operating plans, no clear requirements authorizing the issuance of a directive to 

address issues identified in next-day planning, and no clear requirement to comply with 

any directive so issued. NIPSCO is concerned that this raises the possibility that 

potential next-day problems identified in the operational planning analyses may not get 

resolved in the next-day planning period because the reliability coordinator’s authority to 

issue operating instructions is limited to real-time operation. According to NIPSCO, this 

limitation undermines some of the usefulness of the next-day planning and the 

performance of operational planning analyses.

Commission Determination

60. We do not share NIPSCO’s concern. Rather, we believe that, because the 

reliability coordinator is required to have a coordinated operating plan for the next-day 

operations, the reliability coordinator will perform its task of developing a coordinated 

operating plan in good faith, with inputs not only from its transmission operators and 

balancing authorities, but also from its neighboring reliability coordinators.48 A 

reliability coordinator has a wide-area view and bears the ultimate responsibility to 

 48 See Reliability Standards IRO-008-2, Requirements R1 and R2, and IRO-014-3, 

Requirement R1.
Docket No. RM15-16-000 - 44 -

maintain the reliability within its footprint, “including the authority to prevent or mitigate 

emergency operating situations in both next-day analysis and real-time operations.”49

61. In addition, we do not agree with NIPSCO’s claim that operating instructions are 

“clearly limited to real-time operations.” The phrase “real-time operation” in the 

definition of operating instruction as emphasized by NIPSCO applies to the entity that 

issues the operating instruction which is “operating personnel responsible for the Realtime operation.” The definition of operating instruction is “[a] command by operating 

personnel responsible for the Real-time operation of the interconnected Bulk Electric 

System....” In addition, the time horizons associated with the issuance of or compliance 

with an operating instruction are not found in the definition of operating instructions, but 

found in the individual requirement(s) applicable to issuing an operating instruction. For 

example, Reliability Standard TOP-001-3, Requirements R1 through R6 and IRO-001-4, 

Requirements R1 through R3 are all requirements associated with the issuance or 

compliance of operating instructions. In all nine requirements, the defined time horizon 

is “same-day operations” and “real-time operations.”50 Accordingly, we deny NIPSCO’s 

request on this issue.

 49 See supra n. 46. 

50 NERC’s “Time Horizons” document defines “Same-Day Operations” time 

horizon as “routine actions required within the timeframe of a day, but not real-time” and 

defines “Real-Time Operations” time horizon as “actions required within one hour or less 

to preserve the reliability of the bulk electric system.” See

http://www.nerc.com/files/Time_Horizons.pdf.
Docket No. RM15-16-000 - 45 -

4. Updating Operational Planning Analyses and Real-Time 

Assessments

62. NIPSCO is concerned that the proposed Reliability Standards are not clear as to 

whether updates or additional analyses are required. NIPSCO points to Reliability 

Standards IRO-008-2 and TOP-002-4, which require reliability coordinators to perform -

and transmission operators and balancing authorities to have - an operational analysis for 

the next-day, but do not specify when such analysis must be performed or if it needs to be 

updated in next-day planning based on any change in inputs. Similarly, NIPSCO asserts 

that the proposed Reliability Standards require the performance of a real-time assessment 

every 30 minutes but do not address the need to potentially update operating plans based 

on changes in system conditions (including unplanned outages of protection system 

degradation) and do not require the performance of additional real-time assessments or 

other studies with more frequency based on changes in system conditions. NIPSCO 

explains that it is not clear if or when, based on the operational planning analysis results, 

some type of additional study or analysis would need to be undertaken prior to the 

development of an operating plan. According to NIPSCO, the text of the requirements 

and the definition do not specifically require additional studies; however, it seems that 

when issues associated with protection system degradation or outages are identified, 

further study of these issues would be required and/or additional analyses required to

update results as protection system status or transmission or generation outages change.
Docket No. RM15-16-000 - 46 -

Commission Determination

63. We do not share NIPSCO’s concern. Reliability Standards IRO-008-2 and TOP002-4 require reliability coordinators to perform and transmission operators to have an 

operational planning analysis to assess whether its planned operations for next-day will 

exceed any of its SOLs (for the transmission operator) and SOLs/IROLs (for the 

reliability coordinator). Both are required to have an operating plan(s) to address 

potential SOL and/or IROL exceedances based on its operational planning analysis 

results. We believe that, if the applicable inputs of the operational planning analysis 

change from one operating day to the next operating day, and because an operational 

planning analysis is an “evaluation of projected system conditions,” a new operational 

planning analysis must be performed to include the change in applicable inputs. Based 

on the results of the new operational planning analysis for next-day, operating plans may 

need updating to reflect the results of the new operational planning analysis. Likewise 

with the real-time assessment, as system conditions change and the applicable inputs to 

the real-time assessment change, a new assessment would be needed to accurately reflect 

applicable inputs, as stated in the real-time assessment definition.51

 51 Real-time assessment is defined as “An evaluation of system conditions using 

Real-time data to assess existing (pre-Contingency) and potential (post-Contingency) 

operating conditions. The assessment shall reflect applicable inputs including, but not 

limited to: load, generation output levels, known Protection System and Special 

Protection System status or degradation, Transmission outages, generator outages, 

Interchange, Facility Ratings, and identified phase angle and equipment limitations. 

(Real-time Assessment may be provided through internal systems or through third-party

services.).”
Docket No. RM15-16-000 - 47 -

5. Performing a Real-time Assessment When Real-Time 

Contingency Analysis Is Unavailable

64. Reliability Standard TOP-001-3, Requirement R13 requires transmission operators 

to ensure a real-time assessment is performed at least every 30 minutes. NIPSCO states 

that NERC’s definition of real-time assessment anticipates that real-time assessments 

must be performed through the use of either an internal tool or third-party service.52 

NIPSCO believes that compliance with the requirement to perform a real-time 

assessment should not be dependent on the availability of a system or tool. According to 

NIPSCO, if a transmission operators’ tools are unavailable for 30 minutes or more, they 

should be permitted to meet the requirement to assess existing conditions through other 

means. 

Commission Determination

65. Reliability Standard TOP-001-3, Requirement R13 requires the transmission 

operator to ensure the assessment is performed at least once every 30 minutes, but does 

not state that the transmission operator on its own must perform the assessment and does 

not specify a system or tool. This gives the transmission operator flexibility to perform 

its real-time assessment. Further supporting this flexibility, NERC’s definition of realtime assessment states that a real-time assessment “may be provided through internal 

systems or through third-party services.”53 Therefore, we believe that Reliability 

 52 See supra n. 48. 

53 NERC TOP/IRO Petition at 18.
Docket No. RM15-16-000 - 48 -

Standard TOP-001-3, Requirement R13 does not specify the system or tool a 

transmission operator must use to perform a real-time assessment. In addition, NERC 

explains that Reliability Standard TOP-001-3, Requirement R13 and the definition of 

real-time assessment “do not specify the manner in which an assessment is performed nor 

do they preclude Reliability Coordinators and Transmission Operators from taking 

‘alternative actions’ and developing procedures or off-normal processes to mitigate 

analysis tool (RTCA) outages and perform the required assessment of their systems. As 

an example, the Transmission Operator could rely on its Reliability Coordinator to 

perform a Real-time Assessment or even review its Reliability Coordinator’s 

Contingency analysis results when its capabilities are unavailable and vice-versa.”54 

Accordingly, we conclude that TOP-001-3 adequately addresses NIPSCO’s concern, 

namely, if a transmission operators’ tools are unavailable for 30 minutes or more, the 

transmission operator has the flexibility to meet the requirement to assess system

conditions through other means.

6. Valid Operating Limits

66. IESO is concerned that the revised TOP standards do not compel an entity to 

verify existing limits or re-establish limits following an event that results in conditions 

not previously assessed within an acceptable time frame as is specified in the currently-

 54 NERC TOP/IRO Petition, Exh. K (Summary of Development History and 

Complete Record of Development), Consideration of Comments May 19, 2014 through 

July 2, 2014) at 61.
Docket No. RM15-16-000 - 49 -

effective Reliability Standard TOP-004-2 Requirement R4.

55 IESO disagrees that this is 

sufficient because there is no requirement in the Reliability Standard TOP-001-3 standard 

to derive a new set of limits, particularly transient stability limits, or verify that an 

existing set of limits continue to be valid for the prevailing conditions within an 

established timeframe. IESO contends that a real-time assessment is useful only if the 

system conditions are assessed against a valid set of limits and is unable to verify or reestablish stability-restricted SOLs with which to assess system conditions to address 

reliability concerns. IESO believes that an explicit requirement to verify or re-establish 

SOLs when entering into an unstudied state must therefore be imposed to fill this 

reliability gap. 

67. Further, IESO asserts that implementing operating plans to mitigate an SOL 

exceedance does not require transmission operators to determine a valid set of limits with 

which to compare the prevailing system conditions (i.e. whether or not the limits are 

exceeded). While the IESO supports performing a real-time assessment every 

30 minutes, it asserts that performing an assessment without first validating the current 

set of limits or re-establishing a new set of limits as the boundary conditions leaves a 

reliability gap.

 55 Requirement R4 states: “If a Transmission Operator enters an unknown 

operating state (i.e. any state for which valid operating limits have not been determined), 

it will be considered to be in an emergency and shall restore operations to respect proven 

reliable power system limits within 30 minutes.”
Docket No. RM15-16-000 - 50 -

Commission Determination

68. We agree with IESO that valid operating limits, including transient stability limits, 

are essential to the reliable operation of the interconnected transmission network and that 

a transmission operator must not enter into an unknown operating state. Further, we

agree with IESO that Reliability Standard TOP-001-3 has no requirements to derive a 

new set of limits or verify an existing set of limits for prevailing operating conditions 

within an established timeframe. However, IESO’s concerns regarding the establishment 

of transient stability operating limits are addressed collectively through proposed 

Reliability Standard TOP-001-3, certain currently-effective Facilities Design, 

Connections, and Maintenance (FAC) Reliability Standards and NERC’s Glossary of 

Terms definition of SOLs.

69. In its SOL White Paper, NERC stated that the intent of the SOL concept is to 

bring clarity and consistency for establishing SOLs, exceeding SOLs, and implementing 

operating plans to mitigate SOL exceedances.56 In addition, “transient stability ratings” 

 56 NERC Petition, Exh. E (White Paper on System Operating Limit Definition and 

Exceedance Clarification) at 1. NIPSCO requests clarification as to how NERC’s SOL 

White Paper can be used in determining compliance. NIPSCO requests that any 

substantive content that is treated as containing enforceable compliance requirements be 

filed with the Commission for approval. NERC developed the SOL White Paper as a 

guidance document which provides links between relevant reliability standards and 

reliability concepts to establish a common understanding necessary for developing 

effective operating plans to mitigate SOL exceedances. Guidelines are illustrative but not 

mandatory and enforceable compliance requirements. See, e.g. North American Electric 

Reliability Corp., 143 FERC ¶ 61,271, at P 15 (2013). Accordingly, we see no need for 

further revisions to the Reliability Standards to incorporate the SOL White Paper as 

requested by NIPSCO.
Docket No. RM15-16-000 - 51 -

are included in the SOL definition. Further, in the SOL White Paper, NERC states that 

the “concept of SOL determination is not complete without looking at the approved 

NERC FAC standards FAC-008-3, FAC-011-2 and FAC-014-2.”57 Specific to IESO’s 

concerns of establishing transient stability limits, we agree with NERC that approved 

Reliability Standard FAC-011-2, Requirement R2 requires that the reliability 

coordinator’s SOL methodology include a requirement that SOLs provide a certain level 

of bulk electric system performance including among other things, that the “BES shall 

demonstrate transient, dynamic and voltage stability” and that “all Facilities shall be 

within their...stability limits” for both pre- and post-contingency conditions.58 In 

addition, we note that currently-effective Reliability Standard FAC-011-2, Requirement 

R2.1 states that “[i]n the determination of SOLs, the BES condition used shall reflect 

current or expected system conditions and shall reflect changes to system topology such 

as Facility outages.”59

70. With respect to Reliability Standard TOP-001-3, we agree with NERC that 

Requirement R13 specifies that transmission operators must perform a real-time 

assessment at least once every 30 minutes, which by definition is an evaluation of system 

conditions to assess existing and potential operating conditions. The real-time 

 57 NERC Petition, Exh. E at 1.

58 Id. at 2. See also Reliability Standard FAC-011-2, Requirement R2. 

59 Reliability Standard FAC-011-1, Requirement R2.1 (emphasis added).
Docket No. RM15-16-000 - 52 -

assessment provides the transmission operator with the necessary knowledge of the 

system operating state to initiate an operating plan, as specified in Requirement R14, 

when necessary to mitigate an exceedance of SOLs. In addition, the SOL White Paper 

provides technical guidance for including timelines in the required operating plans to 

return the system to within prescribed ratings and limits.60 Accordingly, we conclude 

that the establishment of transient stability operating limits is adequately addressed 

collectively through proposed Reliability Standard TOP-001-3, currently-effective 

Reliability Standards FAC-011-2 and FAC-014-2 and NERC’s Glossary of Terms 

definition of SOLs.

61

III. Information Collection Statement

71. The collection of information contained in this Final Rule is subject to review by 

the Office of Management and Budget (OMB) regulations under section 3507(d) of the 

Paperwork Reduction Act of 1995 (PRA).62 OMB’s regulations require approval of 

certain informational collection requirements imposed by agency rules.63 Upon approval 

of a collection(s) of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of a rule will not be 

 60 NERC Petition at 57-58.

61 See Reliability Standard FAC-014-2, Requirement R2.

62 44 U.S.C. 3507(d) (2012).

63 5 C.F.R. § 1320.11.
Docket No. RM15-16-000 - 53 -

penalized for failing to respond to these collections of information unless the collections 

of information display a valid OMB control number. 

Public Reporting Burden: The number of respondents below is based on an estimate of 

the NERC compliance registry for the balancing authority, transmission operator, 

generator operator, distribution provider, generator owner, load-serving entity, 

purchasing-selling entity, transmission service provider, interchange authority, 

transmission owner, reliability coordinator, planning coordinator, and transmission 

planner functions. The Commission based its paperwork burden estimates on the 

NERC compliance registry as of May 15, 2015. According to the registry, there are 

11 reliability coordinators, 99 balancing authorities, 450 distribution providers, 

839 generator operators, 80 purchasing-selling entities, 446 load-serving entities, 

886 generator owners, 320 transmission owners, 24 interchange authorities, 

75 transmission service providers, 68 planning coordinators, 175 transmission planners 

and 171 transmission operators. The estimates are based on the change in burden from 

the current standards to the standards approved in this Final Rule. The following table 

illustrates the burden to be applied to the information collection: 
Docket No. RM15-16-000 - 54 -

RM15-16-000 (Transmission Operations Reliability Standards,

Interconnection Reliability Operations and Coordination Reliability Standards)

Number of 

Respondents

64

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total 

Number of 

Responses 

(1)*(2)=(3)

Average 

Burden & 

Cost Per 

Response65

(4)

Total Annual 

Burden Hours 

& Total 

Annual Cost

(3)*(4)=(5)

Cost per 

Respondent

($)

(5)÷(1)

FERC-725A

TOP-001-3 196 (TOP & 

BA)

1 196 96 hrs.

$6,369

18,816 hrs., 

$1,248,441 

96 hrs, 

$6,369

TOP-002-4 196 (TOP & 

BA)

1 196 284 hrs.

$18,843

55,664 hrs., 

$3,693,306

284 hrs., 

$18,843

TOP-003-3 196 (TOP & 

BA)

1 196 230 hrs.

$15,260

45,080 hrs., 

$2,991,058

230 hrs., 

$15,260

Sub-Total for 

FERC-725A

123,252 hrs., 

$7,932,806

FERC-725Z

IRO-001-4

66 177 (RC & 

TOP)

1 177 0 hrs.

$0

0 hrs.

$0

0 hrs.

$0

IRO-002-4 11 (RC) 1 11 24 hrs.

$1,592

264 hrs., 

$17,516

24 hrs., 

$1,592

IRO-008-2 11 (RC) 1 11 228 hrs.

$15,127

2,508 hrs., 

$166,405

228 hrs., 

$15,127

IRO-010-2 11 (RC) 1 11 36 hrs.

$2,388

396 hrs., 

$26,274

36 hrs., 

$2,388

IRO-014-3 11 (RC) 1 11 12 hrs.

$796

132 hrs., 

$8,758

12 hrs., 

$796

IRO-017-1 180 (RC, PC, 

& TP)

1 180 218 hrs.

$14,464

39,240 hrs., 

$2,603,574

218 hrs., 

$14,464

Sub-Total for 

FERC-725Z

42,540 hrs., 

$2,822,529.00

 64 The number of respondents is the number of entities for which a change in 

burden from the current standards to the proposed exists, not the total number of entities 

from the current or proposed standards that are applicable.

65 The estimated hourly costs (salary plus benefits) are based on Bureau of Labor 

Statistics (BLS) information, as of April 1, 2015, for an electrical engineer ($66.35/hour). 

These figures are available at http://bls.gov/oes/current/naics3_221000.htm#17-0000.

66 IRO-001-4 is a revised standard with no increase in burden.
Docket No. RM15-16-000 - 55 -

Retirement of 

current standards 

currently in FERC725A

457(RC, TOP, 

BA, TSP, 

LSE, PSE, & 

IA)

1 457 -223 hrs.

-$14,796

-101,911 hrs., 

-$6,761,794

-223 hrs.

-$14,796

NET TOTAL of 

NOPR in RM15-

16

63,881 hrs, 

$3,993,540

Title: FERC-725Z, Mandatory Reliability Standards: IRO Reliability Standards, and 

FERC-725A, Mandatory Reliability Standards for the Bulk-Power System.

Action: Proposed Changes to Collections.

OMB Control Nos: 1902-0276 (FERC-725Z); 1902-0244 (FERC-725A).

Respondents: Business or other for-profit and not-for-profit institutions.

Frequency of Responses: On-going. 

72. Necessity of the Information and Internal review: The Commission has reviewed 

the requirements of Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-

4, IRO-002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 and made a 

determination that the standards are necessary to implement section 215 of the FPA. The 

Commission has assured itself, by means of its internal review, that there is specific, 

objective support for the burden estimates associated with the information requirements.

73. Interested persons may obtain information on the reporting requirements by 

contacting the Federal Energy Regulatory Commission, Office of the Executive Director, 

888 First Street, NE, Washington, DC 20426 [Attention: Ellen Brown, e-mail: 

DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. 

74. Comments on the requirements of this rule may also be sent to the Office of 

Management and Budget, Office of Information and Regulatory Affairs [Attention: Desk 
Docket No. RM15-16-000 - 56 -

Officer for the Federal Energy Regulatory Commission]. For security reasons, comments 

should be sent by e-mail to OMB at the following e-mail address: 

oira_submission@omb.eop.gov. Please reference OMB Control Nos. 1902-0276 (FERC725Z) and 1902-0244 (FERC-725A)) in your submission.

IV. Environmental Analysis

75. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.67 The Commission has categorically excluded certain actions 

from this requirement as not having a significant effect on the human environment. 

Included in the exclusion are rules that are clarifying, corrective, or procedural or that do 

not substantially change the effect of the regulations being amended.68 The actions 

approved herein fall within this categorical exclusion in the Commission’s regulations. 

V. Regulatory Flexibility Act Analysis 

76. The Regulatory Flexibility Act of 1980 (RFA) generally requires a description and 

analysis of Proposed Rules that will have significant economic impact on a substantial 

number of small entities. 69 The Small Business Administration’s (SBA) Office of Size 

 67 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations 

Preambles 1986-1990 ¶ 30,783 (1987).

68 18 C.F.R. 380.4(a)(2)(ii).

69 5 U.S.C. 601-12. 
Docket No. RM15-16-000 - 57 -

Standards develops the numerical definition of a small business.70 The SBA revised its 

size standard for electric utilities (effective January 22, 2014) to a standard based on the 

number of employees, including affiliates (from a standard based on megawatt hours).71 

Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO-002-4, 

IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 are expected to impose an additional 

burden on 196 entities (reliability coordinators, transmission operators, balancing 

authorities, transmission service providers, and planning authorities). Comparison of the 

applicable entities with the Commission’s small business data indicates that 

approximately 82 of these entities are small entities that will be affected by the proposed 

Reliability Standards.72 As discussed above, Reliability Standards TOP-001-3, TOP-002-

4, TOP-003-3, IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO017-1 will serve to enhance reliability by imposing mandatory requirements for 

operations planning, system monitoring, real-time actions, coordination between 

applicable entities, and operational reliability data. The Commission estimates that each 

of the small entities to whom the proposed Reliability Standards TOP-001-3, TOP-002-4, 

 70 13 C.F.R. 121.101.

71 SBA Final Rule on “Small Business Size Standards: Utilities,” 78 FR 77343 

(Dec. 23, 2013).

72 The Small Business Administration sets the threshold for what constitutes a 

small business. Public utilities may fall under one of several different categories, each 

with a size threshold based on the company’s number of employees, including affiliates, 

the parent company, and subsidiaries. For the analysis in this NOPR, we are using a 

750 employee threshold for each affected entity to conduct a comprehensive analysis.
Docket No. RM15-16-000 - 58 -

TOP-003-3, IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 

applies will incur costs of approximately $147,364 (annual ongoing) per entity. The 

Commission does not consider the estimated costs to have a significant economic impact 

on a substantial number of small entities. 

VI. Document Availability

77. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington, DC 20426.

78. From FERC's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field.

79. User assistance is available for eLibrary and the FERC’s 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 No. RM15-16-000 - 59 -

VII. Effective Date and Congressional Notification

80. This final rule is effective [insert date 60 days from publication in Federal 

Register]. The Commission has determined, with the concurrence of the Administrator 

of the Office of Information and Regulatory Affairs of OMB, that this rule is not a “major 

rule” as defined in section 351 of the Small Business Regulatory Enforcement Fairness 

Act of 1996.

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.