130 FERC ¶ 61,208 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

[Docket No. RM10-6-000] 

Interpretation of Transmission Planning Reliability Standard 

(March 18, 2010) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: Requirement R1.3.10 of the Commission-approved transmission planning 

Reliability Standard TPL-002-0 provides that planning authorities and transmission 

planners must consider in their planning studies the effects of the operation of their 

protection systems, including backup and redundant protection systems. The North 

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

reliability organization, requests approval of an interpretation of Reliability Standard 

TPL-002-0. In this order, the Commission proposes to reject NERC’s proposed 

interpretation of Requirement R1.3.10 of Reliability Standard TPL-002-0 and, instead, 

proposes an alternative interpretation of the provision. 

DATES: Comments are due [date that is 45 days after publication in the FEDERAL 

REGISTER].

ADDRESSES: You may submit comments, identified by docket number by any of the 

following methods: 
Docket No. RM10-6-000 - 2 - 

 Agency Web Site: http://ferc.gov. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format 

and not in a scanned format. 

 Mail/Hand Delivery: Commenters unable to file comments electronically must 

mail or hand deliver an original and 14 copies of their comments to: Federal 

Energy Regulatory Commission, Secretary of the Commission, 888 First Street, 

N.E., Washington, D.C. 20426. 

FOR FURTHER INFORMATION CONTACT: 

Ron LeComte (Legal Information) 

Office of General Counsel 

888 First Street, NE 

Washington, DC 20426 

ron.lecomte@ferc.gov

Eugene Blick (Technical Information) 

Office of Electric Reliability 

888 First Street, NE 

Washington, DC 20426 

eugene.blick@ferc.gov

Edward Franks (Technical Information) 

Office of Electric Reliability 

888 First Street, NE. 

Washington, DC 20426 

edward.franks@ferc.gov

Lauren Rosenblatt (Legal Information) 

Office of Enforcement 

888 First Street, NE 

Washington, DC 20426 

lauren.rosenblatt@ferc.gov

SUPPLEMENTARY INFORMATION:
130 FERC ¶ 61,208 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Interpretation of Transmission Planning Reliability 

Standard 

Docket No. RM10-6-000 

NOTICE OF PROPOSED RULEMAKING 

(March 18, 2010) 

1. On November 17, 2009, the North American Electric Reliability Corporation 

(NERC) submitted a petition (NERC Petition) requesting approval of NERC’s 

interpretation of Requirement R1.3.10 of Commission-approved transmission planning 

Reliability Standard TPL-002-0 (System Performance Following Loss of a Single Bulk 

Electric System Element). NERC developed the interpretation in response to a request 

for interpretation submitted to NERC by PacifiCorp on January 12, 2009. The 

Commission proposes to reject the NERC proposed interpretation of Requirement 

R1.3.10 of Reliability Standard TPL-002-0 and, instead, proposes an alternative 

interpretation of the provision. 

I. Background

2. Section 215 of the Federal Power Act (FPA) requires a Commission-certified 

Electric Reliability Organization (ERO) to develop mandatory and enforceable 

Reliability Standards, which are subject to Commission review and approval.1

 

 1

 16 U.S.C. 824. 
Docket No. RM10-6-000 - 2 - 

Specifically, the Commission may approve, by rule or order, a proposed Reliability 

Standard or modification to a Reliability Standard if it determines that the Standard is 

just, reasonable, not unduly discriminatory or preferential, and in the public interest.2

 

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

Commission oversight, or by the Commission independently.3

3. Pursuant to section 215 of the FPA, the Commission established a process to select 

and certify an ERO,4

 and subsequently certified NERC.5 On April 4, 2006, NERC 

submitted to the Commission a petition seeking approval of 107 proposed Reliability 

Standards. On March 16, 2007, the Commission issued a Final Rule, Order No. 693,6

approving 83 of the 107 Reliability Standards, including transmission planning 

Reliability Standards TPL-001-0 through TPL-004-0. In addition, pursuant to section 

 2 Id. 824o(d)(2). 

3 Id. 824o(e)(3). 

4 Rules Concerning Certification of the Electric Reliability Organization; and 

Procedures for the Establishment, Approval, and Enforcement of Electric Reliability 

Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh’g, Order 

No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006). 

5 North American Electric Reliability Corp., 116 FERC ¶ 61,062, order on reh’g 

& compliance, 117 FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v. FERC, 564 F.3d 

1342 (D.C. Cir. 2009). 

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

FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 

(2007). 
Docket No. RM10-6-000 - 3 - 

215(d)(5) of the FPA,7

 the Commission directed NERC to develop modifications to 56 of 

the 83 approved Reliability Standards, including TPL-002-0.8

4. NERC’s Rules of Procedure provide that a person that is “directly and materially 

affected” by Bulk-Power System reliability may request an interpretation of a Reliability 

Standard.9

 In response, the ERO will assemble a team with relevant expertise to address 

the requested interpretation and also form a ballot pool. NERC’s Rules of Procedure 

provide that, within 45 days, the team will draft an interpretation of the reliability 

standard and submit it to the ballot pool. If approved by the ballot pool and subsequently 

by the NERC Board of Trustees (Board), the interpretation is appended to the Reliability 

Standard and filed with the applicable regulatory authorities for approval. 

II. Transmission Planning Reliability Standards

5. Each of the transmission planning Reliability Standards, TPL-001-0 through TPL004-0, requires the planning authorities and transmission planners (planner) to provide a 

“valid assessment” that would “ensure that reliable systems are developed that meet 

specified performance requirements” both in the near-term (years one through five) and 

in the longer-term (years six through ten, or as needed). For each of these Reliability 

Standards, entities must adequately assess a range of operating conditions on their 

systems and plan to meet certain performance criteria that the Reliability Standards 

 7

 16 U.S.C. 824o(d)(5). 

8

 Order No. 693, FERC Stats & Regs. ¶ 31,242 at P 1797. 

9

 NERC Rules of Procedure, Appendix 3A, Reliability Standards Development 

Procedure, Version 6.1, at 26-27 (2007). 
Docket No. RM10-6-000 - 4 - 

specify for each of four classes of contingencies.10 The principles that planners must 

apply to the design of the assessment and of the supporting studies are set forth in the 

Requirements of the specific Reliability Standard. 

6. Table I, which is incorporated into each TPL Reliability Standards, sets forth the 

different types of contingencies that planners must study pursuant to the specific 

Reliability Standard, and the performance criteria the system must meet when 

experiencing those contingencies to reliably meet all projected customer demand. 

7. Reliability Standard TPL-002-0 requires planners to assess system performance 

subject to Category B contingencies (“event resulting in the loss of a single element”) 

outlined in Table I. As provided in Table I, Category B contingencies include: 

(1) a single-line-to-ground (SLG) or three-phase (3Ø) fault with “normal clearing” 

that removes from service either a generator, transmission circuit or transformer;11 

(2) loss of an element without a fault; or 

(3) outage of a single pole (direct current) line with normal clearing. 

8. Requirement R1 of Reliability Standard TPL-002-0 states: 

R1. The Planning Authority and Transmission Planner shall each 

demonstrate through a valid assessment that its portion of the 

 10 TPL-001-0 through TPL-004-0 each includes the same Table I, titled 

“Transmission System Standards – Normal and Emergency Conditions,” which identifies 

the classes of contingencies as Category A through Category D. TPL-002-0 addresses 

Category B contingencies. 

11 See, Section IV. C. for the definition of normal clearing. 
Docket No. RM10-6-000 - 5 - 

interconnected transmission system is planned such that the Network can be 

operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the 

range of forecast system demands, under the contingency conditions as 

defined in Category B. To be valid, the Planning Authority and 

Transmission Planner assessments shall: ... 

9. Requirement R1 proceeds with sub-Requirements R1.1 through R1.5, which 

provide the criteria that must be met to qualify the assessment directed by Requirement 

R1 as valid. In particular, Requirement R1.3 mandates that the assessment shall 

[b]e supported by a current or past study and/or system simulation testing 

that addresses each of the following categories, showing system 

performance following Category B. The specific elements selected (from 

each of the following categories) for inclusion in these studies and 

simulations shall be acceptable to the associated Regional Reliability 

Organization(s). 

Further, Requirement R1.3.10 requires the planner to 

[i]nclude the effects of existing and planned protection systems, including 

any backup or redundant systems. 

10. In sum, Requirement R1 provides the parameters of a valid assessment of system 

performance when experiencing a single contingency; Requirement R1.3 defines the 

criteria for the “base cases” that must be included in the studies to support the 
Docket No. RM10-6-000 - 6 - 

assessment.12 Requirement R1.3.10 provides as a base case criteria that the studies must 

include the effects of existing and planned protection systems, including any backup or 

redundant systems. 

11. Requirement R1.3.10 requires that planners study how a utility’s protection 

system,13 which isolates faults within a defined geographic area, would operate under 

circumstances “including backup or redundant systems.” A utility designs its protection 

system with “primary” protection,14 and may also employ “redundant” protection that 

operates for a primary protection system component that fails. Utilities also use 

“backup” protection that functions to isolate a fault when the primary protection system 

does not operate. Depending on the specific design, backup may remove more elements, 

or take longer to isolate the fault than the primary protection system.15 

 12 Requirement R1.3 uses the term “categories” to define the criteria that must be 

included in the base cases. 

13 A protection system consists of protective relays, associated communication 

systems, voltage and current sensing devices, station batteries and DC control circuitry 

for the protection of bulk electric system elements. It detects faults and initiates 

operation of circuit breakers, thereby isolating the faulted element(s) from the remainder 

of the interconnected transmission system. 

14 A primary protection scheme is the first line of defense designed to remove the 

minimum number of elements in the shortest time. 

15 A backup protection system isolates the fault or disturbance by removing 

additional elements some period of time after the non-redundant primary protection 

system would do so, operating because that primary protection system did not function 

properly. Remote backup protection refers to protection systems that operate breakers 

distant from the site of the contingency and therefore result in the isolation of a larger 

portion of the bulk electric system. 
Docket No. RM10-6-000 - 7 - 

III. NERC Proposed Interpretation

12. In the NERC Petition, NERC explains that it received a request from PacifiCorp 

for an interpretation of Reliability Standard TPL-002-0, Requirement R1.3.10, addressing 

three specific questions. Below, we restate the PacifiCorp questions and NERC 

interpretations: 

Question 1: Does TPL-002-0 R1.3.10 require that all elements that are expected 

to be removed from service through normal operation of the protection systems be 

removed in simulations? 

Response 1: TPL-002-0 requires that System studies or simulations be made to 

assess the impact of single Contingency operation with Normal Clearing. TPL002-0, R1.3.10 does require that all elements expected to be removed from service 

through normal operations of the Protection Systems be removed in simulations. 

Question 2: Is a Category B disturbance limited to faults with [N]ormal [C]learing 

where the protection system operates as designed in the time expected with proper 

functioning of the protection system(s) or do Category B disturbances extend to 

protection system misoperations and failures? 

Response 2: This standard does not require an assessment of the Transmission 

System performance due to a Protection System failure or Protection System 

misoperation. Protection System failure or Protection System misoperation is 

addressed in TPL-003-0 — System Performance following Loss of Two or More 

Bulk Electric System Elements (Category C) and TPL-004-0 — System 
Docket No. RM10-6-000 - 8 - 

Performance Following Extreme Events Resulting in the Loss of Two or More 

Bulk Electric System (BES) Elements (Category D). 

Question 3: Does TPL-002-0, R1.3.10 require that planning for Category B 

[C]ontingencies assume a [C]ontingency that results in something other than a 

[N]ormal [C]learing event even though the TPL-002-0 Table I - Category B matrix 

uses the phrase "SLG or 3-Phase Fault, with Normal Clearing?” 

Response 3: TPL-002-0, R1.3.10 does not require simulating anything other than 

Normal Clearing when assessing the impact of a Single Line Ground (SLG) or 3-

Phase (3Ø) Fault on the performance of the Transmission System.16

13. In support of its request for approval, NERC contends that the proposed 

interpretation directly supports the reliability purpose of TPL-002-0 because it clarifies 

what is required for the “System simulations” cited in the main requirement without 

expanding the reach of the standard.17 NERC maintains that the proposed interpretation 

clearly identifies what needs to be done – that all elements expected to be removed from 

service through normal operation of the protection system must be removed in 

simulations and that only normal clearing is required in the simulations. NERC states 

 16 NERC Petition at 10. In support for its request for an interpretation, PacifiCorp 

states that “[i]f TPL-002-0, R1.3.10 requires that planning for Category B Contingencies 

must assume failure or misoperation of all existing and planned protection systems, 

protection system failures previously identified as Category C [] Contingencies or 

Category D [] Contingencies would now become Category B Contingencies ...” Id. at 

Appendix A at 1-2. 

17 NERC Petition at 11. 
Docket No. RM10-6-000 - 9 - 

that the proposed interpretation clearly distinguishes that misoperations and failures of 

the protection system are not part of Reliability Standard TPL-002-0, but are addressed in 

other standards. NERC states that the interpretation will result in ensuring that an 

adequate level of reliability for the Bulk-Power System will be achieved and maintained 

by providing clarity and certainty in support of the objective. 

14. In approving the proposed interpretation, the NERC Board stated that it applied a 

standard of strict construction that does not expand the reach of the Reliability Standard 

or correct a perceived gap or deficiency in the standard.18 The NERC Board 

recommended that any gaps or deficiencies in a Reliability Standard that are evident 

through the interpretation process be addressed promptly by the standards drafting team. 

NERC states that it will examine any gaps or deficiencies in Reliability Standard TPL002-0 in its consideration of the next version of this standard through the Reliability 

Standards Development Procedure.19

IV. Discussion

15. We propose to reject NERC’s proposed interpretation of Reliability Standard TPL002-0, Requirement R1.3.10. NERC proposes to interpret that simulations to assess the 

impact of single contingency operation “do[] not require an assessment of the 

Transmission System performance due to a Protection System failure or Protection 

 18 Id. at 5. 

19 NERC states that this standard is included in Project 2006-02 – Assess 

Transmission Future Needs and Develop Transmission Plans that is expected to be 

completed in the first half of 2010. 
Docket No. RM10-6-000 - 10 - 

System misoperation” to be in compliance with Requirement R1.3.10 of Reliability 

Standard TPL-002-0. NERC’s proposed interpretation miscategorizes non-operation of 

non-redundant primary protection systems as protection system failure which is 

addressed in TPL-003-0 and TPL-004-0. However, pursuant to TPL-002-0, planners are 

required to study the effects of existing and planned protection systems, including backup 

and redundant systems. Accordingly, by categorizing the non-operation of nonredundant primary protection systems as a protection system failure, NERC’s proposed 

interpretation misses studying the effects of backup and redundant protection systems 

pursuant to Requirement R1.3.10 of TPL-002-0. Rather, for the reasons discussed below, 

we believe that the Requirement R1.3.10 of TPL-002-0 requires that planners study, in 

their system assessments, the non-operation of primary protection systems in order to 

ascertain whether and how reliance on the as-designed backup or redundant protection 

systems affects reliability. Accordingly, we propose an interpretation of Requirement 

R1.3.10 of Reliability Standard TPL-002-0 consistent with our understanding. 

16. In support of our proposed interpretation, we explain that planning assessments are 

developed through base case simulations. We then distinguish a contingency from the 

base case, and conclude that the non-operation of a non-redundant primary protection 

system is not a contingency. Finally, we explain that normal clearing of a contingency 

depends on the protection system that operates to clear the contingency, and that only by 

modeling the non-operation of non-redundant primary protection systems in the base case 

would the planner include the effects of existing and planned protection systems, 

including backup or redundant systems. For these reasons, our proposed interpretation 
Docket No. RM10-6-000 - 11 - 

would require modeling of the non-operation of primary protection systems to be in 

compliance with Requirement R1.3.10 of Reliability Standard TPL-002-000, and not by 

the requirements to be in compliance with Reliability Standards TPL-003-0 and TPL004-0. 

A. Assessment through Base Case Simulations

17. Reliability Standard TPL-002-0 requires that planning authorities and planners 

demonstrate, through a valid assessment, that their portion of the interconnected 

transmission system will supply the projected customer demands and projected firm 

transmission service over a variety of conditions. A planner performs the assessment of 

its portion of the interconnected transmission system through computer modeling and 

simulations, in which the planner first creates base cases that reflect an array of system 

operating conditions. Using these base cases as a starting point, the planner then assesses 

the performance of the system and tests the base cases by subjecting them through 

computer modeling and simulations to various Category B Contingencies outlined in 

Table I. 

18. Performance of the system as modeled, assuming all of the Contingencies taken 

one at a time and at any location in the bulk electric system, must meet the performance 

criteria specified in Table I for Category B Contingencies. The performance criteria in 

Table I specifies that, in the event of a Category B Contingency, the system (1) remains 
Docket No. RM10-6-000 - 12 - 

stable and both thermal and voltage limits remain within applicable ratings;20 (2) 

continues to serve all firm demand and firm transfers;21 and (3) does not have any 

cascading outages. If the studies or system simulation tests show that, for Category B 

Contingencies, any of the system base cases do not meet these performance criteria, 

pursuant to Requirement R2 of Reliability Standard TPL-002-0, the planner must 

determine and document a modification. 

B. Distinguishing a Contingency from the Base Case

19. As previously discussed, Table I of Reliability Standard TPL-002-0 sets forth the 

Category B Contingencies that a planner must assess pursuant to Reliability Standard 

TPL-002-0. Table I defines contingencies in terms of their “initiating event(s)” and the 

elements the initiating event takes out of service. The determination of what elements 

would be taken out of service as a result of a Category B Contingency should not be 

confused with the number of elements ultimately taken out of service by the system’s 

 20 TPL-002-0, Table I defines “applicable ratings” in its footnote “a”. If other than 

normal ratings are applied, the planner must show that the bulk electric system can 

withstand the next contingency through system adjustments that do not result in the loss 

of firm load or firm transfers. System adjustments for Category B Contingencies do not 

include tripping of capacity resources. 

21 See Order No. 693, FERC Stats & Regs. ¶ 31,242 at P 1791-1795. 
Docket No. RM10-6-000 - 13 - 

response to the initiating event.22 For example, a contingency may involve a fault at a 

transformer at a generating unit. In response to the fault, operation of the primary 

protection system at the unit transformer, as designed, removes both the unit transformer 

and the associated generator from service. This scenario qualifies as a single contingency 

because there is only one initiating event involving one element - the transformer - even 

though the end state of the system includes the loss of two system elements – a unit 

transformer and a generator. 

20. It is also important to distinguish an element taken out of service by a contingency 

or the operation of a protection system from an element or protection system component 

that the base case assumes is not in operation. Transmission elements that are not in 

service and generators that are not dispatched or that are assumed to be “out of service” 

in the base case are not considered to be contingencies. For example, if the base case 

assumes that three generators and one line will be out of service for load conditions or 

maintenance, the base case system without those facilities in service is the normal 

operating condition. Requirement R1.3.10 requires the system planner to study the 

 22 In Order No. 693, the Commission explained, “a single contingency consists of 

a failure of a single element that faithfully duplicates what will happen in the actual 

system. .... Thus, if the system is designed such that failure of a single element removes 

from service multiple elements in order to isolate the faulted element, then that is what 

should be simulated to assess system performance.” Order No. 693, FERC Stats & Regs. 

¶ 31,242 at P 1716. 
Docket No. RM10-6-000 - 14 - 

effects of the non-operation of the non-redundant primary protection system in the base 

case simulations, not the effects of protection systems that are out of service.23 

21. The Commission proposes to interpret that the non-operation of a non-redundant 

primary protection system is not a contingency and Requirement R1.3.10 requires that the 

planner model, as a condition in the base case, the non-operation of the primary 

protection system, accounting for operation of the redundant protection system or, 

alternatively, the fact that the protection system is not redundant, as appropriate. Only by 

modeling and simulating system conditions with base cases representing element outages 

and clearing times associated with non-operation of the primary protection system will a 

planner comply with Requirement R1.3.10 of Reliability Standard TPL-002-0, that is, to 

study the “effects of ... any backup or redundant [protection] systems” on Category B 

contingencies. The Commission intends its proposed interpretation to ensure that the 

phrase is not rendered a nullity. 

C. Normal versus Delayed Clearing of the Contingency

22. Requirement R1.3.10 also requires that a planner’s studies and simulations model 

the Category B Contingencies with normal clearing. Footnote “e” of Table I defines 

“normal” and “delayed” clearing as follows: 

Normal clearing is when the protection system operates as designed and the Fault 

is cleared in the time normally expected with proper functioning of the installed 

 23 TPL-002-0, R.1.3.12 provides for the inclusion of a planned (including 

maintenance) outage of any bulk electric equipment (including protection systems or 

their components). 
Docket No. RM10-6-000 - 15 - 

protection system. Delayed clearing of a Fault is due to failure of any protection 

system component such as a relay, circuit breaker, or current transformer, and not 

because of an intentional design delay. 

23. The assumptions in a base case as to which protection system will operate to clear 

the contingency against which the base case is tested determines the amount of time 

associated with “operate[] as designed.” Thus, the base case assumptions determine 

which method of clearing constitutes normal clearing. If the base case being tested 

assumes the primary protection system operates, normal clearing of the contingency will 

be the clearing that is consistent with the as-designed operation of the primary protection 

system. If the base case assumes the primary protection system will not operate, normal 

clearing will be that clearing that is consistent with the redundant protection, if provided, 

or as-designed backup protection for that primary protection system.24 In a study or 

simulation test, how the protection systems operate will determine which circuit breakers 

will open and the times it takes for specific breakers to open. The changes in system 

topology due to the opening of circuit breakers (which takes elements out of service), the 

operating times in which those circuit breakers open, and the total time required to clear 

the fault from the system all affect how the bulk electric system performs. 

 24 For example, for a fault near one end of a line protected by distance relaying 

without communications, normal clearing from the end close to the fault will be zone 1 or 

times associated with primary clearing while the remote end will be zone 2 or times 

associated with back-up clearing. Both of these times are normal clearing as they are in 

accordance with design criteria. 
Docket No. RM10-6-000 - 16 - 

24. Delayed clearing of the contingency results only when the protection system in 

service in the base case (whether primary or back-up) does not operate as-designed due to 

a failure, such as a relay failing to operate (one form of relay misoperation), stuck breaker 

or other disabling condition. The concepts of normal and delayed clearing apply in the 

same manner to non-redundant primary protection systems. An example of normal 

clearing with longer clearing times is if the non-operation of a primary protection system 

disables both the primary protection and its breaker-failure-initiate protection. The 

backup protection that the system base case must test would be the next level of backup 

that would operate in the event of the contingency. The next level of backup protection 

may, for example, be the protection systems located at the adjacent substations, and will 

typically take longer to operate the necessary breakers by removing more elements to 

clear the fault than the operation of the primary or breaker-failure-initiate protection 

systems.25 These longer clearing times do not constitute or create a situation of delayed 

clearing, however, because the longer clearing times are the as-designed operating times 

of the backup protection system being utilized. 

25. With this understanding, the Commission proposes to interpret Requirement 

R1.3.10 as requiring a planner to study the effects of the as-designed backup protection 

system, and a planner must consider whether this clearing is consistent with the as-

 25 In the circumstance of this example, the Commission refers to the system that 

initiates breaker failure protection as the backup protection system that is coordinated to 

operate when the non-redundant primary protection system does not operate within a 

specified period of time. 
Docket No. RM10-6-000 - 17 - 

designed normal clearing of the protection system being studied. It follows that where a 

study’s base case is designed to test the effects of backup protection systems, the base 

case assumption that the backup protection system operates in the time normally expected 

is not equivalent to delayed clearing due to a primary protection system component 

failure. 

26. Rather, the backup protection system becomes the analytical starting point for the 

examined normal operating conditions, i.e., the base case, and any additional time and 

elements removed from service resulting from operation of that backup protection 

beyond those the primary protection system would require is intentional and as 

designed. The operating characteristics (i.e., time and elements removed) of the primary 

protection system are simply no longer part of the analysis. Delayed clearing in the case 

of simulating the effects of backup protection systems only results when there is a failure 

of a protection system component in the protection systems being simulated. 

27. Finally, we propose that the interpretation of R1.3.10 discussed herein will apply 

prospectively from the effective date of any Final Rule and no entity will be subject to 

financial penalties for having operated in a manner inconsistent with this proposed 

interpretation prior to the effective date of any Final Rule. 

D. Related Discussion in Order No. 693

28. The Commission did not specifically discuss a protection system failure or 

misoperation in Order No. 693. However, the Commission discussed the issue of a single 

point of protection system failure and how it factors into planning studies under the 

System Protection Coordination (PRC) Reliability Standards. The Commission stated: 
Docket No. RM10-6-000 - 18 - 

With respect to MISO’s comment that virtually all protection systems have 

backups and therefore the Commission’s proposals are not necessary, unless the 

backup protection has the same design goals and capabilities as the primary 

protection, a relay failure in the primary protection may still threaten system 

reliability. Further, we note that while the [Protection and Control] Reliability 

Standards do not specifically require protection systems consisting of redundant 

and independent protection groups for each critical element in the Bulk-Power 

System, such requirements are included as one potential solution in the TPL 

Reliability Standards.26

29. Therefore, the Commission has recognized the effect that non-operation of 

primary protection systems may have on reliability in the context of observing that 

redundant or backup protection systems may minimize the reliability risks that nonoperation of primary protection systems poses. Consistent with the concern the 

Commission discussed regarding the PRC Reliability Standards, Requirement R1.3.10 of 

Reliability Standard TPL-002-0 provides that the effect of non-operation of primary 

protection systems be studied for a valid assessment of system reliability. 

V. Comment Procedures

30. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

 26 Order No. 693, FERC Stats & Regs. ¶ 31,242 at P 1436, n.380 (if delayed 

clearing results in reliability criteria violations, one solution can be the use of redundant 

relay systems, citing TPL-002-0 Table I, footnote e). 
Docket No. RM10-6-000 - 19 - 

proposals that commenters may wish to discuss. Comments are due [date that is 45 days 

from publication in the FEDERAL REGISTER]. Comments must refer to Docket No. 

RM10-6-000, and must include the commenter's name, the organization they represent, if 

applicable, and their address in their comments. 

31. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 

32. Commenters that are not able to file comments electronically must send an 

original and 14 copies of their comments to: Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First Street N.E., Washington, DC, 20426. 

33. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 

VI. Document Availability

34. 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 
Docket No. RM10-6-000 - 20 - 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 20426. 

35. 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. 

36. User assistance is available for eLibrary and the FERC’s web site during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

By direction of the Commission. 

( S E A L ) 

Kimberly D. Bose, 

Secretary.