Interpretation of Transmission Planning Reliability Standard, 14386-14390 [2010-6565]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 75, Number 57 (Thursday, March 25, 2010)]
[Proposed Rules]
[Pages 14386-14390]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-6565]


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DEPARTMENT OF ENERGY

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.

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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 May 10, 2010.

ADDRESSES: You may submit comments, identified by docket number by any 
of the following methods:
     Agency Web Site: https://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, NE., Washington, DC 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:

Notice of Proposed Rulemaking

    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\ 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\
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    \1\ 16 U.S.C. 824.
    \2\ Id. 824o(d)(2).
    \3\ Id. 824o(e)(3).
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    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-

[[Page 14387]]

001-0 through TPL-004-0. In addition, pursuant to section 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\
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    \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 (DC 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).
    \7\ 16 U.S.C. 824o(d)(5).
    \8\ Order No. 693, FERC Stats & Regs. ] 31,242 at P 1797.
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    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.
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    \9\ NERC Rules of Procedure, Appendix 3A, Reliability Standards 
Development Procedure, Version 6.1, at 26-27 (2007).
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II. Transmission Planning Reliability Standards

    5. Each of the transmission planning Reliability Standards, TPL-
001-0 through TPL-004-0, 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 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.
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    \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.
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    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 (3[Oslash]) fault 
with ``normal clearing'' that removes from service either a generator, 
transmission circuit or transformer;\11\
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    \11\ See, Section IV. C. for the definition of normal clearing.
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    (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 
interconnected transmission system is planned such that the Network 
can be operated to supply projected customer demands and projected 
Firm (non-recallable 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 
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.
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    \12\ Requirement R1.3 uses the term ``categories'' to define the 
criteria that must be included in the base cases.
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    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\
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    \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.
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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. TPL-002-0, 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

[[Page 14388]]

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 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 (3[Oslash]) Fault on the performance of the 
Transmission System.\16\
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    \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.
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    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 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.
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    \17\ NERC Petition at 11.
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    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 TPL-002-0 in its consideration of 
the next version of this standard through the Reliability Standards 
Development Procedure.\19\
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    \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.
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IV. Discussion

    15. We propose to reject NERC's proposed interpretation of 
Reliability Standard TPL-002-0, 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 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 non-redundant 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 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 TPL-004-0.

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

[[Page 14389]]

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.
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    \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.
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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 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.
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    \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.
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    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 
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\
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    \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).
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    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 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.
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    \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.
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    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

[[Page 14390]]

times of the backup protection system being utilized.
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    \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.
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    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-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:

    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\
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    \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).

    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 non-operation 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 proposals that commenters may wish 
to discuss. Comments are due May 10, 2010. 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 https://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, NE., 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 (https://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington DC 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 e-mail 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.
Kimberly D. Bose,
Secretary.
[FR Doc. 2010-6565 Filed 3-24-10; 8:45 am]
BILLING CODE 6717-01-P