[Federal Register Volume 77, Number 88 (Monday, May 7, 2012)]
[Rules and Regulations]
[Pages 26686-26697]
[FR Doc No: 2012-10944]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM11-18-000; Order No. 762]

Transmission Planning Reliability Standards

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: Under section 215 of the Federal Power Act, the Federal Energy
Regulatory Commission remands proposed Transmission Planning (TPL)
Reliability Standard TPL-002-0b, submitted by the North American
Electric Reliability Corporation (NERC), the Commission-certified
Electric Reliability Organization. The proposed Reliability Standard
includes a provision that allows for planned load shed in a single
contingency provided that the plan is documented and alternatives are
considered and vetted in an open and transparent process. The
Commission finds that this provision is vague, unenforceable and not
responsive to the previous Commission directives on this matter.
Accordingly, the Final Rule remands NERC's proposal as unjust,
unreasonable, unduly discriminatory or preferential, and not in the
public interest.

DATES: This rule will become effective July 6, 2012.

ADDRESSES: You may submit comments, identified by docket number by any
of the following methods:
     Agency Web Site: http://www.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 comments to: Federal Energy
Regulatory Commission, Secretary of the Commission, 888 First Street
NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:
Eugene Blick (Technical Information), Office of Electric Reliability,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, Telephone:<PHONE_NUMBER><EMAIL_ADDRESS>Robert T. Stroh (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, Telephone:<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

139 FERC ] 61,060

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, and Cheryl A. LaFleur.

Final Rule

Issued April 19, 2012.
    1. Under section 215(d) of the Federal Power Act,\1\ the Commission
remands proposed Transmission Planning (TPL) Reliability Standard TPL-
002-0b, submitted by the North American Electric Reliability
Corporation (NERC), the Commission-certified Electric Reliability
Organization. The proposed Reliability Standard includes a provision
that allows for planned load shed in a single contingency provided that
the plan is documented and alternatives are considered and vetted in an
open and transparent process.\2\ The Commission finds that this
provision is vague, unenforceable and not responsive to the previous
Commission directives on this matter. Accordingly, the Final Rule
remands NERC's proposal as unjust, unreasonable, unduly discriminatory
or preferential, and not in the public interest. We require NERC to
utilize its Expedited Reliability Standards Development Process to
develop timely modifications to TPL-002-0b, Table 1 footnote `b' in
response to our remand.\3\
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    \1\ 16 U.S.C. 824o(d)(4) (2006).
    \2\ NERC filed a petition seeking approval of Table 1, footnote
`b' of four Reliability Standards: Transmission Planning: TPL-001-
1--System Performance Under Normal (No Contingency) Conditions
(Category A), TPL-002-1b--System Performance Following Loss of a
Single Bulk Electric System Element (Category B), TPL-003-1a--System
Performance Following Loss of Two or More Bulk Electric System
Elements (Category C), and TPL-004-1--System Performance Following
Extreme Events Resulting in the Loss of Two or More Bulk Electric
System Elements (Category D). While footnote `b' appears in all four
of the above referenced TPL Reliability Standards, its relevance and
practical applicability is limited to TPL-002-0a.
    \3\ NERC Rules of Procedure, Appendix 3A, Standard Processes
Manual at 34 (effective January 31, 2012).
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I. Background

    2. Section 215 of the FPA requires a Commission-certified Electric
Reliability Organization (ERO) to develop mandatory and enforceable
Reliability Standards, which are subject to Commission review and
approval. Approved Reliability Standards are enforced by the ERO,
subject to Commission oversight, or by the Commission independently. On
March 16, 2007, the Commission issued Order No. 693, approving 83 of
the 107 Reliability Standards filed by NERC, including Reliability
Standard TPL-002-0.\4\ In addition, pursuant to section 215(d)(5) of
the FPA, \5\ the Commission directed NERC to develop modifications to
56 of the 83 approved Reliability Standards, including footnote `b' of
Reliability Standard TPL-002-0.\6\
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    \4\ 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).
    \5\ 16 U.S.C. 824o(d)(5)(2006).
    \6\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1797.
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A. Transmission Planning (TPL) Reliability Standards

    3. Currently-effective Reliability Standard TPL-002-0b addresses
Bulk-Power System planning and related transmission system performance
for single element contingency conditions. Requirement R1 of TPL-002-0b
requires that each planning authority and transmission planner
``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
transmission services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category
B of Table I.'' \7\ Table I identifies different categories of
contingencies and allowable system impacts in the planning process.
With regard to system impacts, Table I further provides that a Category
B (single) contingency must not result in cascading outages, loss of
demand or curtailed firm transfers, system instability or exceeded
voltage or thermal limits. With regard to loss of demand, current
footnote `b' of Table 1 states:
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    \7\ Reliability Standard TPL-002-0a, Requirement R1.

    Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied
by the Faulted element or by the affected area, may occur in certain
areas without impacting the overall reliability of the
interconnected transmission systems. To prepare for the next
contingency, system adjustments are permitted, including
curtailments of contracted Firm (non-recallable reserved) electric
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power Transfers.

B. Order No. 693 Directive

    4. In Order No. 693, the Commission stated that it believes that
the transmission planning Reliability Standard should not allow an
entity to plan for the loss of non-consequential firm load in the event
of a single contingency.\8\ The Commission directed the ERO to develop
certain modifications, including a clarification of Table 1, footnote
`b.'
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    \8\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1794.
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    5. In a subsequent clarifying order, the Commission stated that it
believed that a regional difference, or a case-specific exception
process that can be technically justified, to plan for the loss of firm
service would be acceptable in limited circumstances.\9\ Specifically,
the Commission stated that ``a regional difference, or a case-specific
exception process that can be technically justified, to plan for the
loss of firm service at the fringes of various systems would be an
acceptable approach.'' \10\
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    \9\ Mandatory Reliability Standards for the Bulk Power System,
131 FERC ] 61,231, at P 21 (2010) (June 2010 Order).
    \10\ Id.
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C. NERC Petition

    6. On March 31, 2011, NERC filed a petition seeking approval of its
proposal to revise and clarify footnote `b' ``in regard to load loss
following a single contingency.'' \11\ NERC stated that it did not
eliminate the ability of an entity to plan for the loss of non-
consequential load in the event of a single contingency but drafted a
footnote that, according to NERC, ``meets the Commission's directive
while simultaneously meeting the needs of industry and respecting
jurisdictional bounds.'' \12\ NERC stated that its proposed footnote
`b' establishes the requirements for the limited circumstances when and
how an entity can plan to interrupt Firm Demand for Category B
contingencies. According to NERC, the provision allows for planned
interruption of Firm Demand when ``subject to review in an open and
transparent stakeholder process.'' \13\ NERC's proposed footnote `b'
states:
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    \11\ NERC Petition at 10.
    \12\ Id.
    \13\ Id.

    An objective of the planning process should be to minimize the
likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers
is allowed when

achieved through the appropriate redispatch of resources obligated
to re-dispatch, where it can be demonstrated that Facilities,
internal and external to the Transmission Planner's planning region,
remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any Firm Demand. It is recognized that
Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2)
Interruptible Demand or Demand-Side Management Load. Furthermore, in
limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to
circumstances where the use of Demand interruption are documented,
including alternatives evaluated; and where the Demand interruption
is subject to review in an open and transparent stakeholder process
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that includes addressing stakeholder comments.

    7. NERC supplemented the filing on June 7, 2011, in response to a
Commission deficiency letter. NERC explained that ``the approach
proposed in footnote `b' is equally efficient because many of the
stakeholder processes that will be used in footnote `b' planning
decisions are already in place, as implemented by FERC in Order No. 890
and in state regulatory jurisdictions.'' \14\ NERC also pointed to
state public utility commission processes or processes existing in
local jurisdictions that address transmission planning issues that
could serve to provide a case-specific review of the planned
interruption of Firm Demand. According to NERC, such processes would
more likely engage the appropriate local-level decision-makers and
policy-makers.
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    \14\ NERC Data Response at 4.
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    8. With respect to review and oversight by NERC and the Regional
Entities, NERC submitted that an ERO-specific process would place the
ERO in the position of managing and actively participating in a
planning process, which conflicts with its role as the compliance
monitor and enforcement authority. NERC also stated that neither the
ERO nor the Regional Entities will review decisions regarding planned
interruptions. Their role will be limited to reviewing whether the
registered entity participated in a stakeholder process when planning
to interrupt Firm Demand. NERC explained that Regional Entities will
have oversight after-the-fact by auditing the entity's implementation
of footnote `b' to determine if the entity planned on interrupting Firm
Demand and whether the decision by the entity to rely on planned
interruption of Firm Demand was vetted through the stakeholder process
and qualified as one of the situations identified in footnote `b.'
    9. Furthermore, NERC stated that an objective of the planning
process should be to minimize the likelihood and magnitude of planned
Firm Demand interruptions. NERC contended that, due to the wide variety
of system configurations and regulatory compacts, it is not feasible
for the ERO to develop a one-size-fits-all criterion for limiting the
planned firm load interruptions for Category B events. According to
NERC, the standards drafting team evaluated setting a certain magnitude
of planned interruption of Firm Demand, but there was no analytical
data to support a single value, and it would be viewed as arbitrary.

D. Notice of Proposed Rulemaking

    10. On October 20, 2011, the Commission issued a Notice of Proposed
Rulemaking (NOPR \15\) proposing to remand NERC's proposal to modify
footnote `b.' In the NOPR, the Commission stated that it believed that
NERC's proposal does not meet the directives in Order No. 693 and the
June 2010 Order and does not clarify or define the circumstances in
which an entity can plan to interrupt Firm Demand for a single
contingency. The Commission expressed concern that the procedural and
substantive parameters of NERC's proposed stakeholder process are too
undefined to provide assurances that the process will be effective in
determining when it is appropriate to plan for interrupting Firm
Demand, does not contain NERC-defined criteria on circumstances to
determine when an exception for planned interruption of Firm Demand is
permissible, and could result in inconsistent results in
implementation. The NOPR stated that the proposed footnote effectively
turns the processes into a reliability standards development process
outside of NERC's existing procedures. Furthermore, the NOPR stated
that regardless of the process used, the result could lead to
inconsistent reliability requirements within and across reliability
regions. While the Commission recognized that some variation among
regions or entities is reasonable, there are no technical or other
criteria to determine whether varied results are arbitrary or based on
meaningful distinctions.
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    \15\ Transmission Planning Reliability Standards, Notice of
Proposed Rulemaking, 76 FR 66229 (Oct. 20, 2011), FERC Stats. &
Regs. ] 32,683 (2011).
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    11. The Commission proposed to provide further guidance on
acceptable approaches to footnote `b' and sought comment on certain
options for revising footnote `b', as well as other potential options
to solve the concerns outlined in the NOPR. In response to the NOPR,
comments were filed by seventeen interested parties.\16\
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    \16\ NERC, The Edison Electric Institute (EEI), American Public
Power Association (APPA), National Association of Regulatory Utility
Commissioners (NARUC), ITC Holdings Corp. (ITC), Manitoba Hydro,
California Department of Water Resources State Water Project
(California SWP) Hydro One Networks, Inc and the Ontario Independent
Electricity System Operator (Hydro One and IESO), Duke Energy
Corporation (Duke), New York State Public Service Commission
(NYPSC), Bonneville Power Administration (BPA), Kansas City Power &
Light Company and KCP&L Greater Missouri Operations Company (KCPL),
Midwest Independent System Operator, Inc. (MISO), Public Utility
District No. 1 of Snohomish County, Washington (Snohomish),
Transmission Access Policy Study Group (TAPS), Powerex Corp.
(Powerex), and Florida Reliability Coordinating Council (FRCC).
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II. Discussion

    12. For the reasons discussed below, the Commission concludes that
NERC's proposed TPL-002-0b does not meet the Commission's Order No. 693
directives, nor is it an equally effective and efficient alternative.
Further, the Commission finds that the proposal is vague, potentially
unenforceable and may lack safeguards to produce consistent results. On
this basis, the Commission remands the proposal to NERC as unjust,
unreasonable, unduly discriminatory or preferential and not in the
public interest. Below, the Commission also provides guidance on
acceptable approaches to footnote `b.'
    13. The Commission adopts the proposed NOPR finding that the
footnote `b' process lacks adequate parameters. The Reliability
Standard requires that, when planning to interrupt Firm Demand, the
Firm Demand interruption must be ``subject to review in an open and
transparent stakeholder process that includes addressing stakeholder
comments.'' \17\ Without meaningful substantive parameters governing
the stakeholder process, the enforceability of this obligation by NERC
and the Regional Entities would be limited to a review to ensure only
that a stakeholder process occurred. As NERC explained, Regional
Entities' involvement is limited to after-the-fact oversight by
auditing the entity's implementation of footnote `b' to determine if
the entity planned on interrupting Firm Demand and whether the decision
by the entity to rely on planned interruption of Firm Demand was vetted
through the stakeholder process and qualified as one of the situations
identified in footnote `b.' \18\
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    \17\ NERC Petition at 10.
    \18\ NERC Data Response at 7-9.

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    14. Further, the NERC proposal leaves undefined the circumstances
in which it is allowable to plan for Firm Demand to be interrupted in
response to a Category B contingency. The Commission believes that
proposed footnote `b' could be used as a means to override the
reliability objective and system performance requirements of the TPL
Reliability Standard without any technical or other criteria specified
to determine when planning to interrupt Firm Demand would be allowable,
and without violating any of the requirements of the TPL Reliability
Standard. The TPL Reliability Standard requires that a planner
demonstrate through a valid assessment that the transmission system is
planned and can be operated to supply projected Firm Demand at all
demand levels over a range of forecasted system demands.\19\ In
addition, a planner must consider all single contingencies under Table
1, Category B and demonstrate system performance.\20\ For single
contingency events where system performance is not met, a planner must
provide a written summary of its plans to achieve system performance
including implementation schedules, in service dates of facilities and
implementation lead times.\21\
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    \19\ Reliability Standard TPL-002-0b, Requirement R1.
    \20\ Reliability Standard TPL-002-0b, Requirement R1.3.7.
    \21\ Reliability Standard TPL-002-0b, Requirement R2.
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    15. However, if system performance is not met for any single
contingency event(s) under NERC's proposed footnote `b,' a planner
could plan to interrupt some portion of Firm Demand to meet system
performance requirements thereby overriding the performance
requirements of the TPL Reliability Standard. For example, if a planner
determines during its annual assessment that for a single bulk-power
system transformer contingency other bulk-power system elements would
exceed their thermal ratings, a planner would have authority under the
standard to plan to interrupt Firm Demand to relieve the exceeded
thermal ratings of the bulk-power system elements rather than planning
the system to withstand such a single contingency and avoid shedding
firm load as the performance requirements of the TPL Reliability
Standard require. Therefore, without articulating some bounds on the
use of the planned shedding of Firm Demand, there could be instances of
multiple exceptions that could affect the robustness of the system.
Further, contrary to commenters contentions, NERC's proposal, for
example, has no provision to evaluate this cumulative effect of the
individual decisions to shed firm.\22\
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    \22\ BPA Comments at 5 (``The reasons for interrupting Firm
Demand would be documented in studies and demonstrate that there
would be no adverse impact to the BPS''); FRCC Comments at 3
(``Indeed, the transmission planning entity is responsible as part
of the system assessment process under the TPL standards to test
remedies to ensure that they address the problems being caused and
do not cause additional problems.''); and Hydro One Comments at 5
(``Loss of load is under the purview of the regulatory authority and
not NERC, unless it has an adverse impact on the BES which is
already taken into consideration by the TPL standards * * * In all
cases, steps are taken in planning, design and operations of the
system to ensure that Firm Demand shedding would not adversely
impact the BES * * *'').
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    16. The Commission disagrees with commenters that NERC's proposed
footnote `b' will have no adverse impact on reliable planning of the
bulk-power system because planning to shed Firm Demand is intended to
ensure that single contingency events do not result in adverse impacts
and intended to preserve bulk-power system reliability.\23\ Table 1 of
the TPL Reliability Standard identifies the system performance
requirements or ``System Limits or Impacts'' that a planner must apply
during its assessment of Category B, single contingency events.\24\
Except in limited circumstances, if a planner determines that it must
plan to interrupt Firm Demand so that it does not violate the Table 1
system performance requirements, a planner should not apply footnote
`b' as a mitigation plan to plan to operate reliably. The Commission
therefore is concerned that NERC's proposal provides authority to
adjust the TPL Reliability Standard and its system performance
requirements for each single contingency event that does not meet the
system performance requirements of Table 1.
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    \23\ See, e.g., NERC Comments at 11, TAPS Comments at 10, APPA
Comments at 6.
    \24\ Reliability Standard TPL-002-0b, Table 1, Transmission
System Standards--Normal and Emergency Conditions. Table 1
identifies the system performance requirements or ``System Limits or
Impacts'' which are as follows: ``System Stable and both Thermal and
Voltage Limits within Applicable Rating'', ``Loss of Demand or
Curtailed Firm Transfers'' and ``Cascading Outages.''
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    17. Further, NERC has not provided technically sound means of
determining situations in which planning to interrupt Firm Demand would
be allowable. While NERC expects that such determinations will be made
in a stakeholder process, this provides no assurance that such a
process will use technically sound means of approving or denying
exceptions. The Commission concludes that the multiple stakeholder
processes across the country engaging in such determinations could lead
to inconsistent and arbitrary exceptions including, potentially,
allowing entities to plan to interrupt any amount of Firm Demand in any
location and at any voltage level.
    18. While the Commission recognizes that some variation among
regions or entities is reasonable given varying grid topography and
other considerations, there are no technical or other criteria to
determine whether varied results are arbitrary or based on meaningful
distinctions. The Commission, thus, concludes that NERC's proposal
lacks safeguards to ensure against inconsistent results and arbitrary
determinations to allow for the planned interruption of Firm Demand.
    19. A remand gives NERC and industry flexibility to develop an
approach that would address the issues identified by the Commission
with the proposed footnote `b' stakeholder process including, as
discussed below, definition of the process and criteria or guidelines
for the process.
    20. The Commission believes that, on remand, both NERC and the
Commission will benefit from a more complete record regarding the
electric industry's reliance on planned Firm Demand interruptions. In
response to the Commission's request to explain and quantify the extent
to which Firm Demand is planned to be interrupted pursuant to
currently-effective footnote `b,' NERC explained:

    NERC and the Regional Entities have not collected statistics or
preformed a survey concerning the prospective implementation of
Footnote b under TPL-002-0a. During the drafting team's
deliberations concerning TPL-001-2 and TPL-002-0a Footnote b,
including the NERC Technical Conference on Footnote b, the informal
assessments demonstrated that the use of Footnote b would not be
widespread.\25\
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    \25\ NERC Data Response at 10.

    Likewise, several commenters state that the interruption of Firm
Demand is rarely needed, but provide no support for this
conclusion.\26\ For example, EEI asks the Commission to ``recognize''
that ``* * * the actions taken as outcomes of the planning review
process, are likely to identify few/isolated circumstances in which
these [footnote b] provisions would be invoked* * *.'' \27\ However,
the Commission believes that more specific information regarding the
specific circumstances and frequency with which Firm Demand is planned
to be interrupted will assist both NERC in developing, and the
Commission in reviewing, appropriate revisions to

footnote `b' on remand. Therefore, pursuant to section 39.2(d) of the
Commission's regulations,\28\ we direct NERC to identify the specific
instances of any planned interruptions of Firm Demand under footnote
`b' and how frequently the provision has been used. We direct NERC to
use section 1600 of its Rules of Procedure to obtain information from
users, owners and operators of the bulk-power system to provide this
requested data.\29\ NERC shall submit this information to the
Commission with NERC's footnote `b' filing that addresses the concerns
in this Final Rule.
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    \26\ See, e.g., FRCC Comments at 4; MISO Comments at 4; BPA
Comments.
    \27\ EEI Comments at 2.
    \28\ 18 U.S.C. 39.2(d).
    \29\ NERC Rules of Procedure, Section 1601 (effective January
31, 2012).
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    21. We urge NERC to develop in a timely manner an appropriate
modification that is responsive to the Commission's directives in Order
No. 693 and our concerns set forth in this Final Rule. In that regard,
we require NERC to deploy its Expedited Reliability Standards
Development Process to quickly respond to the remand. As the Commission
noted in previous orders, the use of planned or controlled load
interruption is a fundamental reliability issue and, certainty
regarding the loss of non-consequential load for a single contingency
event is warranted.\30\ Thus, using the Expedited Standards Development
Process will more rapidly bring needed certainty to this fundamental
reliability issue.
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    \30\ North American Electric Reliability Corp., 130 FERC ]
61,200 (2010) (March 2010 Order); North American Electric
Reliability Corp., 131 FERC ] 61,231 (2010) (June 2010 Order).
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    22. Below we discuss three concerns: (a) Jurisdictional issues, (b)
lack of technical criteria, and (c) the stakeholder process. The
Commission also provides guidance on other acceptable approaches.

A. Jurisdictional Issues

    23. A number of commenters express concern that the Commission is
reaching beyond its FPA section 215 jurisdiction.\31\ Commenters assert
that the Commission options exceed its jurisdiction involving
acceptable levels and types of service. Commenters seek assurance that
the Commission's proposal does not infringe on matters reserved to the
States and instead ``only prescribe acceptable load shedding as it
pertains to wholesale customers that are in a position to select
interruptible or conditional firm transmission service.'' \32\ NARUC
states that ``any NERC standard for shedding distribution level load
must be guided by States and that a demonstration that interruption of
the load will not cause instability, uncontrolled separation, or
cascading failures on the bulk system is appropriate for a NERC
standard.'' \33\ NARUC adds that specifications of what retail load and
what levels of retail load can be interrupted is a State determination
that is not reviewable by the Commission. TAPS agrees with NERC that
issues pertaining to whether it is permissible to plan to interrupt
firm load involves conflicts among federal, provincial, state, and
local governing bodies.\34\
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    \31\ See, e.g., Comments of NERC, NARUC, APPA and TAPS.
    \32\ NYPSC Comments at 5.
    \33\ NARUC Comments at 3-4.
    \34\ TAPS Comments at 9.
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    24. The Commission disagrees that it is infringing on State
Commissions or overstepping jurisdictional bounds. In this Final Rule,
the Commission remands NERC's proposed footnote `b' as an inadequate
mechanism to address planned curtailment of firm demand and not
responsive to the Commission's directives in Order No. 693 regarding
this matter. The Commission is not directing that NERC develop a
specific solution or approach on remand. Thus, our remand of the NERC
proposed modification to TPL-002-0b, Table 1, footnote `b' is fully
within the Commission's authority pursuant to section 215(d)(4) to
remand to the ERO for further consideration a modification to a
proposed reliability standard that the Commission disapproves in whole
or in part. Moreover, FPA section 215 gives the Commission jurisdiction
over mandatory Reliability Standards to ensure reliability of the Bulk-
Power System.\35\ Consistent with its statutory authority, the
Commission's interest and focus in this proceeding is on the planned
interruption of Firm Demand on the Bulk-Power System. The Commission
views this matter in the context of Reliability Standard TPL-002-0b,
which requires that in planning the system to withstand the loss of a
single Bulk-Power System element, Bulk-Power System performance
criteria must be met. If it is not met, a corrective action plan is
required to address the Bulk-Power System performance criteria
violation. Contingencies studied pursuant to Reliability Standard TPL-
002-0b pertinent to Bulk-Power System facilities are subject to
Commission jurisdiction under FPA section 215. In sum, the performance
of the Bulk-Power System under the TPL-002-0b Reliability Standard is
within the Commission's jurisdiction.
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    \35\ 16 U.S.C. 824o(b)(1).
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B. Lack of Technical Criteria

NOPR Proposal
    25. In the NOPR, the Commission proposed to remand NERC's proposal
to modify Reliability Standard TPL-002-0b, Table 1, footnote `b.' The
Commission stated that it believed that NERC's proposal does not meet
the directives in Order No. 693 and the June 2010 Order and does not
clarify or define the circumstances in which an entity can plan to
interrupt Firm Demand for a single contingency.\36\ In the NOPR the
Commission expressed concern that NERC's proposed footnote `b' lacks
parameters. Without any substantive parameters governing the
stakeholder process, the enforceability of this obligation by NERC and
the Regional Entities would be limited to a review to ensure only that
a stakeholder process occurred. The Commission noted that NERC appears
to confirm this concern, as NERC explained that Regional Entities'
involvement is limited to after-the-fact oversight by auditing the
entity's implementation of footnote `b' to determine if the planned
interruption of Firm Demand was vetted through the stakeholder
process.\37\
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    \36\ NOPR, FERC Stats. & Regs. ] 32,683 at P 11.
    \37\ Id. P 12.
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    26. Further, in the NOPR the Commission stated that since the
proposed footnote `b' contains no constraints, it could allow an entity
to plan to interrupt any amount of planned Firm Demand, in any location
or at any voltage level as needed for any single contingency, provided
that it is documented and subjected to a stakeholder process. The
Commission found this result remains contrary to the underlying
Reliability Standard and prior Commission orders.\38\ The Commission
requested comment on this specific concern of the lack of technical
criteria or parameters.
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    \38\ Id.
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Comments
    27. Some commenters agree with the Commission that there is lack of
technical criteria to determine planned interruption of Firm Demand.
For example, California SWP states that Reliability Standards ``should
ensure transparent criteria based on technical merits and not software
limitations derived from a desire to mask [locational marginal pricing]
price signals with socialized pricing or on status quo practices.''
\39\ ITC believes that there is a need for defined parameters that will
guide the review of exceptions and that will prevent

planned interruptions from becoming commonplace.\40\ Manitoba Hydro
states that the characteristics of openness and transparency are
indicators of a non-discriminatory planning process; however, these
characteristics do not ensure that certain reliability criteria of the
planned facilities will be met.\41\
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    \39\ California SWP Comments at 4.
    \40\ ITC Comments at 2.
    \41\ Manitoba Hydro Comments at 6.
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    28. Other commenters disagree with the Commission's concern that
there is a lack of criteria to determine planned interruption of Firm
Demand. NERC states that it does not believe that an exceptions process
that provides defined criteria, with some allowances, could be crafted
that would respect pre-existing decision making processes that occur at
state and local jurisdictions. NERC argues that the decision to
interrupt local load is essentially an economic decision--a quality of
service issue, not a reliability issue.\42\
---------------------------------------------------------------------------

    \42\ NERC Comments at 13.
---------------------------------------------------------------------------

    29. MISO disagrees that additional language would reduce the
potential for inconsistent results and points out that registered
entities already have many established requirements that govern the
transmission planning processes.\43\ MISO believes that if the
Commission determines that criteria are needed, such criteria should be
determined by the stakeholders in the regions though their established
stakeholder processes.\44\ EEI does not believe that specific criteria
should be developed until a better understanding is obtained regarding
the role of service interruptions as a reliability tool.\45\ EEI
believes that these are appropriate aspects of the NERC proposal that
would be readily amenable to an initial implementation approach,
followed by an adjustment period that would refine the overall process
consistent with the Commission's concerns.
---------------------------------------------------------------------------

    \43\ MISO Comments at 3.
    \44\ Id. at 5.
    \45\ EEI Comments at 10.
---------------------------------------------------------------------------

Commission Determination
    30. We believe that openness and transparency do not alone ensure
that bulk electric system performance criteria will be met to ensure
system reliability. The Commission is not persuaded that developing
technical criteria is unachievable. As the Commission observed in the
NOPR, NERC has thresholds in other reliability contexts, such as
vegetation management pursuant to Reliability Standard FAC-003-1 which
applies to all transmission lines operated at 200 kV and above.
Likewise, NERC's Statement of Compliance Registry Criteria includes
numerous thresholds for determining eligibility for registration.\46\
---------------------------------------------------------------------------

    \46\ See, e.g., NERC Statement of Registry Criteria, section
III. The Commission approved the Statement of Registry Criteria in
Order No. 693. See Order No. 693, FERC Stats. & Regs. ] 31,242 at P
95.
---------------------------------------------------------------------------

    31. The Commission does not agree with EEI's recommendation to
implement a stakeholder process that is absent technical criteria but
then amend it later. While the Commission has, in other circumstances,
approved a Reliability Standard and, as a separate action, directed
NERC to develop a modification pursuant to section 215(d)(5) of the
FPA, in such proceedings the Commission concluded that the proposed
Reliability Standard was just, reasonable, not unduly discriminatory or
preferential and in the public interest. In the immediate proceeding,
however, we cannot make such a finding in light of the flawed
stakeholder process provision.
    32. In response to MISO's argument that such criteria should be
determined by the stakeholders in the regions though their established
stakeholder processes, the Commission would be amenable to such an
approach if, for example, NERC and/or the Regional Entities developed
an exception process that provides flexibility in decisions based on
disparate topology or on other matters since they could utilize their
technical expertise to determine the reliability impact from one region
to another. For these reasons, the Commission concludes that a more
defined process is needed with NERC-defined technical criteria to
determine planned interruption of Firm Demand. However, we conclude
that the approach of allowing a decentralized process without any
overarching parameters is unacceptable.
    33. With regard to NERC's comment that the decision to interrupt
local load is essentially an economic decision that is a quality of
service issue, not a reliability issue, the Commission notes that in
Order No. 693, we dismissed the argument that it may be preferable to
plan the bulk electric system in such a manner that contemplates the
interruption of some firm load customers in the event of a N-1
contingency, and that such interruption is based largely on the matter
of economics, not reliability.\47\
---------------------------------------------------------------------------

    \47\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1792.
---------------------------------------------------------------------------

C. Stakeholder Process

NOPR Proposal
    34. In the NOPR, the Commission expressed concern that NERC's
proposed footnote `b' stakeholder process is insufficient to meet Order
No. 693 and the June 2010 Order clarification that a regional
difference, or a case-specific exception process that can be
technically justified, to plan for the loss of firm services at the
fringes of the systems is acceptable in limited circumstances.\48\ The
Commission also noted that nothing in the proposed footnote `b' defines
the stakeholder process, other than that it must be an open and
transparent stakeholder process that includes addressing stakeholder
comments.\49\ The Commission noted that any meeting that is open to
stakeholders could meet this criteria.
---------------------------------------------------------------------------

    \48\ NOPR, FERC Stats. & Regs. ] 32,683 at P 19.
    \49\ Id. P 20.
---------------------------------------------------------------------------

    35. The Commission further stated that the lack of a defined
stakeholder process could allow a transmission planner to develop a
process that provides insufficient opportunity for stakeholder
participation and transparency yet still comply with the standard. The
Commission expressed its belief that nothing in the proposed footnote
`b' restricts the stakeholder process, other than that it must be an
open and transparent stakeholder process that includes addressing
stakeholder comments. The Commission requested comment on whether a
stakeholder process is the appropriate vehicle to approve or deny
exceptions to allow entities to plan to interrupt Firm Demand for a
single contingency and if so, whether the proposed footnote `b' would
require any stakeholder due process.
Comments
    36. Several commenters believe that NERC's proposed stakeholder
process is the appropriate venue to approve or deny exceptions to
interrupt planned Firm Demand. NERC and other commenters contend that
building on existing stakeholder processes is appropriate, rather than
creating new, duplicative processes. While EEI, APPA, and TAPS concur
with or acknowledge the Commission's concerns about the inadequacy of
the proposed stakeholder process, they nonetheless urge the Commission
to approve NERC's proposal stating that it reflects the considered
expertise that instances of planned load shed are uncommon and not
amenable to a one-size-fits-all approach.\50\ NERC believes the
introduction of an additional planning process may contribute to
further delays and regulatory confusion. NERC states

that ``keeping decision-making with those most impacted by decisions
regarding reliability and costs, lack of jurisdictional authority, and
the existence of established open and transparent stakeholder
processes--are the reasons NERC did not create a new stakeholder
process.'' \51\
---------------------------------------------------------------------------

    \50\ See, e.g., EEI Comments at 3, TAPS Comments at 5, APPA
Comments at 3.
    \51\ NERC Comments at 12.
---------------------------------------------------------------------------

    37. Duke Energy believes that the current Order No. 890-type
process involving the local transmission planning collaborative is the
appropriate stakeholder process. Duke Energy suggests that footnote `b'
should be revised to include a local regulatory authority process as
the appropriate stakeholder process to allow entities to plan to
interrupt Firm Demand for a single contingency. According to Duke
Energy, in such a process a transmission planner would submit its plan
to interrupt Firm Demand for a single contingency to its local
regulatory authority that has jurisdiction over quality of service to
local load prior to any actual interruption of Firm Demand.
    38. BPA states that the stakeholder process will keep the decision
local, where the parties involved understand the different factors that
must be considered in deciding the proper path forward.\52\ APPA
maintains that these processes impose due process requirements on the
transmission planner, including participation in an open and
transparent stakeholder process that considers stakeholder
comments.\53\
---------------------------------------------------------------------------

    \52\ BPA Comments at 4.
    \53\ APPA Comments at 5.
---------------------------------------------------------------------------

    39. FRCC disagrees with the Commission that enforceability is
limited since the process requires development of a record documenting
the decisions and stakeholder comments and planning authority
responses. According to FRCC, the result will provide NERC and the
Commission substantive and procedural grounds to assess whether
sufficient consideration was given to maintaining reliability.\54\
---------------------------------------------------------------------------

    \54\ FRCC Comments at 3.
---------------------------------------------------------------------------

    40. Some commenters believe that NERC's proposed stakeholder
process is not the appropriate vehicle to approve or deny exceptions to
interrupt planned Firm Demand. ITC argues that the stakeholder process
is inadequately undefined to ensure that planned Firm Demand
interruptions are kept to a minimum. Manitoba Hydro indicates that by
acknowledging an exception for interruptible Firm Demand, NERC appears
to recognize that the right to interrupt is not solely a reliability
issue, but also a commercial or legal issue based on contractual
rights.\55\
---------------------------------------------------------------------------

    \55\ Manitoba Hydro Comments at 5.
---------------------------------------------------------------------------

    41. While TAPS encourages the Commission to accept NERC's proposed
footnote `b,' it shares the NOPR's concerns about the adequacy of the
open and transparent stakeholder process and has argued for a decision-
making role for transmission-dependent utilities in the Order No. 890
and Order No. 1000 planning processes to ensure that stakeholder
processes do not result in a presentation of a decision followed by the
transmission provider simply ``rubber-stamping'' the decision.\56\ If
the Commission determines that these objectives cannot be accomplished
without more robust action from the Commission in this proceeding, TAPS
urges the Commission not to remand the proposed footnote `b,' but
instead to accept NERC's proposal and direct NERC to submit a further
modified footnote `b' to address the parameters of the ``open and
transparent stakeholder process that includes addressing stakeholder
comments.'' \57\
---------------------------------------------------------------------------

    \56\ TAPS Comments at 5.
    \57\ Id. at 11.
---------------------------------------------------------------------------

Commission Determination
    42. The Commission is not persuaded that the stakeholder process is
adequately defined. The Commission is concerned that the stakeholder
process could undermine the system performance criteria of TPL-002-0b
Reliability Standard. As the Commission stated in Order No. 693, one of
the key reliability objectives of the TPL Reliability Standard is that
the system can be operated following the loss of one element and supply
projected firm customer demands and projected firm transmission
services at all demand levels over the range of forecast system
demands.\58\ The Commission finds that the stakeholder process without
appropriate parameters is inconsistent with the reliability objective
to supply projected firm customer demands for the loss of one element.
While the Reliability Standard requires that the system is planned so
that the system can be operated following the loss of one element and
supply projected firm customer demands, the proposed stakeholder
process could defeat this by allowing a transmission planner to plan to
shed as much load as needed so that the system can be operated to
supply whatever customers remain.
---------------------------------------------------------------------------

    \58\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1771.
---------------------------------------------------------------------------

    43. The Commission agrees with TAPS to the extent it observes that
the proposal could allow a transmission planner to utilize a new or
existing stakeholder process that provides insufficient opportunity for
a stakeholder to provide meaningful input. We conclude that the
stakeholder process with no criteria to objectively assess whether
varied results are arbitrary or based on meaningful differences is
unjust, unreasonable, unduly discriminatory or preferential, and not in
the public interest. Nothing in proposed footnote `b' defines the
stakeholder process, other than it must be an open and transparent
stakeholder process that includes addressing stakeholder comments.
    44. The Commission is not persuaded by FRCC's comment that
enforceability is not limited by proposed footnote `b' and that
development of a record will provide NERC ``substantive and
procedural'' grounds to assess the outcome of the process. Neither FRCC
nor any other commenter identifies the minimum procedural safeguards to
assure an adequate level of stakeholder participation and consideration
of stakeholder comment in the decision-making process. Moreover, even
NERC, which states that it can conduct after-the-fact audits, indicates
that such audits would not explore substantive adequacy or the
reliability basis for a decision to plan to shed Firm Demand.\59\
Further, the Commission is not persuaded by APPA and BPA comments that
local stakeholder participation and due process requirements imposed on
the transmission planner are sufficient. Rather, the Commission
believes that if a transmission planner invokes a process that provides
for minimal stakeholder involvement, it could argue that it satisfied
the provision, even if the transmission planner is the ultimate
decision maker and simply `rubber stamps' its own proposal to interrupt
planned Firm Demand.
---------------------------------------------------------------------------

    \59\ NERC Data Response at 7-9.
---------------------------------------------------------------------------

D. Guidance on Acceptable Approaches to Footnote `b'

    45. The Commission proposed three options in the NOPR for further
guidance on acceptable approaches to footnote `b.' In addition, the
Commission requested comment on other potential options to solve the
concerns outlined in the NOPR.
1. Existing Protocols To Develop Criteria/Quantitative Limits
    46. In the NOPR, the Commission acknowledged that NERC considered a
variety of limits but observed that NERC's establishment of some form
of

criteria for planning to interrupt Firm Demand could be an acceptable
approach for footnote `b.' The Commission requested comment on whether
existing protocols such as the Department of Energy's Electric
Emergency Incident and Disturbance Report (Form OE-417), which requires
an entity to report a certain amount of uncontrolled loss of firm
system loads, or NERC's Statement of Compliance Registry Criteria could
provide guidance to NERC to devise criteria.
Comments
    47. Commenters were unanimous that the examples of existing
protocols would not be beneficial to devise criteria. NERC and others
state that any bright-line megawatt limit would be inappropriate
because the bright-line would be arbitrary.\60\ Some commenters do not
believe that existing protocols, such as the requirement in Form OE-417
should be used to determine criteria related to planned loss of Firm
Demand.\61\
---------------------------------------------------------------------------

    \60\ NERC Comments at 14.
    \61\ ITC Comments at 5; see also Hydro One and IESO Comments.
---------------------------------------------------------------------------

    48. BPA, ITC, and Duke Energy comment that setting a quantitative
limit would push transmission planners to plan to meet such a limit for
a single contingency in all cases. Currently, transmission planners
start from the premise that no load should be interrupted in the event
of a single contingency. ITC believes that including such an acceptable
lost load criterion as an option could lead to that option being chosen
as the ``default solution,'' i.e., allowing for a certain amount of
acceptable interruption of Firm Demand without a stakeholder exception
review process.\62\ In the same vein, Duke indicates that a specific
megawatt threshold may prohibit certain interruptions of Firm Demand
that would be acceptable from a quality of service and local
consequences perspectives.\63\
---------------------------------------------------------------------------

    \62\ ITC Comments at 5.
    \63\ Duke Comments at 6.
---------------------------------------------------------------------------

Commission Determination
    49. The Commission is persuaded by the commenters that Form OE-417
or the Registry Criteria are not, by themselves, beneficial to use to
devise criteria. The Commission also agrees that a bright-line criteria
by itself does not present a viable option and would have the potential
to constitute an acceptable de facto interruption and become
commonplace to plan to interrupt Firm Demand. For example, if the
bright-line criteria included up to 50 MW of planned interruptible Firm
Demand under proposed footnote `b', then planners may choose to
automatically shed up to 50 MW of load as their first course of action
for any single contingency event that would cause a violation of system
performance criteria. This is not an acceptable outcome.
2. A Blend of Quantitative and Qualitative Thresholds
    50. The Commission also sought comment on whether a blend of
quantitative and qualitative thresholds to be used to interrupt planned
Firm Demand would be an appropriate option for providing criteria that
would be generally applicable, but also for allowing for certain cases
that may exceed the criteria. For example, a Reliability Standard could
require a process with a quantitative limitation on how much Firm
Demand could be planned for interruption and the standard could provide
an exception process where a registered entity would submit documents
and explanation to the ERO or a Regional Entity for approval based upon
certain considerations.\64\ The Commission suggested that setting
generally applicable criteria for when an applicable entity can plan to
shed Firm Demand, coupled with an exceptions process overseen by NERC
and the Regional Entities, could mean that few exception requests must
be processed by NERC and the Regional Entities.\65\ The Commission
observed in the NOPR that this approach may satisfy the need for
technical criteria while accounting for NERC's concerns about the
difficulty of developing a one-size-fits-all criterion for limiting
planned Firm Demand interruptions and the appropriateness and
feasibility of managing and actively participating in each planning
process.
---------------------------------------------------------------------------

    \64\ NOPR, FERC Stats. & Regs. ] 32,683 at P 18.
    \65\ Id. P 27.
---------------------------------------------------------------------------

Comments
    51. California SWP indicates that standards must constrain the use
of firm load shedding as a reliability solution in transmission
planning and at the same time, require a transparent and clearly
defined stakeholder process to support any such planned use of load
shedding for single contingency events.\66\ BPA suggests that, if the
Commission does set a quantitative limit on planned interruption of
Firm Demand, a limit based on a fraction of aggregated normal peak load
would be one option that may be more effective and adaptable to all
sizes of utilities.\67\
---------------------------------------------------------------------------

    \66\ California SWP Comments at 2.
    \67\ BPA Comments at 4.
---------------------------------------------------------------------------

    52. Other commenters disagree that a blend is a good option. NARUC
indicates that rather than inventing another stakeholder process by
requiring NERC to set specific quantitative or qualitative requirements
for distribution load shedding, NERC should look to State commissions
and existing State curtailment plans to guide load shedding in
contingency planning.\68\ Duke Energy submits that a blend of
quantitative and qualitative thresholds does not provide enough
flexibility to permit the qualitative assessment of the loads and
locations for which transmission planners may interrupt under their
exercise of footnote `b' because a blended threshold may still rely too
heavily on a quantitative threshold for planned interruption of Firm
Demand.\69\ FRCC states it is not feasible to develop a single
quantitative rule that would apply equitably to all stakeholders and
regions.\70\
---------------------------------------------------------------------------

    \68\ NARUC Comments at 3.
    \69\ Duke Energy Comments at 7.
    \70\ FRCC Comments at 7.
---------------------------------------------------------------------------

    53. EEI believes that adopting a process that would provide greater
clarity, reporting, and refinement would provide the specific
information on the extent that the footnote `b' issue presents itself.
EEI also agrees with NERC that efforts to create a one-size-fits-all
approach have less value than a process that ensures openness and
transparency.
Commission Determination
    54. The Commission believes that setting a quantitative and
qualitative threshold in developing a limited exception for planned
interruption of Firm Demand may be a workable solution. First,
qualitative thresholds could be used to overcome the concern discussed
immediately above regarding the quantitative threshold becoming an
acceptable de facto interruption of planned Firm Demand. By utilizing a
blend, the planner must also meet the qualitative threshold which could
consist of, for example, the submittal of documents and explanation to
the entity ultimately deciding whether the planned load shed is
acceptable. For example, if 100 MW of planned Firm Demand was permitted
to be interrupted, the planner could not automatically and unilaterally
shed up to 100 MW of planned Firm Demand each time system performance
criteria would be violated. Under the blend concept, the Commission
envisions that

the planner would consider up to 100 MW of planned Firm Demand
interruption along with other options to resolve the system performance
criteria violation and submit its documentation and explanation to the
entity deciding whether the planned load shed is acceptable. The
concept of a blend of thresholds would prevent an acceptable de facto
interruption of planned Firm Demand and avoid the difficulty of
developing a one-size-fits-all criterion for limiting planned Firm
Demand interruptions, but still allow for those limited circumstances
to be reviewed in an exception process where a limited amount of
planned interruption of Firm Demand may be acceptable.
    55. We believe it is appropriate for the Regional Entities, with
NERC as the final authority, to make determinations under a ``blended''
exception process. First, NERC and the Regional Entities provide both
objectivity in the decision-making process as well as the necessary
reliability-focused expertise. Second, this should not overly burden
NERC or Regional Entity resources as utilization of the planned load
shed exception is--and would be--rarely utilized.\71\ Further, we are
not persuaded by the assertion that NERC would be conflicted as the ERO
and also inserting itself in the process. NERC's ERO role would
continue, in coordination with its current responsibilities in
implementing other exceptions such as the Technical Feasibility
Exception process under the Critical Infrastructure Protection
Reliability Standards.
---------------------------------------------------------------------------

    \71\ See, e.g., FRCC Comments at 4; MISO Comments at 4; BPA
Comments.
---------------------------------------------------------------------------

    56. The Commission does not agree with BPA's suggestion of using
quantitative thresholds based on a fraction of aggregated normal peak
load. BPA's suggestion attempts to address the concerns of commenters
that a bright-line threshold must be established that would be a one-
size-fits-all criteria. For example, instead of a megawatt bright-line
threshold for all entities, the ERO could establish a threshold based
on a percentage of aggregated normal peak load. The Commission believes
that it would be difficult to demonstrate that adoption of BPA's
suggestion would be just and reasonable, not unduly discriminatory or
preferential and in the public interest. If criteria were established
that permitted a percentage of aggregated normal peak load as an
acceptable threshold for planned interruption of Firm Demand, even a
small percentage could equate to entire towns, cities or regions of
load.\72\ The Commission, therefore, does not support the planned
interruption of Firm Demand based on a fraction of aggregated normal
peak load. The Commission believes that an appropriate mechanism would
be based on impact studies that consider minimizing planned
interruption of Firm Demand within, and adjacent to, communities and
small localities.
---------------------------------------------------------------------------

    \72\ For example, the PJM aggregated normal system peak load is
approaching 160,000 MW, so a one percent threshold would equate to
allowance of planned interruption for a single contingency of up to
1600 MW of load, which is the size of some entire towns, cities or
regions.
---------------------------------------------------------------------------

    57. The Commission offers guidance to NERC to consider the option
of a blend of quantitative and qualitative thresholds. An example of a
qualitative threshold could include identifying geographical or
topological ``fringes of the system.'' While interruption at the
fringes of the system may be expected by some consumers, not all
customers necessarily have that same expectation. For example, we don't
expect that many water treatment facilities or telecom switching
stations normally plan to be interrupted for single contingency
events.\73\ While the Commission has offered one example of a
qualitative threshold, NERC may explore other qualitative thresholds on
remand. The Commission believes that a blend of quantitative and
qualitative thresholds coupled with an exception process overseen by
NERC and the Regional Entities would be a reasonable option to allow
for the limited interruption of planned Firm Demand. Accordingly, the
Commission directs the ERO to consider some blend of quantitative and
qualitative thresholds.
---------------------------------------------------------------------------

    \73\ While we anticipate that such facilities are prepared for
distribution-level blackouts, we are not aware that they are
prepared for a transmission-level blackout.
---------------------------------------------------------------------------

3. Customer or Community Consent
    58. In the NOPR the Commission also requested comment on whether a
feasible option would be to revise footnote `b' to allow for the
planned interruption of Firm Demand in circumstances where the
``transmission planner can show that it has customer or community
consent and there is no adverse impact to the Bulk-Power System.'' \74\
The Commission suggested that this would not require affirmative
consent by every individual retail customer, but would recognize that
either group would need to be adequately defined. The Commission
requested comments on who might be able to represent the customer or
community in this option and how customer or community consent might be
demonstrated.\75\ The Commission also requested comment on how it would
be determined that firm demand shedding with customer consent would not
adversely impact the Bulk-Power System. Additionally, the Commission
requested comment on whether a customer who would otherwise consent to
having its planning authority or transmission planner plan to interrupt
Firm Demand pursuant to this option could instead select interruptible
or conditional firm service under the tariff to address cost concerns.
---------------------------------------------------------------------------

    \74\ NOPR, FERC Stats. & Regs. ] 32,683 at P 28.
    \75\ Id.
---------------------------------------------------------------------------

Comments
    59. Several commenters agreed with the Commission that the customer
or community consent should be required. ITC believes the customers or
entities should be involved in a stakeholder process such as a
representative group for the affected load or customers (community
representatives or a separate load serving entity where the
transmission provider is not an integrated utility), the public
service/utility regulatory commission for the affected load, the RTO or
ISO for the affected area, and any other affected entity. California
SWP also supports notice to and consent of loads (or their wholesale
representatives) that are planned to be interrupted for the loss of a
single element.\76\ In its comments, California SWP explains that it
was ``surprised to learn that in lieu of transmission upgrades, [its
transmission planner] relied on interruption of SWP's large firm pump
loads supposedly receiving the same California Independent System
Operator (CAISO) transmission service as provided to SCE loads. At that
time, SWP was not consulted about the planned curtailment of its firm
loads as an alternative to a transmission upgrade, and thus had no
opportunity to correct this error.'' \77\
---------------------------------------------------------------------------

    \76\ California SWP Comments at 4.
    \77\ Id. at 2-3.
---------------------------------------------------------------------------

    60. Other commenters disagree that customer or community consent
should be required. NERC states that it has no relationship with retail
customers and, therefore, has no mechanism to bring retail customers
into the conversation. NERC adds that both wholesale and retail
customers are already involved in state processes which provide a forum
for them to be heard.
    61. Hydro One and the IESO submit that customer interests are
managed by the relevant regulatory authority and consent is through
regulatory approval. In all cases, steps are taken in planning, design,
and operations of the system to

ensure that Firm Demand shedding would not adversely impact the bulk
electric system in addition to the fact that the customer also has
other options such as to select interruptible service. NYPSC recommends
that the Commission only prescribe acceptable load shedding as it
pertains to wholesale customers that are in a position to select
interruptible or conditional firm transmission service under
Commission-approved tariffs.
    62. FRCC states that the evaluation of the possible use of
interruptible or conditional firm service instead of planned
interruptions of Firm Demand is not warranted. According to FRCC, the
adoption of a Firm Demand interruption alternative would inherently
entail customer benefits from foregone project costs and the non-
incurrence of environmental and other impacts. The customers would also
generally enjoy a higher quality of service than traditional
interruptible or conditional firm. Consequently, FRCC believes that
applying any such rate in place of Demand interruption would present
imponderable issues of quantification and application.
    63. BPA does not believe that this proceeding is appropriate to
decide issues related to service choice. BPA argues that the Commission
has determined that the rate for conditional firm service be the same
as the firm rate. BPA does not anticipate that the interruption of Firm
Demand would occur on a frequent basis, if at all. Thus, BPA does not
believe that a customer should pay a different transmission rate under
these circumstances. APPA states that footnote `b' arms wholesale
transmission customers and communities served at retail with
information and studies prepared by the transmission planner,
documenting the specific circumstances (i.e., specific Bulk Electric
System Contingency events) under which interruption of Firm Demand may
be needed to address bulk electric system performance requirements.
Commission Determination
    64. We understand NERC's position that as the entity that addresses
Bulk-Power System reliability, it does not have a mechanism to
coordinate with customers. Likewise, how to define customers and
community decisions and engage them in the NERC process could be
challenging.\78\
---------------------------------------------------------------------------

    \78\ As suggested in the NOPR, customer or community consent
would not require affirmative consent by every individual retail
customer, but the process NERC developed would recognize that either
group would need to be adequately defined. We note that, although
NERC comments that it addresses Bulk-Power System reliability, the
process that NERC proposes will impact firm load service to retail
customers.
---------------------------------------------------------------------------

    65. At the same time, California SWP provides a compelling example
of how a customer can be adversely affected by planned load shedding
for Firm Demand if it was unaware its load would be interrupted until
its load was actually shed. In contrast to California SWP's experience,
a customer should have notice and understanding that the transmission
planner plans to curtail certain Firm Demand in the event of a single
contingency indentified in the system modeling under NERC's
Transmission Planning requirements. NERC should consider these matters
on remand.\79\
---------------------------------------------------------------------------

    \79\ We will not consider the tariff-related comments as they
are beyond the scope of this rulemaking.
---------------------------------------------------------------------------

Summary
    66. In sum, the Commission remands the proposed footnote `b' and
directs NERC to revise its proposal to address the Commission's
concerns described above, subject to consideration of the additional
guidance provided in this Final Rule.
    67. As stated in the NOPR, NERC will need to support the revision
to footnote `b.' If there is a threshold component to the revised
footnote, NERC would need to support the threshold and show that
instability, uncontrolled separation, or cascading failures of the
system will not occur as a result of planning to shed Firm Demand up to
the threshold. In addition, if there is an individual exception option,
the applicable entities should be required to find that there is no
adverse impact to the Bulk-Power System from the exception and that it
is considered in wide-area coordination and operations. Further, the
Commission believes that any exception should be subject to further
review by the Regional Entity or NERC.

III. Information Collection Statement

    68. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\80\ The information contained here
is also subject to review under section 3507(d) of the Paperwork
Reduction Act of 1995.\81\
---------------------------------------------------------------------------

    \80\ 5 CFR 1320.11.
    \81\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    69. As stated above, the subject of this Final Rule is NERC's
proposed modification to Table 1, footnote `b' applicable in four TPL
Reliability Standards. This Final Rule remands the footnote `b'
modification to NERC. By remanding footnote `b' the applicable
Reliability Standards and any information collection requirements are
unchanged. Therefore, the Commission will submit this Final Rule to OMB
for informational purposes only.
    70. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, email:
<EMAIL_ADDRESS>phone:<PHONE_NUMBER>, or fax: (202) 273-
0873].

IV. Environmental Analysis

    71. 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.\82\ 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.\83\ The actions proposed
herein fall within this categorical exclusion in the Commission's
regulations.
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    \82\ 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).
    \83\ 18 CFR 380.4(a)(2)(ii).
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V. Regulatory Flexibility Act

    72. The Regulatory Flexibility Act of 1980 (RFA) \84\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a proposed rule and that minimize
any significant economic impact on a substantial number of small
entities. The Small Business Administration's (SBA) Office of Size
Standards develops the numerical definition of a small business.\85\
The SBA has established a size standard for electric utilities, stating
that a firm is small if, including its affiliates, it is primarily
engaged in the transmission, generation and/or distribution of electric
energy for sale and its total electric output for the preceding twelve
months did not exceed four million megawatt hours.\86\ The RFA is not
implicated by this Final Rule because the Commission is remanding

footnote `b' and not proposing any modifications to the existing burden
or reporting requirements. With no changes to the Reliability Standards
as approved, the Commission certifies that this Final Rule will not
have a significant economic impact on a substantial number of small
entities.
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    \84\ 5 U.S.C. 601-612.
    \85\ 13 CFR 121.201.
    \86\ Id. n.22.
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VI. Document Availability

    73. 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.
    74. 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.
    75. 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
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
VII. Effective Date and Congressional Notification

    76. These regulations are effective July 6, 2012. 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 direction of the Commission. Commissioner Norris is
dissenting in part and concurring in part with a separate statement
attached.
Kimberly D. Bose,
Secretary.

    NORRIS, Commissioner, dissenting in part and concurring in part:

    The continued implementation and evolution of the mandatory
reliability standards program enacted by Congress in 2005 has been
at the forefront of our agenda since I arrived at the Commission in
2010. As we have grappled with the difficult issues raised by
proposed new or revised standards, and as I have discussed these
issues with regulated industry, state regulators, and the public, I
have consistently heard a common theme: mandatory reliability
standards come with costs that consumers ultimately must bear.
    As I have thought about this issue, it has become clear to me
that in any discussion of a new or revised mandatory reliability
standard, there is always a tradeoff between the level of
reliability to be achieved by that standard and the costs that the
standard will impose. However, that tradeoff is rarely discussed
explicitly in the standards development process or during the
Commission's review of standards. But, we know that it is an
implicit consideration of entities participating in the standards
development process. I believe it is more appropriate to make those
considerations, where they are relevant, explicit. Therefore, I have
advocated for an open dialogue between NERC, the industry, and the
Commission to consider the connection between the mandatory
standards we approve to maintain and improve the reliability of the
Bulk Power System and the costs required to meet those standards.
    However, I have perceived some hesitancy in openly addressing
costs when considering reliability matters. This is not surprising,
as there are no easy answers to these tough questions, and
regulators and industry charged with assuring reliability will
always be hesitant to be perceived as sacrificing reliability in an
effort to save on costs. While I am not advocating for a cost-
benefit threshold for approving reliability standards, I do not
believe that we can ignore the costs of proposed mandatory
reliability standards as we consider whether they are ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest''.\1\ These are issues with real world implications,
not just for the reliability and security of our Nation's electric
grid, but for the day-to-day struggles of local communities to
balance the economic realities of many competing obligations.
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    \1\ See 16 U.S.C. 824o(d)(2).
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    I am compelled to raise these issues in this proceeding because
I believe that the Transmission Planning (TPL) Reliability Standard
footnote `b' addressed in today's order presents a stark example of
the tradeoffs that sometimes must be made between increasing levels
of reliability and the costs that come with achieving them. As such,
I hope my comments today will help generate a dialogue on how
economics and reliability fit together when considering mandatory
reliability standards.
    In today's order, I agree with the majority's decision to remand
proposed TPL footnote `b' because it is vague, potentially
unenforceable, and lacks adequate safeguards to determine when
planning to shed firm load would be permitted. However, I am
concerned that, in allowing for an exception to the TPL standards
requirement that firm load must be maintained under N-1 scenarios,
the order does not sufficiently recognize that this is both an
economic and reliability issue, and must allow for a balancing of
the economic and reliability considerations involved.
    There may be cases where planning to avoid shedding firm load in
all N-1 scenarios will impose significant costs on customers, with
perhaps little added reliability benefit for those customers. In
such instances, I believe that wholesale transmission customers and
local communities with retail load service should be empowered to
consider the economic tradeoffs between incurring costs to avoid
shedding firm load versus planning to shed firm load, as long as
that decision does not adversely impact the reliability of the Bulk
Power System. Simply put, if a customer seeks to avoid significant
costs, and can do so without impacting its neighbors, the customer
should be making that decision. Today's order fails to adequately
acknowledge the economic consequences of having to invest in
significant facility upgrades to avoid shedding firm load under
certain N-1 scenarios that may be rare or unlikely and that would
have only local impacts.\2\
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    \2\ Transmission Planning Reliability Standards, Order No. 762,
139 FERC ] 61,060, at P 33 (2012) (``With regard to NERC's comment
that the decision to interrupt local load is essentially an economic
decision that is a quality of service issue, not a reliability
issue, the Commission notes that in Order No. 693, we dismissed the
argument that * * * such interruption is based largely on the matter
of economics, not reliability.'') I also note that the brief
Commission findings in Order No. 693 failed to acknowledge or
sufficiently address this issue, leaving the uncertainty we are
still faced with today. Mandatory Reliability Standards for the
Bulk-Power System, Order No. 693, FERC Stats. & Regs. ] 31,242, at P
1791-1794 (2007).
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    Accordingly, in my view, the Commission should have directed
NERC to revise footnote `b' to address two broad concerns. First,
wholesale transmission customers and retail load should have the
ability to choose whether to shed firm load during an N-1
contingency where that decision will not adversely impact the Bulk
Power System. Second, the decision to shed firm load must be
validated to ensure that there is no adverse impact on the Bulk
Power System. Absent this reliability check, the planning of firm
load shedding should not be permitted, because reliability of the
Bulk Power System is paramount. While NERC, the Regional Entity,
and/or the local planning authority must be involved in the
reliability check, these entities would not be expected to be
involved in the economic decision.
    Additionally, I agree with various comments filed in response to
the NOPR that firm load shedding is and should be used rarely or
infrequently. I do not expect that any new process that NERC may
propose to determine whether firm load shedding is permitted would
result in a rush by entities seeking to plan to shed firm load. In
other words, I do not expect this exception to ``swallow the rule''
under the TPL standards that firm load may not be planned to be shed
for N-1 contingencies.
    Finally, the concerns I note above regarding the failure to
consider both the economic and reliability aspects of a decision to
plan to shed firm load extend to the specific guidance provided in
the order. The guidance in the order with respect to what

would constitute an allowable exception fails to provide a realistic
means for entities to balance these economic and reliability
considerations. Instead, I would have provided that an entity could
submit its plan to shed firm load for a single contingency to its
relevant regulatory authority or governing body prior to any actual
interruption.\3\ The politically accountable regulatory authority or
governing body would have then made the determination, based upon
economics and in the best interests of its customers, as to whether
firm load shedding should be permitted. Those determinations would
be subject to oversight and review by NERC, the Regional Entity,
and/or the planning authority to ensure that they will not adversely
impact the Bulk Power System.\4\
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    \3\ See e.g., Duke Energy Corporation Dec. 22, 2011 Comments,
Docket No. RM11-18-000.
    \4\ NERC may propose an alternative to Commission guidance that
is equally efficient and effective at addressing the Commission's
reliability concerns. Order No. 693 at P 31.
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    For these reasons, I respectfully dissent in part and concur in
part.

John R. Norris,

Commissioner.

[FR Doc. 2012-10944 Filed 5-4-12; 8:45 am]
BILLING CODE 6717-01-P