Transmission Planning Reliability Standards, 66229-66235 [2011-27624]
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Federal Register / Vol. 76, No. 207 / Wednesday, October 26, 2011 / Proposed Rules
for any action that may have a
significant adverse effect on the human
environment.47 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.48 The
actions proposed here fall within this
categorical exclusion in the
Commission’s regulations.
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VI. Regulatory Flexibility Act
Certification
69. The Regulatory Flexibility Act of
1980 (RFA) 49 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.50 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.51
70. Proposed Reliability Standard
PRC–006–1 proposes to establish
design, assessment, and documentation
requirements for automatic UFLS
program. It will be applicable to
planning coordinators and entities that
are responsible for the ownership,
operation, or control of UFLS
equipment. Proposed Standard EOP–
003–2 proposes to remove balancing
authorities from having to comply with
R2 and M1 of the standard. Comparison
of the NERC compliance registry with
data submitted to the Energy
Information Administration on Form
EIA–861 indicates that perhaps as many
as 8 small entities are registered as
planning coordinators and 18 small
entities are registered as balancing
authorities. The Commission estimates
that the small planning coordinators to
47 Order
No. 486, Regulations Implementing the
National Environmental Policy Act of 1969, FERC
Stats. & Regs., Regulations Preambles 1986–1990
¶ 30,783 (1987).
48 18 CFR 380.4(a)(2)(ii).
49 5 U.S.C. 601–612.
50 13 CFR 121.101.
51 13 CFR 121.201, Sector 22, Utilities & n.1.
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whom the proposed Reliability Standard
will apply will incur compliance and
recordkeeping costs of $157,184
($19,648 per planning coordinator)
associated with the Standard’s
requirements. The small balancing
authorities will receive a savings of
$154,728 ($8,596 per balancing
authority). Accordingly, proposed
Reliability Standards PRC–006–1 and
EOP–003–2 should not impose a
significant operating cost increase or
decrease on the affected small entities.
71. Based on this understanding, the
Commission certifies that these
Reliability Standards will not have a
significant economic impact on a
substantial number of small entities.
Accordingly, no regulatory flexibility
analysis is required.
VII. Comment Procedures
72. 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 December 27, 2011.
Comments must refer to Docket No.
RM11–20–000, and must include the
commenter’s name, the organization
they represent, if applicable, and their
address in their comments.
73. 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.
74. Commenters that are not able to
file comments electronically must send
an original of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
75. 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.
VIII. Document Availability
76. 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 the
Commission’s Home Page (https://
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www.ferc.gov) and in the Commission’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.
77. From the Commission’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.
78. User assistance is available for
eLibrary and the Commission’s Web site
during normal business hours from the
Commission’s 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.
List of Subjects in 18 CFR Part 40
Electric power; Electric utilities;
Reporting and recordkeeping
requirements.
By direction of the Commission.
Commissioner Spitzer is not participating.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2011–27625 Filed 10–25–11; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM11–18–000]
Transmission Planning Reliability
Standards
Federal Energy Regulatory
Commission, DOE.
ACTION: Notice of proposed rulemaking.
AGENCY:
Transmission Planning (TPL)
Reliability Standards are intended to
ensure that the transmission system is
planned and designed to meet an
appropriate and specific set of reliability
criteria. Reliability Standard TPL–002–
0a references a table which identifies
different categories of contingencies and
allowable system impacts in the
planning process. The table includes a
footnote regarding planned or controlled
interruption of electric supply where a
single contingency occurs on a
transmission system. North American
Electric Reliability Corporation (NERC),
the Commission-certified Electric
SUMMARY:
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Federal Register / Vol. 76, No. 207 / Wednesday, October 26, 2011 / Proposed Rules
Reliability Organization, requests
approval of a revision to the footnote. In
this notice, the Commission proposes to
remand NERC’s proposed revision to the
footnote.
DATES: Comments are due December 27,
2011.
ADDRESSES: You may submit comments,
identified by docket number by any of
the following methods:
• Agency Web Site: https://
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:
Robert T. Stroh (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, Telephone: (202) 502–8473.
Eugene Blick (Technical Information),
Office of Electric Reliability, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, Telephone: (202) 502–8066.
SUPPLEMENTARY INFORMATION:
Notice of Proposed Rulemaking
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October 20, 2011.
1. On March 31, 2011, the North
American Electric Reliability
Corporation (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).1
Pursuant to section 215(d)(4) of the
Federal Power Act (FPA) 2, the
Commission proposes to remand the
proposed Table 1, footnote b. As
discussed below, the Commission
believes that the proposed Reliability
Standard does not meet the statutory
1 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.
2 18 U.S.C. 824o(d)(4) (2006).
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criteria for approval that it be just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.3 The Commission seeks
comments on its proposal.
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.
3. Pursuant to section 215 of the FPA,
the Commission established a process to
select and certify an ERO 4 and,
subsequently, certified NERC as the
ERO.5 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, Table
1, footnote ‘b.’ 6 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
footnote ‘b’ of Reliability Standard TPL–
002–0.8
A. Transmission Planning (TPL)
Reliability Standards
4. Currently-effective Reliability
Standard TPL–002–0a addresses BulkPower System planning and related
system performance for single element
contingency conditions. Requirement
R1 of TPL–002–0a 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
3 16
U.S.C. 824o(d)(2) (2006).
Concerning Certification of the Electric
Reliability Organization; and Procedures for the
Establishment, Approval and Enforcement of
Electric Reliability Standards, Order No. 672, FERC
Stats. & Regs. ¶ 31,204, order on reh’g, Order No.
672–A, FERC Stats. & Regs. ¶ 31,212 (2006).
5 North American Electric Reliability Corp., 116
FERC ¶ 61,062, order on reh’g & compliance, 117
FERC ¶ 61,126 (2006), aff’d sub nom., Alcoa, Inc.
v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
6 Mandatory Reliability Standards for the BulkPower 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)(2006).
8 Order No. 693, FERC Stats & Regs. ¶ 31,242 at
P 1797.
Table I.’’ 9 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 the clause
regarding loss of demand, current
footnote ‘b’ of Table 1 states:
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 (nonrecallable reserved) electric power Transfers.
B. Order No. 693 Directive
5. 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.10 The Commission
directed the ERO to develop certain
modifications, including a clarification
of Table 1, footnote ‘b’. The Commission
stated that:
Based on the record before us, we believe
that the transmission planning Reliability
Standard should not allow an entity to plan
for the loss of non-consequential load in the
event of a single contingency. The
Commission directs the ERO to clarify the
Reliability Standard. Regarding the
comments of Entergy and Northern Indiana
that the Reliability Standard should allow
entities to plan for the loss of firm service for
a single contingency, the Commission finds
that their comments may be considered
through the Reliability Standards
development process. However, we strongly
discourage an approach that reflects the
lowest common denominator. The
Commission also clarifies that an entity may
seek a regional difference to the Reliability
Standard from the ERO for case-specific
circumstances.11
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9 Reliability
Standard TPL–002–0a, Requirement
R1.
10 See Order No. 693, FERC Stats. & Regs.
¶ 31,242 at P 1794. Non-consequential load loss
includes the removal, by any means, of any planned
firm load that is not directly served by the elements
that are removed from service as a result of the
contingency. Currently-effective footnote ‘b’ deals
with both consequential load loss and nonconsequential load loss. NERC’s proposed footnote
‘b’ characterizes both types of load loss as ‘‘Firm
Demand.’’ The focus of this NOPR is NERC’s
proposed treatment of non-consequential load loss
or planned interruption of ‘‘Firm Demand.’’
11 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 1794 (footnotes omitted).
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6. 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 ‘‘at the fringes of various
systems’’ would be an acceptable
approach in limited circumstances.12
Specifically, the Commission clarified
that:
Moreover, the Commission, in * * * Order
No. 693, then provided a clarification that an
entity may seek a regional difference to the
Reliability Standard from the ERO for casespecific circumstances. We believe 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. Thus, the
Commission did not dictate a single solution
as NERC and others now claim. In any event,
NERC must provide a strong technical
justification for its proposal.13
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C. NERC’s Petition for Approval of TPL–
002–0a, Footnote b
7. 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.’’ 14 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.’’ 15 NERC states
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. It allows for
planned interruption of Firm Demand
when ‘‘subject to review in an open and
transparent stakeholder process.’’ 16
NERC’s proposed footnote ‘b’ states:
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 redispatch 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
12 Mandatory Reliability Standards for the Bulk
Power System, 131 FERC ¶ 61,231, at P 21 (2010)
(June 2010 Order).
13 Id.
14 NERC Petition at 10.
15 Id.
16 Id.
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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 [Bulk Electric System]
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 that includes addressing stakeholder
comments.
D. Supplemental Information
8. 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.’’ 17 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.
NERC added that an ERO-sponsored
planning process is not likely to be
efficient or effective because of
extensive jurisdictional issues between
NERC, the Commission, and the many
authorities having jurisdiction that
would have to be resolved before
implementation could occur. NERC
added that an ERO-specific process
would lead to conflicts among federal,
provincial, state and local governing
bodies that have jurisdiction over
various parts of the planning, siting and
construction process. NERC also
believes that a NERC-centered process
would duplicate planning actions
occurring elsewhere (e.g., where
resource allocation decisions are
actually being made), and such a
process could lead to inconsistent
results. NERC concluded that a more
reasonable and expeditious path would
be to rely on existing stakeholder
processes. According to NERC, such
processes would more likely engage the
appropriate local-level decision-makers
and policy-makers.
9. With respect to review and
oversight by NERC and the Regional
Entities, NERC submitted that an EROspecific process would place the ERO in
the position of managing and actively
participating in a planning process,
which conflicts with its role as the
17 NERC
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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.
10. Furthermore, NERC stated that an
objective of the planning process should
be to minimize the likelihood and
magnitude of planned Firm Demand
interruptions. NERC recognizes that
there may be topological or system
configurations where allowing planned
interruptions of Firm Demand may
provide more reliable service. NERC
contends 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.
II. Discussion
11. The Commission proposes to
remand NERC’s proposal to modify
Reliability Standard TPL–002–0a, Table
1, footnote ‘b.’ The Commission believes
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.
Specifically, the Commission is
concerned 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. In proposing a
stakeholder process without
specification of any technical means by
which exceptions are to be evaluated,
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the proposed footnote effectively turns
the processes into a reliability standards
development process outside of NERC’s
existing procedures. Furthermore, the
Commission believes that regardless of
the process used, the result could lead
to inconsistent reliability requirements
within and across reliability regions.
While the Commission recognizes that
some variation among regions or entities
is reasonable given varying grid
topography and other legitimate
considerations, there are no technical or
other criteria to determine whether
varied results are arbitrary or based on
meaningful distinctions. While the
Commission acknowledges that NERC
has flexibility in developing alternative
approaches, we believe that the
proposed approach is not equally
efficient or effective as the
Commission’s directives and that NERC
has failed to provide a strong technical
justification for its proposal.
12. As an initial matter, the
Commission is concerned that the
process lacks parameters. The 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.’’ 18
However, 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. Indeed, NERC’s explanation
appears to confirm this concern, as
NERC explained that Regional Entities’
involvement is limited to 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’.
13. Further, the Commission is
concerned that 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 TPL–
002–0a Reliability Standard requires
Planning Authorities and Transmission
Planners to 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 Moreover, the
planner must consider all single
contingencies applicable to Table I,
Category B and demonstrate that system
performance is met. For those instances
where system performance is not met,
the 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.20 In
regard to NERC’s proposal, the
Commission is concerned that footnote
‘b’ would function 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. In
this case NERC has provided no
technically sound means of determining
situations in which planning to
interrupt Firm Demand would be
allowable, and instead has removed
such decision-making to an unspecified
stakeholder process without any
assurance that such processes will
deploy technically sound means of
approving or denying exceptions.
Without any technical or other criteria
specified to determine when planning to
interrupt Firm Demand would be
allowable, the Commission is concerned
that 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. While the Commission
recognizes that some variation among
regions or entities is reasonable given
varying grid topography and other
legitimate considerations, there are no
technical or other criteria to determine
whether varied results are arbitrary or
based on meaningful distinctions. The
Commission is thus concerned that
there may be a lack of consistency in
determinations to allow the planned
interruption of Firm Demand. The
proposed stakeholder process does not
have any parameters except for
openness and transparency. As a result,
multiple processes that could be
adopted across the country would likely
lead to inconsistent determinations to
allow for the planned interruption of
Firm Demand.
14. The Commission believes that a
remand would give NERC and industry
flexibility to develop an approach that
19 Reliability
21 See
Standard TPL–002–0a,
Requirements R1.5 and R2.
Petition at 10.
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A. Lack of Technical or Other Criteria
15. NERC’s proposal does not
prescribe the criteria that would define
the parameters of permissible
interruption of Firm Demand. In Order
No. 693 the Commission expressed
concern that, as a general rule, footnote
‘b’ should not allow an entity to plan for
the loss of non-consequential load in the
event of a single contingency and
directed NERC to clarify the standard.
The Commission stated in the June 2010
Order that a regional difference or a
case-specific exception process that
could be technically justified would be
acceptable. While the Commission
allows NERC to propose an equally
effective and efficient solution to a
Commission’s proposed solution, the
Commission does not believe that the
proposal is equally effective and
efficient. First, NERC’s proposed
footnote ‘b’ contains no constraints and
could allow an entity to plan to
interrupt any amount of 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. This
result is contrary to the underlying
standard and our prior orders.21 Further,
NERC did not technically justify its
proposal, instead relying on the benefit
of having transparency in the process.
The Commission does not believe
transparency in this instance can
substitute for a technical justification.
16. In its supplemental filing, NERC
states that it is not feasible for the ERO
to develop a one-size-fits-all criterion
for limiting the planned interruption of
Firm Demand due to the wide variety of
system configurations and regulatory
compacts.22 NERC states that the
standards drafting team believes there is
no analytical data to support a single
level and therefore any single value was
viewed as arbitrary.
17. We are not persuaded by NERC’s
reasoning. First, both NERC and the
Commission have developed thresholds
in other reliability contexts that have
overcome similar claims of arbitrariness.
For example, the threshold for
conducting vegetation management
pursuant to Reliability Standard FAC–
003–1 applies to all transmission lines
operated at 200 kV and above.23 In the
Standard TPL–002–0a, Requirement
R1.
20 Reliability
18 NERC
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.
Frm 00035
Fmt 4702
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Order No. 693, see also June 2010 Order.
Data Response at 6.
23 Reliability Standard FAC–003–1.
22 NERC
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same vein, NERC’s Statement of
Compliance Registry Criteria has
numerous thresholds for determining
eligibility for registration.24 The
Commission did not suggest a one size
fits all exceptions process. If the ERO
were to perform an exception process, it
might include flexibility in decisions
based on disparate topology or on other
matters since it could utilize its
technical expertise to determine the
reliability impact from one region to
another. Moreover, the Commission’s
proposal to remand revised footnote ‘b’
due to a lack of criteria does not
preclude NERC from developing another
alternative, provided that it is equally
‘‘efficient and effective.’’
18. Finally, the Commission
understands that there are a wide
variety of system configurations and
regulatory compacts. NERC indicates
that the standards drafting team
considered a variety of limits; however,
it is not clear whether NERC considered
a blend of quantitative and qualitative
thresholds. For example, a standard
could require a process with a
quantitative limitation on how much
Firm Demand could be planned for
interruption and that 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.25 In short,
we believe that a more defined process
would be needed but, by itself, would
not be adequate without NERC-defined
technical or other criteria to determine
planned interruption of Firm Demand.
The Commission seeks comment on
these proposals.
B. Stakeholder Process
jlentini on DSK4TPTVN1PROD with PROPOSALS
19. The Commission believes that
NERC’s proposed footnote ‘b’
stakeholder process does not meet Order
No. 693 and the June 2010 Order
directive. According to NERC, the type
of stakeholder process used under its
proposed footnote ‘b’ can vary from one
planning entity to the next. NERC offers
several stakeholder processes as
examples, such as the Order 890-type
process, a state public utility
commission or local jurisdiction
process, or a Regional Transmission
Organization/Independent System
24 See, e.g., NERC Statement of Registry Criteria,
Section III. The Commission approved Statement of
Registry Criteria in Order No. 693.
25 While we encourage NERC to exercise
flexibility in designing an appropriate standard,
under this example, the exception process could
consist of a stakeholder process that has some level
of due process as long as that process does not
allow the entity that proposes its exception to make
the decision on whether to grant the exception.
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16:20 Oct 25, 2011
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Operator (RTO/ISO) stakeholder
process.
20. First, because NERC’s proposed
footnote ‘b’ does not define the
stakeholder process, the express terms
of the standard would allow an
applicable entity to form or participate
in any stakeholder process and be
compliant with the proposed standard.
Second, as we have mentioned, NERC
has offered no technical justification for
exceptions to be granted through the
stakeholder process and therefore no
means for the Commission to judge
whether the process will protect the
reliability of the Bulk-Power System.
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 is
concerned that any meeting that is open
to stakeholders could meet this
standard. Further, because the
stakeholder process is not defined, the
proposal could allow a transmission
planner to develop a process that
provides insufficient process and
transparency and still comply with the
standard. The Commission believes that
such process would be insufficient
because it allows any stakeholder
process to essentially become a
reliability standards development
processes outside of NERC’s existing
procedures. Furthermore, the
Commission believes that regardless of
the stakeholder process used, the
outcome could lead to inconsistent
results, with no technical or other
criteria to determine whether varied
results are arbitrary or based on
meaningful distinctions. The
Commission seeks 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.
21. Nor does the standard describe
what would be entailed in addressing
the stakeholder comments. As described
above, the process under the standard
does not provide for any technical rigor
to address stakeholder concerns. While
the standard requires transparency and
an opportunity for stakeholder
comments on the transmission planner’s
proposed plan to interrupt Firm
Demand, it does not mandate any
particular stakeholder involvement, nor
does it mandate that interested
governmental authorities be afforded
notice and an opportunity to comment.
As we read the proposed standard, a
responsible entity could define when it
PO 00000
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66233
would plan to interrupt Firm Demand
on its own, then ask for stakeholder
input on that plan. While the standard
requires the responsible entity to
‘‘address’’ stakeholder comments, the
responsible entity is not required to
specify or support the technical basis
upon which it rendered a decision. The
Commission believes that the
stakeholder process in proposed
footnote ‘b’ would allow the
transmission planner to define the
circumstances when it would rely on
planned interruption of Firm Demand,
provide that definition for review by
regulators and other stakeholders,
receive comments from regulators and
stakeholders requesting a more narrow
definition, and explain to the regulators
and stakeholders why it is declining the
request and maintaining the broader
definition, even if every other
transmission planner facing similar
circumstances would reach the opposite
conclusion.
22. In Order No. 693 and the June
2010 Order, the Commission stated that
a regional difference or a case-specific
exception process, among other things,
would be an acceptable approach. With
regard to a case-specific process, NERC
replied it would ‘‘create undesirable
delays and uncertainty in the
transmission planning process.’’ 26
However, the proposed footnote ‘b’ does
not provide a time limitation by which
planning decisions to interrupt Firm
Demand must be made. The
Commission is not persuaded that
NERC’s proposed approach ameliorates
this concern. The Commission seeks
comment on whether an exceptions
process that provides defined criteria,
with some allowance or consideration
for unique circumstances, could be
crafted that would resolve NERC’s
concerns of ‘‘undesirable delays’’ and
‘‘uncertainty.’’
23. In sum, the Commission is
concerned that the stakeholder process
set forth in the NERC proposal is not
sufficiently defined, rendering it
potentially unenforceable. As
mentioned above, the proposed
stakeholder process includes no
parameters other than openness and
transparency. NERC states that it and
the Regional Entities will review a
responsible entity’s decision to plan to
interrupt Firm Demand using an afterthe-fact audit, to determine if the
entity’s implementation of footnote ‘b’
to plan Firm Demand interruption and
whether the decision by the entity was
vetted through the stakeholder process
and qualified as one of the situations
26 NERC
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jlentini on DSK4TPTVN1PROD with PROPOSALS
identified in footnote ‘b.’ 27 The
Commission believes that this could
result in a transmission planner
invoking a process that provides for
minimal stakeholder involvement,
providing scant reasons to reject any
stakeholder input and then defending
its decision by claiming that it has
satisfied the provision. While the
Compliance Enforcement Authority
would verify that the process fulfilled
the letter of NERC’s proposed footnote
‘b’—that some open, transparent
stakeholder process was involved and
that the responsible entity in some way
addressed stakeholder concerns—there
is no mechanism for the ERO or a
Regional Entity to enforce a finding that
the evidence does not support an
acceptable instance of planned
interruption of Firm Demand. The
Commission seeks comment on the
concerns raised above.
C. Commission Proposal
24. The Commission believes that
NERC’s proposed footnote ‘b’ does not
meet the Commission’s Order No. 693
directives, nor is it an equally effective
and efficient alternative. On this basis,
the Commission proposes to remand the
proposal to NERC.
25. The Commission also proposes to
provide further guidance on acceptable
approaches to footnote ‘b’. We seek
comment on all of the options below. In
addition, while the Commission is
proposing certain options for revising
footnote ‘b’, we also seek comment on
other potential options to solve the
concerns outlined in this NOPR. As
noted above, the Commission
understands that there are a wide
variety of system configurations and
regulatory compacts. We believe that a
more defined process than that provided
in the proposed footnote ‘b’ would be
needed but, by itself, would not be
adequate without NERC-defined
technical or other criteria to determine
an acceptable planned interruption of
Firm Demand at the fringes of the
system.28
26. We acknowledge that the
standards drafting team considered a
variety of limits; however, setting some
form of criteria within the standard
itself for planning to interrupt Firm
Demand may be an acceptable approach
to setting criteria for footnote ‘b’ and
would be an option for NERC to
consider. We also seek comment on
whether existing protocols could
provide guidance to NERC in devising
27 NERC
Data Response at 7–8.
exceptions process to determine specific
requests for planned interruption of Firm Demand
may not necessarily be limited to the fringes of the
system.
28 Any
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16:20 Oct 25, 2011
Jkt 226001
criteria. For example, the Department of
Energy’s Electric Emergency Incident
and Disturbance Report (Form OE–417)
requires, among other things, an entity
to report the uncontrolled loss of 300
Megawatts or more of firm system loads
for more than 15 minutes from a single
incident, load shedding of 100
Megawatts or more implemented under
emergency operational policy, and the
loss of service for more than 1 hour to
50,000 customers. While these are
reporting requirements for the
operational timeframe, and may include
distribution level load shedding, the
Commission requests comments on
whether they could also serve as a basis
for setting limits on when an entity can
plan to interrupt Firm Demand on the
Bulk-Power System. Another existing
document that could provide guidance
on how to set a limit on the planned
interruption of Firm Demand is NERC’s
Statement of Compliance Registry
Criteria, which uses, for example, 25
MW as a threshold in determining when
a load-serving entity or distribution
provider should register with NERC. We
seek comments on this proposed option,
and any other external documents that
could be used to guide a revision to
footnote ‘b.’
27. Second, as stated above, it is not
clear whether NERC considered a blend
of quantitative and qualitative
thresholds. The Commission seeks
comments on whether this would be an
option for providing criteria that would
be generally applicable, but also for
allowing for certain cases that may
exceed the criteria. For example, a
standard could require a process with a
quantitative limitation on how much
Firm Demand could be planned for
interruption and that 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. NERC has
raised concerns about conflicts among
federal, provincial, state and local
governing bodies that have jurisdiction
over various parts of the planning, siting
and construction process. The
Commission believes that this approach
may satisfy the need for technical
criteria that we have described, while
accounting for NERC’s concerns about
the difficulty of developing a one-sizefits-all criterion for limiting planned
Firm Demand interruptions and the
appropriateness and feasibility of
managing and actively participating in
each planning process. As NERC states,
the objective of footnote ‘b’ should be to
minimize the likelihood and magnitude
of planned Firm Demand interruptions.
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Fmt 4702
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The Commission believes 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. We
seek comment on this option, and
which entities should be involved in the
review and subsequent determination as
to whether an exception should be
allowed.
28. NERC has raised concerns about
conflicts among federal, provincial, state
and local governing bodies that have
jurisdiction over various parts of the
planning, siting and construction
process. There also may be concerns
about the costs of planning to avoid
Firm Demand shedding. The
Commission seeks 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. This presumably would not
require affirmative consent by every
individual retail customer, but we
recognize that either term, customer or
community, would need to be
adequately defined. The Commission
therefore seeks comments on who might
be able to represent the customer or
community in this option and how
customer or community consent might
be demonstrated. Additionally, we seek
comment on how it would be
determined that firm demand shedding
with customer consent would not
adversely impact the Bulk-Power
System. However, we also seek
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.
29. Finally, regardless of how NERC
revises footnote ‘b’ to resolve the
concerns outlined in this NOPR and in
previous orders, the Commission notes
that NERC will need to support the
revision to footnote ‘b.’ If there is a
threshold component to the revised
footnote, the Commission believes that
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 Commission
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believes that 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, we believe that
any exception should be subject to
further review by the Regional Entity,
NERC, and the Commission. This does
not necessarily mean that the Regional
Entity, NERC, or the Commission
should have to approve the exception,
but that any of the three could later
audit its implementation.
30. In conclusion, while the
Commission provides three options for
revising footnote ‘b’ in this Notice of
Proposed Rulemaking, we seek
comments on the feasibility of the
options and on ways in which the
options might be improved. In addition,
we seek comment on whether there are
other ways for NERC to solve the
concerns outlined above in an equally
effective and efficient manner.
jlentini on DSK4TPTVN1PROD with PROPOSALS
III. Information Collection Statement
31. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain reporting and
recordkeeping (collections of
information) imposed by an agency.29
The information contained here is also
subject to review under section 3507(d)
of the Paperwork Reduction Act of
1995.30
32. As stated above, the subject of this
NOPR is NERC’s proposed modification
to Table 1, footnote ‘b’ applicable in
four TPL Reliability Standards. This
NOPR proposes to remand 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 NOPR to OMB for informational
purposes only.
33. Interested persons may obtain
information on the reporting
requirements by contacting the
following: Federal Energy Regulatory
Commission, 888 First Street, NE.
Washington, DC 20426 [Attention: Ellen
Brown, Office of the Executive Director,
e-mail: data.clearance@ferc.gov, phone:
(202) 502–8663, or fax: (202) 273–0873].
IV. Regulatory Flexibility Act
34. The Regulatory Flexibility Act of
1980 (RFA) 31 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
CFR 1320.11.
U.S.C. 3507(d).
31 5 U.S.C. 601–612.
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.32 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.33 The RFA
is not implicated by this NOPR 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 NOPR
will not have a significant economic
impact on a substantial number of small
entities.
V. Comment Procedures
35. 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 60 days from
publication in the Federal Register.
Comments must refer to Docket No.
RM11–18–000, and must include the
commenter’s name, the organization
they represent, if applicable, and their
address in their comments.
36. 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.
37. Commenters that are not able to
file comments electronically must send
an original of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
38. 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
29 5
30 44
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33 Id.
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serve copies of their comments on other
commenters.
VI. Document Availability
39. 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.
40. 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.
41. 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.
Commissioner Spitzer is not participating.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2011–27624 Filed 10–25–11; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF HEALTH AND
HUMAN SERVICES
Food and Drug Administration
21 CFR Parts 201 and 610
[Docket No. FDA–2011–N–0719]
Bar Code Technologies for Drugs and
Biological Products; Retrospective
Review Under Executive Order 13563;
Request for Comments
AGENCY:
Food and Drug Administration,
HHS.
ACTION:
Notice; request for comments.
The Food and Drug
Administration (FDA) is announcing a
review of the ‘‘Bar Code Final Rule,’’
under Executive Order 13563,
‘‘Improving Regulation and Regulatory
Review.’’ The Bar Code Final Rule,
which was published in 2004, requires
SUMMARY:
E:\FR\FM\26OCP1.SGM
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]]>Agencies
[Federal Register Volume 76, Number 207 (Wednesday, October 26, 2011)]
[Proposed Rules]
[Pages 66229-66235]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-27624]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM11-18-000]
Transmission Planning Reliability Standards
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Notice of proposed rulemaking.
-----------------------------------------------------------------------
SUMMARY: Transmission Planning (TPL) Reliability Standards are intended
to ensure that the transmission system is planned and designed to meet
an appropriate and specific set of reliability criteria. Reliability
Standard TPL-002-0a references a table which identifies different
categories of contingencies and allowable system impacts in the
planning process. The table includes a footnote regarding planned or
controlled interruption of electric supply where a single contingency
occurs on a transmission system. North American Electric Reliability
Corporation (NERC), the Commission-certified Electric
[[Page 66230]]
Reliability Organization, requests approval of a revision to the
footnote. In this notice, the Commission proposes to remand NERC's
proposed revision to the footnote.
DATES: Comments are due December 27, 2011.
ADDRESSES: You may submit comments, identified by docket number by any
of the following methods:
Agency Web Site: https://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:
Robert T. Stroh (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, Telephone: (202) 502-8473.
Eugene Blick (Technical Information), Office of Electric Reliability,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, Telephone: (202) 502-8066.
SUPPLEMENTARY INFORMATION:
Notice of Proposed Rulemaking
October 20, 2011.
1. On March 31, 2011, the North American Electric Reliability
Corporation (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).\1\ Pursuant to section 215(d)(4) of the Federal
Power Act (FPA) \2\, the Commission proposes to remand the proposed
Table 1, footnote b. As discussed below, the Commission believes that
the proposed Reliability Standard does not meet the statutory criteria
for approval that it be just, reasonable, not unduly discriminatory or
preferential, and in the public interest.\3\ The Commission seeks
comments on its proposal.
---------------------------------------------------------------------------
\1\ 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.
\2\ 18 U.S.C. 824o(d)(4) (2006).
\3\ 16 U.S.C. 824o(d)(2) (2006).
---------------------------------------------------------------------------
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.
3. Pursuant to section 215 of the FPA, the Commission established a
process to select and certify an ERO \4\ and, subsequently, certified
NERC as the ERO.\5\ 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, Table 1, footnote `b.' \6\ 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 footnote `b' of Reliability Standard
TPL-002-0.\8\
---------------------------------------------------------------------------
\4\ Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval and
Enforcement of Electric Reliability Standards, Order No. 672, FERC
Stats. & Regs. ] 31,204, order on reh'g, Order No. 672-A, FERC
Stats. & Regs. ] 31,212 (2006).
\5\ North American Electric Reliability Corp., 116 FERC ]
61,062, order on reh'g & compliance, 117 FERC ] 61,126 (2006), aff'd
sub nom., Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
\6\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, FERC Stats. & Regs. ] 31,242, order on reh'g, Order
No. 693-A, 120 FERC ] 61,053 (2007).
\7\ 16 U.S.C. 824o(d)(5)(2006).
\8\ Order No. 693, FERC Stats & Regs. ] 31,242 at P 1797.
---------------------------------------------------------------------------
A. Transmission Planning (TPL) Reliability Standards
4. Currently-effective Reliability Standard TPL-002-0a addresses
Bulk-Power System planning and related system performance for single
element contingency conditions. Requirement R1 of TPL-002-0a 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.'' \9\ 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 the clause regarding loss of demand,
current footnote `b' of Table 1 states:
---------------------------------------------------------------------------
\9\ 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
power Transfers.
B. Order No. 693 Directive
5. 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.\10\ The Commission directed the ERO to develop
certain modifications, including a clarification of Table 1, footnote
`b'. The Commission stated that:
---------------------------------------------------------------------------
\10\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1794.
Non-consequential load loss includes the removal, by any means, of
any planned firm load that is not directly served by the elements
that are removed from service as a result of the contingency.
Currently-effective footnote `b' deals with both consequential load
loss and non-consequential load loss. NERC's proposed footnote `b'
characterizes both types of load loss as ``Firm Demand.'' The focus
of this NOPR is NERC's proposed treatment of non-consequential load
loss or planned interruption of ``Firm Demand.''
Based on the record before us, we believe that the transmission
planning Reliability Standard should not allow an entity to plan for
the loss of non-consequential load in the event of a single
contingency. The Commission directs the ERO to clarify the
Reliability Standard. Regarding the comments of Entergy and Northern
Indiana that the Reliability Standard should allow entities to plan
for the loss of firm service for a single contingency, the
Commission finds that their comments may be considered through the
Reliability Standards development process. However, we strongly
discourage an approach that reflects the lowest common denominator.
The Commission also clarifies that an entity may seek a regional
difference to the Reliability Standard from the ERO for case-
specific circumstances.\11\
---------------------------------------------------------------------------
\11\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1794
(footnotes omitted).
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[[Page 66231]]
6. 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 ``at the fringes of various systems'' would be an acceptable
approach in limited circumstances.\12\ Specifically, the Commission
clarified that:
---------------------------------------------------------------------------
\12\ Mandatory Reliability Standards for the Bulk Power System,
131 FERC ] 61,231, at P 21 (2010) (June 2010 Order).
Moreover, the Commission, in * * * Order No. 693, then provided
a clarification that an entity may seek a regional difference to the
Reliability Standard from the ERO for case-specific circumstances.
We believe 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. Thus, the Commission did not dictate a single
solution as NERC and others now claim. In any event, NERC must
provide a strong technical justification for its proposal.\13\
---------------------------------------------------------------------------
\13\ Id.
---------------------------------------------------------------------------
C. NERC's Petition for Approval of TPL-002-0a, Footnote b
7. 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.'' \14\ 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.'' \15\ NERC states 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. It allows for planned interruption of Firm Demand when
``subject to review in an open and transparent stakeholder process.''
\16\ NERC's proposed footnote `b' states:
---------------------------------------------------------------------------
\14\ NERC Petition at 10.
\15\ Id.
\16\ 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 [Bulk Electric System] 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 that includes addressing
stakeholder comments.
D. Supplemental Information
8. 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.'' \17\
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. NERC added that an ERO-
sponsored planning process is not likely to be efficient or effective
because of extensive jurisdictional issues between NERC, the
Commission, and the many authorities having jurisdiction that would
have to be resolved before implementation could occur. NERC added that
an ERO-specific process would lead to conflicts among federal,
provincial, state and local governing bodies that have jurisdiction
over various parts of the planning, siting and construction process.
NERC also believes that a NERC-centered process would duplicate
planning actions occurring elsewhere (e.g., where resource allocation
decisions are actually being made), and such a process could lead to
inconsistent results. NERC concluded that a more reasonable and
expeditious path would be to rely on existing stakeholder processes.
According to NERC, such processes would more likely engage the
appropriate local-level decision-makers and policy-makers.
---------------------------------------------------------------------------
\17\ NERC Data Response at 4.
---------------------------------------------------------------------------
9. 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.
10. Furthermore, NERC stated that an objective of the planning
process should be to minimize the likelihood and magnitude of planned
Firm Demand interruptions. NERC recognizes that there may be
topological or system configurations where allowing planned
interruptions of Firm Demand may provide more reliable service. NERC
contends 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.
II. Discussion
11. The Commission proposes to remand NERC's proposal to modify
Reliability Standard TPL-002-0a, Table 1, footnote `b.' The Commission
believes 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. Specifically, the Commission is concerned 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. In proposing a stakeholder process without
specification of any technical means by which exceptions are to be
evaluated,
[[Page 66232]]
the proposed footnote effectively turns the processes into a
reliability standards development process outside of NERC's existing
procedures. Furthermore, the Commission believes that regardless of the
process used, the result could lead to inconsistent reliability
requirements within and across reliability regions. While the
Commission recognizes that some variation among regions or entities is
reasonable given varying grid topography and other legitimate
considerations, there are no technical or other criteria to determine
whether varied results are arbitrary or based on meaningful
distinctions. While the Commission acknowledges that NERC has
flexibility in developing alternative approaches, we believe that the
proposed approach is not equally efficient or effective as the
Commission's directives and that NERC has failed to provide a strong
technical justification for its proposal.
12. As an initial matter, the Commission is concerned that the
process lacks parameters. The 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.'' \18\ However, 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. Indeed, NERC's explanation appears to confirm this concern,
as NERC explained that Regional Entities' involvement is limited to
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'.
---------------------------------------------------------------------------
\18\ NERC Petition at 10.
---------------------------------------------------------------------------
13. Further, the Commission is concerned that 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 TPL-002-0a Reliability Standard requires Planning Authorities and
Transmission Planners to 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\ Moreover, the planner must consider all single
contingencies applicable to Table I, Category B and demonstrate that
system performance is met. For those instances where system performance
is not met, the 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.\20\ In
regard to NERC's proposal, the Commission is concerned that footnote
`b' would function 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. In this case NERC has
provided no technically sound means of determining situations in which
planning to interrupt Firm Demand would be allowable, and instead has
removed such decision-making to an unspecified stakeholder process
without any assurance that such processes will deploy technically sound
means of approving or denying exceptions. Without any technical or
other criteria specified to determine when planning to interrupt Firm
Demand would be allowable, the Commission is concerned that 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. While
the Commission recognizes that some variation among regions or entities
is reasonable given varying grid topography and other legitimate
considerations, there are no technical or other criteria to determine
whether varied results are arbitrary or based on meaningful
distinctions. The Commission is thus concerned that there may be a lack
of consistency in determinations to allow the planned interruption of
Firm Demand. The proposed stakeholder process does not have any
parameters except for openness and transparency. As a result, multiple
processes that could be adopted across the country would likely lead to
inconsistent determinations to allow for the planned interruption of
Firm Demand.
---------------------------------------------------------------------------
\19\ Reliability Standard TPL-002-0a, Requirement R1.
\20\ Reliability Standard TPL-002-0a, Requirements R1.5 and R2.
---------------------------------------------------------------------------
14. The Commission believes that a remand would give 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.
A. Lack of Technical or Other Criteria
15. NERC's proposal does not prescribe the criteria that would
define the parameters of permissible interruption of Firm Demand. In
Order No. 693 the Commission expressed concern that, as a general rule,
footnote `b' should not allow an entity to plan for the loss of non-
consequential load in the event of a single contingency and directed
NERC to clarify the standard. The Commission stated in the June 2010
Order that a regional difference or a case-specific exception process
that could be technically justified would be acceptable. While the
Commission allows NERC to propose an equally effective and efficient
solution to a Commission's proposed solution, the Commission does not
believe that the proposal is equally effective and efficient. First,
NERC's proposed footnote `b' contains no constraints and could allow an
entity to plan to interrupt any amount of 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. This
result is contrary to the underlying standard and our prior orders.\21\
Further, NERC did not technically justify its proposal, instead relying
on the benefit of having transparency in the process. The Commission
does not believe transparency in this instance can substitute for a
technical justification.
---------------------------------------------------------------------------
\21\ See Order No. 693, see also June 2010 Order.
---------------------------------------------------------------------------
16. In its supplemental filing, NERC states that it is not feasible
for the ERO to develop a one-size-fits-all criterion for limiting the
planned interruption of Firm Demand due to the wide variety of system
configurations and regulatory compacts.\22\ NERC states that the
standards drafting team believes there is no analytical data to support
a single level and therefore any single value was viewed as arbitrary.
---------------------------------------------------------------------------
\22\ NERC Data Response at 6.
---------------------------------------------------------------------------
17. We are not persuaded by NERC's reasoning. First, both NERC and
the Commission have developed thresholds in other reliability contexts
that have overcome similar claims of arbitrariness. For example, the
threshold for conducting vegetation management pursuant to Reliability
Standard FAC-003-1 applies to all transmission lines operated at 200 kV
and above.\23\ In the
[[Page 66233]]
same vein, NERC's Statement of Compliance Registry Criteria has
numerous thresholds for determining eligibility for registration.\24\
The Commission did not suggest a one size fits all exceptions process.
If the ERO were to perform an exception process, it might include
flexibility in decisions based on disparate topology or on other
matters since it could utilize its technical expertise to determine the
reliability impact from one region to another. Moreover, the
Commission's proposal to remand revised footnote `b' due to a lack of
criteria does not preclude NERC from developing another alternative,
provided that it is equally ``efficient and effective.''
---------------------------------------------------------------------------
\23\ Reliability Standard FAC-003-1.
\24\ See, e.g., NERC Statement of Registry Criteria, Section
III. The Commission approved Statement of Registry Criteria in Order
No. 693.
---------------------------------------------------------------------------
18. Finally, the Commission understands that there are a wide
variety of system configurations and regulatory compacts. NERC
indicates that the standards drafting team considered a variety of
limits; however, it is not clear whether NERC considered a blend of
quantitative and qualitative thresholds. For example, a standard could
require a process with a quantitative limitation on how much Firm
Demand could be planned for interruption and that 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.\25\ In short, we believe that a more
defined process would be needed but, by itself, would not be adequate
without NERC-defined technical or other criteria to determine planned
interruption of Firm Demand. The Commission seeks comment on these
proposals.
---------------------------------------------------------------------------
\25\ While we encourage NERC to exercise flexibility in
designing an appropriate standard, under this example, the exception
process could consist of a stakeholder process that has some level
of due process as long as that process does not allow the entity
that proposes its exception to make the decision on whether to grant
the exception.
---------------------------------------------------------------------------
B. Stakeholder Process
19. The Commission believes that NERC's proposed footnote `b'
stakeholder process does not meet Order No. 693 and the June 2010 Order
directive. According to NERC, the type of stakeholder process used
under its proposed footnote `b' can vary from one planning entity to
the next. NERC offers several stakeholder processes as examples, such
as the Order 890-type process, a state public utility commission or
local jurisdiction process, or a Regional Transmission Organization/
Independent System Operator (RTO/ISO) stakeholder process.
20. First, because NERC's proposed footnote `b' does not define the
stakeholder process, the express terms of the standard would allow an
applicable entity to form or participate in any stakeholder process and
be compliant with the proposed standard. Second, as we have mentioned,
NERC has offered no technical justification for exceptions to be
granted through the stakeholder process and therefore no means for the
Commission to judge whether the process will protect the reliability of
the Bulk-Power System. 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 is concerned that any meeting that is open to
stakeholders could meet this standard. Further, because the stakeholder
process is not defined, the proposal could allow a transmission planner
to develop a process that provides insufficient process and
transparency and still comply with the standard. The Commission
believes that such process would be insufficient because it allows any
stakeholder process to essentially become a reliability standards
development processes outside of NERC's existing procedures.
Furthermore, the Commission believes that regardless of the stakeholder
process used, the outcome could lead to inconsistent results, with no
technical or other criteria to determine whether varied results are
arbitrary or based on meaningful distinctions. The Commission seeks
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.
21. Nor does the standard describe what would be entailed in
addressing the stakeholder comments. As described above, the process
under the standard does not provide for any technical rigor to address
stakeholder concerns. While the standard requires transparency and an
opportunity for stakeholder comments on the transmission planner's
proposed plan to interrupt Firm Demand, it does not mandate any
particular stakeholder involvement, nor does it mandate that interested
governmental authorities be afforded notice and an opportunity to
comment. As we read the proposed standard, a responsible entity could
define when it would plan to interrupt Firm Demand on its own, then ask
for stakeholder input on that plan. While the standard requires the
responsible entity to ``address'' stakeholder comments, the responsible
entity is not required to specify or support the technical basis upon
which it rendered a decision. The Commission believes that the
stakeholder process in proposed footnote `b' would allow the
transmission planner to define the circumstances when it would rely on
planned interruption of Firm Demand, provide that definition for review
by regulators and other stakeholders, receive comments from regulators
and stakeholders requesting a more narrow definition, and explain to
the regulators and stakeholders why it is declining the request and
maintaining the broader definition, even if every other transmission
planner facing similar circumstances would reach the opposite
conclusion.
22. In Order No. 693 and the June 2010 Order, the Commission stated
that a regional difference or a case-specific exception process, among
other things, would be an acceptable approach. With regard to a case-
specific process, NERC replied it would ``create undesirable delays and
uncertainty in the transmission planning process.'' \26\ However, the
proposed footnote `b' does not provide a time limitation by which
planning decisions to interrupt Firm Demand must be made. The
Commission is not persuaded that NERC's proposed approach ameliorates
this concern. The Commission seeks comment on whether an exceptions
process that provides defined criteria, with some allowance or
consideration for unique circumstances, could be crafted that would
resolve NERC's concerns of ``undesirable delays'' and ``uncertainty.''
---------------------------------------------------------------------------
\26\ NERC Data Response at 2.
---------------------------------------------------------------------------
23. In sum, the Commission is concerned that the stakeholder
process set forth in the NERC proposal is not sufficiently defined,
rendering it potentially unenforceable. As mentioned above, the
proposed stakeholder process includes no parameters other than openness
and transparency. NERC states that it and the Regional Entities will
review a responsible entity's decision to plan to interrupt Firm Demand
using an after-the-fact audit, to determine if the entity's
implementation of footnote `b' to plan Firm Demand interruption and
whether the decision by the entity was vetted through the stakeholder
process and qualified as one of the situations
[[Page 66234]]
identified in footnote `b.' \27\ The Commission believes that this
could result in a transmission planner invoking a process that provides
for minimal stakeholder involvement, providing scant reasons to reject
any stakeholder input and then defending its decision by claiming that
it has satisfied the provision. While the Compliance Enforcement
Authority would verify that the process fulfilled the letter of NERC's
proposed footnote `b'--that some open, transparent stakeholder process
was involved and that the responsible entity in some way addressed
stakeholder concerns--there is no mechanism for the ERO or a Regional
Entity to enforce a finding that the evidence does not support an
acceptable instance of planned interruption of Firm Demand. The
Commission seeks comment on the concerns raised above.
---------------------------------------------------------------------------
\27\ NERC Data Response at 7-8.
---------------------------------------------------------------------------
C. Commission Proposal
24. The Commission believes that NERC's proposed footnote `b' does
not meet the Commission's Order No. 693 directives, nor is it an
equally effective and efficient alternative. On this basis, the
Commission proposes to remand the proposal to NERC.
25. The Commission also proposes to provide further guidance on
acceptable approaches to footnote `b'. We seek comment on all of the
options below. In addition, while the Commission is proposing certain
options for revising footnote `b', we also seek comment on other
potential options to solve the concerns outlined in this NOPR. As noted
above, the Commission understands that there are a wide variety of
system configurations and regulatory compacts. We believe that a more
defined process than that provided in the proposed footnote `b' would
be needed but, by itself, would not be adequate without NERC-defined
technical or other criteria to determine an acceptable planned
interruption of Firm Demand at the fringes of the system.\28\
---------------------------------------------------------------------------
\28\ Any exceptions process to determine specific requests for
planned interruption of Firm Demand may not necessarily be limited
to the fringes of the system.
---------------------------------------------------------------------------
26. We acknowledge that the standards drafting team considered a
variety of limits; however, setting some form of criteria within the
standard itself for planning to interrupt Firm Demand may be an
acceptable approach to setting criteria for footnote `b' and would be
an option for NERC to consider. We also seek comment on whether
existing protocols could provide guidance to NERC in devising criteria.
For example, the Department of Energy's Electric Emergency Incident and
Disturbance Report (Form OE-417) requires, among other things, an
entity to report the uncontrolled loss of 300 Megawatts or more of firm
system loads for more than 15 minutes from a single incident, load
shedding of 100 Megawatts or more implemented under emergency
operational policy, and the loss of service for more than 1 hour to
50,000 customers. While these are reporting requirements for the
operational timeframe, and may include distribution level load
shedding, the Commission requests comments on whether they could also
serve as a basis for setting limits on when an entity can plan to
interrupt Firm Demand on the Bulk-Power System. Another existing
document that could provide guidance on how to set a limit on the
planned interruption of Firm Demand is NERC's Statement of Compliance
Registry Criteria, which uses, for example, 25 MW as a threshold in
determining when a load-serving entity or distribution provider should
register with NERC. We seek comments on this proposed option, and any
other external documents that could be used to guide a revision to
footnote `b.'
27. Second, as stated above, it is not clear whether NERC
considered a blend of quantitative and qualitative thresholds. The
Commission seeks comments on whether this would be an option for
providing criteria that would be generally applicable, but also for
allowing for certain cases that may exceed the criteria. For example, a
standard could require a process with a quantitative limitation on how
much Firm Demand could be planned for interruption and that 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. NERC has raised concerns
about conflicts among federal, provincial, state and local governing
bodies that have jurisdiction over various parts of the planning,
siting and construction process. The Commission believes that this
approach may satisfy the need for technical criteria that we have
described, 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. As NERC
states, the objective of footnote `b' should be to minimize the
likelihood and magnitude of planned Firm Demand interruptions. The
Commission believes 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. We seek comment on this option, and which entities
should be involved in the review and subsequent determination as to
whether an exception should be allowed.
28. NERC has raised concerns about conflicts among federal,
provincial, state and local governing bodies that have jurisdiction
over various parts of the planning, siting and construction process.
There also may be concerns about the costs of planning to avoid Firm
Demand shedding. The Commission seeks 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. This presumably would not
require affirmative consent by every individual retail customer, but we
recognize that either term, customer or community, would need to be
adequately defined. The Commission therefore seeks comments on who
might be able to represent the customer or community in this option and
how customer or community consent might be demonstrated. Additionally,
we seek comment on how it would be determined that firm demand shedding
with customer consent would not adversely impact the Bulk-Power System.
However, we also seek 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.
29. Finally, regardless of how NERC revises footnote `b' to resolve
the concerns outlined in this NOPR and in previous orders, the
Commission notes that NERC will need to support the revision to
footnote `b.' If there is a threshold component to the revised
footnote, the Commission believes that 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 Commission
[[Page 66235]]
believes that 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, we believe that any exception should be subject to further
review by the Regional Entity, NERC, and the Commission. This does not
necessarily mean that the Regional Entity, NERC, or the Commission
should have to approve the exception, but that any of the three could
later audit its implementation.
30. In conclusion, while the Commission provides three options for
revising footnote `b' in this Notice of Proposed Rulemaking, we seek
comments on the feasibility of the options and on ways in which the
options might be improved. In addition, we seek comment on whether
there are other ways for NERC to solve the concerns outlined above in
an equally effective and efficient manner.
III. Information Collection Statement
31. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\29\ The information contained here
is also subject to review under section 3507(d) of the Paperwork
Reduction Act of 1995.\30\
---------------------------------------------------------------------------
\29\ 5 CFR 1320.11.
\30\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------
32. As stated above, the subject of this NOPR is NERC's proposed
modification to Table 1, footnote `b' applicable in four TPL
Reliability Standards. This NOPR proposes to remand 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 NOPR to OMB for
informational purposes only.
33. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street, NE. Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, e-mail:
data.clearance@ferc.gov, phone: (202) 502-8663, or fax: (202) 273-
0873].
IV. Regulatory Flexibility Act
34. The Regulatory Flexibility Act of 1980 (RFA) \31\ 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.\32\
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.\33\ The RFA is not
implicated by this NOPR 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 NOPR will not have a
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------
\31\ 5 U.S.C. 601-612.
\32\ 13 CFR 121.201.
\33\ Id. n.22.
---------------------------------------------------------------------------
V. Comment Procedures
35. 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 60 days from publication in the Federal
Register. Comments must refer to Docket No. RM11-18-000, and must
include the commenter's name, the organization they represent, if
applicable, and their address in their comments.
36. 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.
37. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street, NE.,
Washington, DC 20426.
38. 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
39. 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.
40. 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.
41. 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. Commissioner Spitzer is not
participating.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2011-27624 Filed 10-25-11; 8:45 am]
BILLING CODE 6717-01-P
