Federal Register / Vol. 72, No. 142 / Wednesday, July 25, 2007 / Rules and Regulations
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Federal Register / Vol. 72, No. 142 / Wednesday, July 25, 2007 / Rules and Regulations
The Rule
This action amends Title 14 Code of
Federal Regulations (14 CFR) part 71 to
establish an RNAV route within the
airspace assigned to the Seattle, Los
Angeles, Albuquerque, Salt Lake City
and Denver Air Route Traffic Control
Center (ARTCC). This route provides a
direct route from the Seattle, WA area
to Phoenix, AZ, and facilitates a more
flexible and efficient use of navigable
airspace for en route instrument flight
rules operations.
The FAA has determined that this
regulation only involves an established
body of technical regulations for which
frequent and routine amendments are
necessary to keep them operationally
current. Therefore, this regulation: (1) Is
not a ‘‘significant regulatory action’’
under Executive Order 12866; (2) is not
a ‘‘significant rule’’ under Department of
Transportation (DOT) Regulatory
Policies and Procedures (44 FR 11034;
February 26, 1979); and (3) does not
warrant preparation of a regulatory
Q–35 IMB to DRK [new]
IMB ................................................................
NEERO ...........................................................
WINEN ...........................................................
CORKR ...........................................................
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Issued in Washington, DC, on July 18,
2007.
Edith V. Parish,
Manager, Airspace and Rules Group.
[FR Doc. E7–14326 Filed 7–24–07; 8:45 am]
BILLING CODE 4910–13–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM06–16–001; Order No. 693–
A]
Mandatory Reliability Standards for the
Bulk-Power System
Issued July 19, 2007.
AGENCY: Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule; order on rehearing.
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SUMMARY: The Commission denies
rehearing and otherwise reaffirms its
determinations in Order No. 693. 72 FR
16,416 (April 4, 2007). We further
clarify certain portions of the Preamble
to that order. Order No. 693 approved
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evaluation as the anticipated impact is
so minimal. Since this is a routine
matter that will only affect air traffic
procedures and air navigation, it is
certified that this rule, when
promulgated, will not have a significant
economic impact on a substantial
number of small entities under the
criteria of the Regulatory Flexibility Act.
Environmental Review
The FAA has determined that this
action qualifies for categorical exclusion
under the National Environmental
Policy Act in accordance with FAA
Order 1050.1E, ‘‘Environmental
Impacts: Policies and Procedures’’,
paragraph 311a. This airspace action is
not expected to cause any potentially
significant environmental impacts, and
no extraordinary circumstances exist
that warrant preparation of an
environmental assessment.
List of Subjects in 14 CFR Part 71
Airspace, Incorporation by reference,
Navigation (air).
VORTAC ........................................................
WP .................................................................
WP .................................................................
Fix ..................................................................
VORTAC ........................................................
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The Proposed Amendment
■ In consideration of the foregoing, the
Federal Aviation Administration
amends 14 CFR part 71 as follows:
PART 71—DESIGNATION OF CLASS A,
B, C, D, AND E AIRSPACE AREAS; AIR
TRAFFIC SERVICE ROUTES; AND
REPORTING POINTS
■ 1. The authority citation for part 71
continues to read as follows:
Authority: 49 U.S.C. 106(g), 40103, 40113,
40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–
1963 Comp., p. 389.
§ 71.1
[Amended]
■ 2. The incorporation by reference in
14 CFR 71.1 of FAA Order 7400.9P,
Airspace Designations and Reporting
Points, dated September 1, 2006, and
effective September 15, 2006, is
amended as follows:
Paragraph 2006
Area Navigation Routes.
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(Lat. 44°38′54″ N., long. 119°42′42″ W.)
(Lat. 41°49′03″ N., long. 118°01′29″ W.)
(Lat. 37°56′00″ N., long. 113°30′00″ W.)
(Lat. 36°05′02″ N., long. 112°24′01″ W.)
(Lat. 34°42′09″ N., long. 112°28′49″ W.)
83 of 107 proposed Reliability
Standards, six of the eight proposed
regional differences, and the Glossary of
Terms Used in Reliability Standards
developed by the North American
Electric Reliability Corporation, which
the Commission has certified as the
Electric Reliability Organization (ERO)
responsible for developing and
enforcing mandatory Reliability
Standards. Order No. 693 also required
the ERO to submit significant
improvements to 56 of the 83 Reliability
Standards that are being approved as
mandatory and enforceable. Finally,
Order No. 693 provided that the
remaining 24 Reliability Standards will
remain pending at the Commission until
further information is provided. Order
No. 693 adds a new part to the
Commission’s regulations, which states
that this part applies to all users, owners
and operators of the Bulk-Power System
within the United States (other than
Alaska or Hawaii) and requires that each
Reliability Standard identify the subset
of users, owners and operators to which
that particular Reliability Standard
applies. The new regulations also
require that each Reliability Standard
that is approved by the Commission will
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be maintained on the ERO’s Internet
website for public inspection.
DATES: Effective Date: The final rule
became effective on June 18, 2007.
FOR FURTHER INFORMATION CONTACT:
Jonathan First (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–8529.
Christy Walsh (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–6523.
Robert Snow (Technical Information),
Office of Energy Markets and
Reliability, Division of Reliability,
Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
6716.
SUPPLEMENTARY INFORMATION:
Before Commissioners: Joseph T. Kelliher,
Chairman; Suedeen G. Kelly, Marc
Spitzer, Philip D. Moeller, and Jon
Wellinghoff.
Order on Rehearing
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Federal Register / Vol. 72, No. 142 / Wednesday, July 25, 2007 / Rules and Regulations
Paragraph
I. Introduction ...........................................................................................................................................................................................
A. Summary of Order No. 693 .........................................................................................................................................................
B. Procedural Matters ........................................................................................................................................................................
II. Discussion ............................................................................................................................................................................................
A. Applicability Issues ......................................................................................................................................................................
1. Bulk-Power System v. Bulk Electric System ........................................................................................................................
2. NERC Registry ........................................................................................................................................................................
3. Use of the NERC Functional Model ......................................................................................................................................
B. Mandatory Reliability Standards .................................................................................................................................................
1. Prioritizing Modifications to Reliability Standards .............................................................................................................
2. Trial Period ............................................................................................................................................................................
C. Common Issues Pertaining to Reliability Standards ..................................................................................................................
1. Blackout Report Recommendation on Liability Limitations ...............................................................................................
2. Fill-in-the-Blank Standards ...................................................................................................................................................
D. Discussion of Individual Reliability Standards ..........................................................................................................................
1. EOP–001–0 .............................................................................................................................................................................
2. EOP–002–2 .............................................................................................................................................................................
3. EOP–008–0 .............................................................................................................................................................................
4. FAC–003–1 .............................................................................................................................................................................
5. IRO–001–1 ..............................................................................................................................................................................
6. IRO–005–1 and IRO–005–2 ...................................................................................................................................................
7. MOD–013–1 ............................................................................................................................................................................
8. PRC–007–0, PRC–008–0, and PRC–009–0 ............................................................................................................................
9. TOP–008–1 .............................................................................................................................................................................
III. Information Collection Statement ......................................................................................................................................................
IV. Document Availability .......................................................................................................................................................................
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I. Introduction
1. On March 16, 2007, the
Commission issued a Final Rule (Order
No. 693) 1 approving, pursuant to
section 215 of the Federal Power Act
(FPA),2 83 of 107 proposed Reliability
Standards, six of the eight proposed
regional differences, and the Glossary of
Terms Used in Reliability Standards
(glossary) developed by the North
American Electric Reliability
Corporation (NERC), which the
Commission has certified as the Electric
Reliability Organization (ERO)
responsible for developing and
enforcing mandatory Reliability
Standards. However, the Commission
stated that, although it believed it is in
the public interest to make these
Reliability Standards mandatory and
enforceable, it also found that much
work remains to be done. Specifically,
it stated that many of these Reliability
Standards require significant
improvement to address, among other
things, the recommendations of the
Blackout Report.3 Therefore, pursuant to
section 215(d)(5), we required the ERO
to submit significant improvements to
56 of the 83 Reliability Standards that
are being approved as mandatory and
enforceable. The Commission stated that
1 Mandatory Reliability Standards for the BulkPower System, Order No. 693, 72 FR 16,416 (Apr.
4, 2007), FERC Stats. & Regs. ¶ 31,242 (2007).
2 16 U.S.C. 824o (2000).
3 U.S.-Canada Power System Outage Task Force,
Final Report on the August 14 Blackout in the
United States and Canada: Causes and
Recommendations (April 2004) (Blackout Report).
The Blackout Report is available on the Internet at
http://www.ferc.gov/cust-protect/moi/blackout.asp.
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the remaining 24 Reliability Standards
will remain pending at the Commission
until further information is provided.
2. Order No. 693 added a new part to
the Commission’s regulations, which
states that this part applies to all users,
owners and operators of the Bulk-Power
System within the United States (other
than Alaska or Hawaii) and requires that
each Reliability Standard identify the
subset of users, owners and operators to
which that particular Reliability
Standard applies. The new regulations
also require that each Reliability
Standard that is approved by the
Commission will be maintained on the
ERO’s Internet Web site for public
inspection.
A. Summary of Order No. 693
3. In Order No. 693, the Commission
stated that there were four possible
courses of action that it would take with
regard to each proposed Reliability
Standard: (1) Approve; (2) approve as
mandatory and enforceable; and direct
modification pursuant to section
215(d)(5); (3) request additional
information; or (4) remand. As
mentioned above, the Commission
approved 83 Reliability Standards and
directed NERC to develop modifications
to 56 of the approved Reliability
Standards. In approving the Reliability
Standards, Order No. 693 stated that, for
an initial period, the Commission would
rely on the NERC definition of bulk
electric system, rather than the statutory
Bulk-Power System, and NERC’s
registration process to provide as much
certainty as possible regarding the
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57
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61
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100
120
123
132
153
156
157
applicability to and the responsibility of
specific entities to comply with the
Reliability Standards in the start-up
phase of a mandatory Reliability
Standard regime.4 Further, while the
Commission did not institute a formal
‘‘trial period,’’ it directed the ERO and
Regional Entities to ‘‘focus their
resources’’ on the ‘‘most serious
violations’’ during an initial period
through December 31, 2007.5
B. Procedural Matters
4. The following entities have filed
timely requests for rehearing or for
clarification of Order No. 693: American
Public Power Association (APPA);
Avista Corporation, Portland General
Electric Company, and Puget Sound
Energy, Inc. (collectively, Avista); City
of Santa Clara, California (Santa Clara);
Cogeneration Association of California
and the Energy Producers and Users
Coalition (California Cogeneration); ISONew England, Inc. (ISO-New England);
Midwest Independent Transmission
System Operator, Inc. (Midwest ISO);
National Association of Regulatory
Utility Commissioners (NARUC);
National Rural Electric Cooperative
Association (NRECA); Pacific Northwest
Security Coordinator (PNSC);
Transmission Agency of Northern
California (TANC); and Xcel Energy
Services, Inc. (Xcel).
5. PNSC’s rehearing request is
deficient because it fails to include a
Statement of Issues section separate
from its arguments, as required by Rule
4 Order No. 693 at P 75.
5 Id. at P 221–22.
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713 of the Commission’s Rules of
Practice and Procedure.6 Rule 713(c)(2)
requires that a rehearing request must
include a separate section entitled
‘‘Statement of Issues’’ listing each issue
presented to the Commission in a
separately enumerated paragraph that
includes representative Commission
and court precedent on which the
participant is relying.7 Under Rule 713,
any issue not so listed will be deemed
waived. Accordingly, we will dismiss
PNSC’s rehearing request.8
6. In any event, PNSC’s arguments on
rehearing are beyond the scope of this
proceeding. PNSC asks the Commission
to clarify that PNSC is in compliance
with IRO–001 because it has written
agreements delineating the
responsibilities and authority of the
operating personnel who staff its
reliability center. Whether any one
entity is in compliance with a
Reliability Standard is not an issue in
the rulemaking.
II. Discussion
A. Applicability Issues
1. Bulk-Power System v. Bulk Electric
System
7. Section 215 of the FPA defines the
term ‘‘Bulk-Power System’’ as follows:
(A) facilities and control systems necessary
for operating an interconnected electric
energy transmission network (or any portion
thereof) and (B) electric energy from
generating facilities needed to maintain
transmission system reliability. The term
does not include facilities used in the local
distribution of electric energy.
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8. The NERC glossary, in contrast,
states that Reliability Standards apply to
the ‘‘bulk electric system,’’ which is
6 18 CFR 385.713(c)(2) (2006). See Revision of
Rules of Practice and Procedure Regarding Issue
Identification, Order No. 663, 70 FR 55,723
(September 23, 2005), FERC Stats. and Regs.
¶ 31,193 (2005). See also, Order 663–A, effective
March 23, 2006, which amends Order No. 663 to
limit its applicability to rehearing requests.
Revision of Rules of Practice and Procedure
Regarding Issue Identification, Order No. 663–A, 71
FR 14,640 (March 23, 2006), FERC Stats. and Regs.
¶ 31,211 (2006) (codified at 18 CFR 385.713(c)(2)
(2006)).
7 As explained in Order No. 663, supra, the
purpose of this requirement is to benefit all
participants in a proceeding by ensuring that the
filer, the Commission, and all other participants
understand the issues raised by the filer, and to
enable the Commission to respond to these issues.
Having a clearly articulated Statement of Issues
ensures that issues are properly raised before the
Commission and avoids the waste of time and
resources involved in litigating appeals regarding
whether the courts of appeals lack jurisdiction
because the issues on appeal were not clearly
identified before the Commission. See Order No.
663 at P 3–4.
8 See, e.g., Duke Power Co., LLC, 116 FERC
¶ 61,171 (2006); and South Carolina Electric & Gas
Co., 116 FERC ¶ 61,218 (2006).
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defined by its regions in terms of a
voltage threshold and configuration, as
follows:
As defined by the Regional Reliability
Organization, the electrical generation
resources, transmission lines,
interconnections with neighboring systems,
and associated equipment, generally operated
at voltages of 100 kV or higher. Radial
transmission facilities serving only load with
one transmission source are generally not
included in this definition.
9. In Order No. 693, the Commission
stated that, for an initial period, it
would rely on the NERC definition of
bulk electric system and NERC’s
registration process to provide as much
certainty as possible regarding the
applicability to and the responsibility of
specific entities to comply with the
Reliability Standards in the start-up
phase of a mandatory Reliability
Standard regime.9 However, the
Commission stated that it was
concerned about the need to address the
potential for gaps in coverage of
facilities. The Commission intends to
address this matter in future
proceedings. As a first step in enabling
the Commission to understand the reach
of the Reliability Standards, we directed
the ERO to provide the Commission
with an informational filing that
includes a complete set of regional
definitions of bulk electric system and
any regional documents that identify
critical facilities to which the Reliability
Standards apply (i.e., facilities below a
100 kV threshold that have been
identified by the regions as critical to
system reliability).
10. However, the Commission
disagreed with commenters who
suggested that there is no intentional
distinction between Bulk-Power System
and bulk electric system. This
distinction was evidenced by the fact
that ‘‘Congress did not borrow the term
of art—bulk electric system—but instead
chose to create a new term, Bulk-Power
System, with a definition that is distinct
from the term of art used by
industry.’’ 10 Thus, the Commission
‘‘confirmed’’ that the Bulk-Power
System reaches farther than those
facilities that are included in NERC’s
definition of the bulk electric system,
although choosing to rely on the NERC
definition for determining the
immediate applicability of the approved
Reliability Standards. The Commission
indicated that it remained concerned
about potential gaps in coverage of
facilities and that any change in
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9 Order No. 693 at P 75.
10 Id. at P 76.
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applicability would be addressed in
future Commission proceedings.
a. Requests for Rehearing
11. NRECA asks that the Commission
clarify that it has not definitively
decided that the term Bulk-Power
System as defined in section 215 of the
FPA encompasses more than NERC’s
definition of bulk electric system.
Rather, NRECA understands that the
Commission deferred on determining
whether its jurisdiction expands beyond
the bounds of the bulk electric system.
NRECA is concerned that Order No. 693
may suggest that the Bulk-Power System
is broader than the bulk electric system
out of a misapprehension that NERC’s
definition imposes a rigorous 100 kV
‘‘cutoff’’ when, according to NRECA, it
actually provides for more flexibility.
Alternatively, if the Commission has
definitively interpreted the term BulkPower System to encompass more than
the bulk electric system, NRECA seeks
rehearing.
12. In support of its request for
rehearing, NRECA raises three
arguments that the Commission erred in
determining that the statutory definition
of Bulk-Power System is broader than
NERC’s definition of bulk electric
system. First, it contends that such a
determination violates a rule of law that
the parts of a statute should be
construed in accordance with the
statute’s overall legislative purpose.11
NRECA explains that section 215 was
intended to replace the prior voluntary
reliability standards with a mandatory
scheme but, to the best of NRECA’s
knowledge, no participant in the
drafting of the legislation expressed the
view that Congress intended to expand
NERC’s scope.12 NRECA states that, if
the issue had been presented, it would
have prompted a legislative record. The
absence of such record confirms that an
intent to expand NERC’s scope was
never expressed.
13. Second, NRECA contends that an
expansive definition of Bulk-Power
System is contrary to the text of section
215, which narrows the Commission’s
reach. Specifically, NRECA contends
that the statutory definition of BulkPower System makes clear that the term
does not encompass all transmission
facilities but, rather, only those facilities
and control systems ‘‘necessary for
operating an interconnected electric
energy transmission network.’’ It also
points to the statutory definitions of
Reliability Standard and Reliable
11 NRECA at 7–11, citing United States v. Public
Utilities Commission of California, 345 U.S. 295,
315 (1953).
12 NRECA at 7–8.
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Operation that refer to protecting the
system from instability, uncontrolled
separation or cascading failures. NRECA
infers from this that there is no reason
to conclude that Congress included in
the definition of Bulk-Power System any
facilities other than those that could
materially contribute to instability,
uncontrolled separation or cascading
outages.
14. Third, NRECA posits that, if
Congress borrows a term of art that has
an established meaning, the established
meaning is to apply.13 NRECA claims
that the terms Bulk-Power System and
bulk electric system have been used
interchangeably for decades and cites
examples from both industry documents
and Commission orders. According to
NRECA, Congress did not adopt NERC’s
exact definition of bulk electric system
because it was insufficiently specific for
legislation. NRECA asserts that
‘‘Congress used more and different
words than NERC in order to provide
clarity, but the definition of Bulk-Power
System incorporated the exact same
facilities as NERC and the regions had
always included in their working
definition of bulk electric system
* * *’’ 14
15. NARUC seeks clarification that the
Commission will ‘‘continue relying on
NERC’s definition of Bulk-Power
System’’ and NERC’s registration
process beyond the initial period during
which mandatory Reliability Standards
are in effect.15 It states that section 215
of the FPA was enacted based on an
industry consensus that it would apply
to facilities and entities covered by the
historical definition of Bulk-Power
System. According to NARUC, the term
applies to higher-voltage, network
facilities that integrate regional
transmission networks to ensure the
reliability of interconnected system
operations. NARUC states that NERC’s
definition of Bulk-Power System is
consistent with section 215 and that a
broader interpretation is inconsistent
with Congressional intent because such
a definition could sweep in facilities
such as load centers and local
transmission facilities that do not have
a material impact on system reliability.
16. NARUC also seeks clarification
that, if the Commission determines that
NERC’s current definition requires
13 Id. at 11–16, citing Morissette v. United States,
342 U.S. 246, 263 (1952).
14 NRECA at 16.
15 NARUC at 3. NARUC refers repeatedly to
‘‘NERC’s definition of Bulk-Power System.’’ It is not
clear from NARUC’s pleading whether this is
simply a typographical error or it seeks to make a
point that NERC’s definition of bulk electric system
is equivalent to the statutory term Bulk-Power
System.
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revision, NERC should revise the
definition using its American National
Standards Institute (ANSI)-accredited
process. Further, NARUC expresses
concern that the Commission has
directed the ERO to submit a complete
set of regional definitions of bulk
electric system and, thus, asks the
Commission to clarify that it will
continue to defer to the ERO’s and
Regional Entities’ determinations
concerning which facilities and entities
materially affect the reliability of the
interconnected transmission network
and should be included in the
compliance registry.
b. Commission Determination
17. The Commission will grant
NRECA’s request for clarification, and
thus dismisses its request for rehearing.
We agree with NRECA that NERC’s
definition of bulk electric system does
not impose a 100 kV cutoff and provides
some flexibility in its application.16
Although Order No. 693 stated that the
Commission believes that the BulkPower System reaches farther than those
facilities that are included in NERC’s
definition of the bulk electric system,
the Commission has not definitively
defined the extent of the facilities
covered by the Bulk-Power System. As
we stated in Order No. 693, the
Commission intends to address
concerns regarding the scope of the term
Bulk-Power System in future
proceedings. NRECA and others will not
be legally precluded from presenting
arguments in such a proceeding that the
terms Bulk-Power System and bulk
electric system encompass the same
facilities.
18. The Commission notes NRECA’s
assertion that the Commission’s
determination that the Bulk-Power
System reaches farther than the bulk
electric system is contrary to the text of
section 215 of the FPA. Because the
Commission has not definitively
defined the extent of the facilities
covered by the Bulk-Power System, the
Commission believes that this
determination is best made in the
context of a Commission proceeding
determining the extent of the BulkPower System. We make no finding on
the matter at this time. The Commission
defers judgment on this matter to a later
proceeding so that the Commission can
develop a record on which to base its
final determination.
19. In response to NARUC, the
Commission will continue to rely on
16 See Mandatory Reliability Standards for the
Bulk Power System, Notice of Proposed
Rulemaking, 71 FR 64,770 (Nov. 3, 2006), FERC
Stats. & Regs., ¶ 32,608 at P 63 (2006).
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NERC’s definition of bulk electric
system, with the appropriate regional
differences, and NERC’s registration
process until the Commission
determines in future proceedings the
extent of the Bulk-Power System. The
requirement that the ERO file a
complete set of regional differences was
to enable the Commission to understand
the current reach of the Reliability
Standards. However, we do not agree
with NARUC that NERC should be
allowed to define Bulk-Power System
using its American National Standards
Institute (ANSI)-accredited process. The
statutory term Bulk-Power System
defines the jurisdiction of the
Commission. Although the Commission
has chosen to defer, for the time being,
to the ERO as to which entities must
comply with Reliability Standards, the
fundamental matter of determining the
extent of Commission’s jurisdiction
cannot and will not be delegated to the
ERO.
2. NERC Registry
20. Order No. 693 accepted the ERO’s
compliance registry process as an
appropriate approach to identify the set
of entities that are responsible for
compliance with a particular Reliability
Standard.17 Further, Order No. 693
explained that NERC has developed a
Statement of Compliance Registry
Criteria that describes how NERC will
identify organizations that may be
candidates for registration and assign
them to the compliance registry. NERC’s
compliance registry process identifies
and registers entities based on categories
of functions within the Bulk-Power
System and related Commissionapproved Reliability Standards. For
example, NERC plans to register
individual generator units of 20 MVA or
greater that are directly connected to the
bulk electric system, generating plants
with an aggregate rating of 75 MVA or
greater, any blackstart unit material to a
restoration plan, or any generator
‘‘regardless of size, that is material to
the reliability of the Bulk-Power
System.’’ The Commission accepted the
Statement of Compliance Registry
Criteria, stating that ‘‘[w]e believe that
NERC has set reasonable criteria for
registration* * *’’.18
21. Further, Order No. 693 noted that
the Commission’s regulations then
exempted most qualifying facilities
(QFs) from specific provisions of the
FPA including section 215.19 The
Commission, however, expressed
concerned whether it is appropriate to
17 Order No. 693 at P 92–101.
18 Id. at P 95.
19 18 CFR 292.601(c) (2006).
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grant QFs a complete exemption from
compliance with Reliability Standards
that apply to other generator owners and
operators, and noted that the
Commission was concurrently issuing a
notice of proposed rulemaking
proposing to amend the Commission’s
regulation that exempts most QFs from
section 215 of the FPA. The
Commission has since issued a final
rule eliminating the exemption of QFs
from the requirements of section 215 of
the FPA.20
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c. Requests for Rehearing
22. California Cogeneration argues
that the Commission improperly relied
on the ERO’s compliance registry
process. It contends that the
Commission, rather than determining
who the ‘‘users’’ of the Bulk-Power
System are, has improperly delegated
this task to the ERO and Regional
Entities. California Cogeneration notes
that the NERC registry criteria were
submitted for information purposes
only. Further, it contends that these
criteria are being applied inconsistently
among the Regional Entities, noting in
particular that Western Electricity
Coordinating Council (WECC) has
developed supplemental criteria that
may result in the registration of entities
not captured by the ERO criteria.21 It
also points to discrepancies in ERCOT’s
registration process.
23. California Cogeneration also
argues that Reliability Standards that are
not clear in how they are applied or are
applied inconsistently are not just and
reasonable. It contends that the
examples of regional variation in the
registration process demonstrate a lack
of required clarity and consistency.
24. NRECA asks the Commission to
clarify that, in expanding the
applicability of certain Reliability
Standards,22 it has not departed from
the compliance registry concept or
sought to dictate actions by the ERO.
Alternatively, the Commission should
grant rehearing. According to NRECA, it
20 Applicability of Federal Power Act Section 215
to Qualifying Small Power Production and
Cogeneration Facilities, Order No. 696, FERC
Statutes and Regulations ¶ 31,248 (2007).
21 California Cogeneration at 5, Referencing
WECC Supplemental Registration Criteria and
Dispute Resolution Process, available at http://
www.wecc.biz.
22 NRECA at 20–23. Specifically, NRECA cites the
Commission’s requirement that (1) COM–001–1, or
some replacement Reliability Standard addressing
black start capability, and COM–002–2 apply to all
distribution providers, (2) TOP–003–0 apply to all
load-serving entities, even those below specified
thresholds, based on the opinion of the
transmission operator, balancing authority, or
reliability coordinator, and (3) VAR–001–1 apply to
all load-serving entities. See Order No. 693 at P 487,
492, 512, 540, 1624, 1626, 1848, 1858 and 1990.
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appears possible, even likely, that the
Commission was not specifying that
additional entities register, but was
merely specifying that the ERO should
consider whether entities otherwise
required to register (because they meet
or exceed specified thresholds, or
because they had been to shown to have
a material impact on grid reliability)
should also be subject to these
particular Reliability Standards.23 If that
is the Commission’s intended meaning,
NRECA requests that the Commission
specify the requested clarification and
resolve the matter (subject to subsequent
consideration by the ERO). However, if
the Commission intends to impose a
broader obligation, i.e., to encompass
additional entities in the Reliability
Standards, then NRECA seeks rehearing.
25. Further, NRECA argues that the
Commission should not, as it recognized
in Order No. 672–A, prescribe either the
text or the substance of a Reliability
Standard, including which entities are
subject to the Reliability Standards,
because that responsibility is reserved to
the ERO, subject to the Commission’s
review. NRECA maintains that the
Commission lacks the authority to
dictate what a Reliability Standard
requires or who it encompasses, as the
Commission has recognized previously
in Order No. 672–A. NRECA notes that
Order No. 693 states that the
Commission ‘‘agrees that a direction for
modification should not be so overly
prescriptive as to preclude the
consideration of viable alternatives in
the ERO’s Reliability Standards
development process * * *. Thus, in
some instances, while we provide
specific details regarding the
Commission’s expectations, we intend
by doing so to provide useful guidance
to assist in the Reliability Standards
development process, not to impede
it.’’ 24
26. Beyond that, NRECA asserts that
the Reliability Standards should not
apply at all to entities whose scope of
activities is too limited to have a
material impact on grid reliability. In
other words, the specific Reliability
Standards should not apply to a
distribution provider or a load-serving
entity just because it is a distribution
provider or a load-serving entity;
instead, the Reliability Standards at
issue, as well as the Reliability
Standards generally, should not apply
23 NRECA at 20, citing see, e.g., Order No. 693 at
P 512 (‘‘APPA’s concern that 2,000 public power
systems would have to be added to the compliance
registry is misplaced, since, as we explain in our
Applicability discussed above, we are approving
NERC’s registry process, including the registry
criteria’’).
24 Order No. 693 at P 185–86.
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unless an entity has a material impact
on grid reliability. According to NRECA,
this concept is central to NERC’s
compliance registry, and the
Commission has not articulated a sound
basis for departing from it,
notwithstanding the Commission’s lack
of authority to do so.
27. With respect to COM–001–1 or
some replacement standard addressing
black start capability, and COM–002–2,
for example, NRECA asserts that some
entities are functionally irrelevant for
black start activities. It argues that
having to coordinate black start
operations with a large number of small
entities, most, if not all, of which are
served through interconnections with
larger and bigger entities in the
hierarchy of the Functional Model,
would hinder, rather than facilitate,
black start operations. NRECA
maintains that the Commission should
defer to the ERO’s technical expertise.
28. NRECA raises similar concerns
with respect to TOP–003–1. According
to NRECA, read literally, the
Commission appears to recommend
delegating the determination of whether
entities that fall below the threshold of
NERC’s definition of bulk electric
system should be subject to the standard
to ‘‘the opinion of the transmission
operator, balancing authority, or
reliability coordinator.’’ If so, NRECA
asserts that this approach would appear
to override both the compliance registry
and the ERO, and the Commission
would effectively delegate authority that
it does not have to entities that could
well face incentives to favor their own
interests over those of load-serving
entities that could be made subject to
the Reliability Standards. The
Commission cannot delegate authority it
does not have in the first place, and the
determination should be that of the ERO
and the Regional Entity. While NRECA
agrees that the ERO and the Regional
Entities may and should take the views
of the transmission operators, balancing
authorities, and reliability coordinators
into account, it argues that this is
considerably different than simply
abdicating the matter to them.
29. NRECA has similar concerns with
the treatment of VAR–001–1 with
respect to the Commission’s ‘‘direct[ing]
the ERO to address the reactive power
requirements of load-serving entities on
a comparable basis with purchasingselling entities.’’ While NRECA agrees
that this may be an appropriate matter
for the ERO to consider, it argues that
the Commission should not be dictating
a particular action, nor should the
Commission be overriding the
compliance registry approach that it
elsewhere endorses in its Final Rule.
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30. Accordingly, NRECA requests the
Commission to clarify that it has not
overridden the compliance registry with
respect to COM–001–1, COM–002–2,
and TOP–003–0, nor dictated specific
changes to those Reliability Standards.
Alternatively, NRECA seeks rehearing.
Absent the requested clarification,
NRECA asserts that the Commission has
sought to prescribe the substance of a
Reliability Standard in excess of its
statutory authority under section 215,
contrary to its own recognition of the
limitations on its authority in Order No.
672–A, and contrary to Order No. 693
itself. NRECA maintains that the
proposed changes could undermine
rather than enhance reliability for the
reasons stated, and thus involve matters
where the Commission should and is
required to defer to the ERO’s technical
expertise.
31. Xcel notes that, pursuant to
NERC’s registry criteria, NERC will
generally register individual generator
units of 20 MVA or greater that are
directly connected to the bulk electric
system. According to Xcel, under
NERC’s criteria, generators that are
connected to distribution facilities are
generally exempt from registration as
they are not connected to the BulkPower System. Xcel seeks rehearing of
the Commission’s decision to accept
this aspect of the ERO’s registration
process, contending that generating
facilities that are connected at a
distribution voltage but deliver energy
to the transmission system can affect
transmission system reliability and,
thus, should be subject to mandatory
Reliability Standards. Further, Xcel
contends that the exclusion of facilities
connected at a distribution level creates
inappropriate incentives for entities to
interconnect generating facilities at the
distribution level rather than the
transmission level.
32. TANC requests clarification of the
Commission’s statement that:
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we believe our concerns can be addressed by
having the ERO, through its compliance
registry process, ensure that each user, owner
and operator of the Bulk-Power System is
registered for each Requirement in the
Reliability Standards that relate to
transmission owners to assure there are no
gaps in coverage of the type discussed
here.[25]
33. According to TANC, this
statement seems to require all entities
subject to the Reliability Standards to
register for each requirement applicable
to transmission owners, which it states
is inconsistent with the Commission’s
goal of preventing overlap and negates
the transmission owner classification in
25 Id. at P 145.
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the NERC Functional Model. Therefore,
TANC asks the Commission to clarify
that only those entities that meet the
description of transmission owner
provided in NERC’s compliance registry
and the NERC Functional Model
descriptions are required to register as
responsible entities for the
Requirements applicable to
transmission owners.
34. TANC asks that the Commission
specify that, where an existing contract
between two parties provides that one is
the transmission owner, but the other
has agreed to perform the TOP
functions, the latter entity be listed in
the compliance registry as the
responsible entity for the TOP
Reliability Standards. Further, TANC
maintains that the transmission owner
should not be the default entity
ultimately responsible for compliance
with the TOP Reliability Standards.
According to TANC, only the entity
accepting responsibility to perform the
tasks delegated to it in the agreement
should be accountable for the
responsibilities assigned to it in the
agreement. TANC asserts that, where
entities have assigned responsibilities
by contract, there is no reason to register
those responsibilities to another entity.
35. California Cogeneration claims
that Order No. 693 failed to adequately
address the unique characteristics of
QFs. It states that reliance on the
registry process, which is based on the
14 functions identified in the NERC
functional model, does not adequately
distinguish among different types of
generators, including size and location,
and their impact on reliability.
California Cogeneration states that the
Commission, as a remedy to these
infirmities, should direct NERC to
immediately initiate a stakeholder
process to revise the Reliability
Standards to identify in greater detail
the entities that are responsible for
compliance and revise requirements to
recognize the operational constraints of
different generators. It states that this
process should be completed before
Reliability Standards become
enforceable. Further, California
Cogeneration states that the stakeholder
process should also develop criteria for
determining whether an entity has a
‘‘material impact’’ on reliability.
36. Finally, California Cogeneration
states that the Commission was not
responsive to issues raised by California
Cogeneration in its rulemaking
comments regarding individual
Reliability Standards that apply to
generator owners and operators and
needed revisions if they are to be
applied to cogenerators. It states that
some of these Reliability Standards
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seem to require information regarding
gross generation or load behind the
customer’s point of interconnection,
contrary to an earlier Commission
order.26 While the Commission directed
the ERO to consider these concerns
during its three-year Work Plan to
review each Reliability Standard,
California Cogeneration contends this
approach does not suffice because
cogenerators must comply with the
Reliability Standards in the interim.
d. Commission Determination
37. The Commission denies California
Cogeneration’s request for rehearing
concerning the definition of users of the
Bulk-Power System. The Commission
has not improperly delegated this
definition to the ERO and Regional
Entities. While NERC proposed the
registry criteria, the Commission
reviewed the criteria and approved
them as appropriate under section 215
of the FPA. Further, the Commission
has provided a method by which any
entity that disagrees with NERC’s
determination to place it in the
compliance registry may submit a
challenge in writing to NERC and, if still
not satisfied, may lodge an appeal with
the Commission.27 Therefore, the
Commission has the ultimate ability to
determine whether an entity should be
on the NERC registry.
38. With regard to the fact that certain
Regional Entities have created
supplemental criteria to determine
which entities should be on the registry,
we agree with California Cogeneration
that this is not appropriate.28 Order No.
693 accepted NERC’s compliance
26 California Cogeneration at 12, citing California
Independent System Operator, Corp., 96 FERC ¶
63,015 (2001) (Initial Decision); Opinion No. 464,
104 FERC ¶ 61,196 (2003) (affirming Initial
Decision).
27 See Order No. 693 at P 101; ERO Certification
Order at P 679.
28 We note that the example cited by California
Cogeneration appears to assert that the NERC
registry criteria incorporates a bright line test as to
which entities should be registered:
The application of the different sets of criteria to
a 30 MW generator interconnected at 69 kv
illustrates the inconsistency in treatment. Under
NERC’s criteria, the generator is interconnected at
less than 100 kv, and it is not therefore a user of
the bulk electric system. The generator would be
eliminated from registration by the first step of
NERC’s process. WECC’s Supplemental Criteria,
however, state that a generator greater than 20 MW
must be registered regardless of the voltage at which
it is interconnected.
California Cogeneration at 5. We disagree with
this interpretation. NERC’s compliance registry
would also allow the ERO and Regional Entities to
register ‘‘[a]ny generator, regardless of size, that is
a blackstart unit material to and designated as part
of a transmission operator entity’s restoration plan,
or; * * * [a]ny generator, regardless of size, that is
material to the reliability of the bulk power
system.’’ NERC Statement of Compliance Registry at
7.
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registration process ‘‘to provide as much
certainty as possible regarding the
applicability and responsibility of
specific entities under the approved
standards.’’ 29 NERC’s Statement of
Compliance Registry does not reference
supplemental compliance registries
created by Regional Entities. While both
the Commission and the ERO have
made it clear that an entity that falls
below the minimum registry criteria
may be included on the compliance
registry on a facility-by-facility basis,
nonetheless NERC’s compliance registry
places the burden on the Regional Entity
to reasonably demonstrate that the
organization is a user, owner or operator
of the Bulk-Power System.30 This
language contemplates a case-by-case
registration of entities outside the NERC
criteria, provided that a reasonable
demonstration of the need to register the
entity 31 is made by the Regional
Entity.32
39. In response to NRECA, in
directing the ERO to expand the
applicability of certain Reliability
Standards, the Commission did not
intend to expand the applicability
beyond those entities that are on the
compliance registry. Rather, we
indicated where the Commission
believed there was a reliability concern
in not applying certain Reliability
Standards to a category of registered
entities. For example, in COM–001–0,
where the Commission directed the ERO
to add distribution providers that are
essential to the implementation of a
black start plan to the Applicability
section, this would include only those
distribution providers that are on the
compliance registry.
40. The Commission agrees with
NRECA to the extent that we do not
wish that a direction for modification be
so overly prescriptive as to preclude the
consideration of viable alternatives in
the ERO’s Reliability Standards
development process. However, as
stated in Order No. 693, in identifying
a specific matter to be addressed in a
modification to a Reliability Standard, it
is important that the Commission
provide sufficient guidance so that the
29 Order No. 693 at P 33.
30 NERC Statement of Compliance Registry at 10,
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n.1.
31 The entity registered would also have to be a
user, owner or operator of NERC’s definition of bulk
electric system.
32 The Commission notes that no Regional Entity
has filed a supplemental registry with the
Commission. The Commission makes its
determination to reject regional registry criteria
without prejudice to a Regional Entity creating
supplemental registry criteria, provided that the
Regional Entity affords due process to those entities
that would be subject to them, and requests ERO
and Commission approval of such criteria.
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ERO has an understanding of the
Commission’s concerns and an
appropriate, but not necessarily
exclusive, outcome to address those
concerns. Without such direction and
guidance, the ERO might not know how
to respond adequately to a Commission
proposal to modify a Reliability
Standard.33 Thus, in some instances,
while we provided specific details
regarding the Commission’s
expectations, we intended by doing so
to provide useful guidance to assist in
the Reliability Standards development
process, not to impede it.
41. With respect to the specific
Reliability Standards cited by NRECA,
the Commission first notes that NRECA
does not appear to request rehearing on
the substance of the directed
modifications, but argues that the
Commission was too prescriptive
procedurally. In many instances, the
Commission provided guidance to the
ERO and stated that it could develop an
alternative to our direction, so long as
the alternative is as effective and
efficient as the Commission’s proposal.
However, with respect to the Reliability
Standards cited by NRECA, the
Commission has identified specific
concerns about the gap in applicability
in the Reliability Standard. For
example, as to COM–001–1 and COM–
002–2, the Commission was concerned
about having a reliability gap during
normal and emergency operations.
Section 215(d)(5) of the FPA states:
The Commission, upon its own motion or
upon complaint, may order the Electric
Reliability Organization to submit to the
Commission a proposed reliability standard
or a modification to a reliability standard that
addresses a specific matter if the
Commission considers such a new or
modified reliability standard appropriate to
carry out this section.
In the instances cited by NRECA, the
Commission has identified a deficiency
in the applicability of the Reliability
Standard. To correct this deficiency, the
ERO must add the specific entity to the
Applicability section of the Reliability
Standard.
42. TOP–003–0 contains
Requirements that can have a significant
impact on both the reliability of the
Bulk-Power System and on competition
with regard to available transfer
capability (ATC). The Commission’s
approval of TOP–003–0 does not
override either the compliance registry
or the ERO. The planning authority or
transmission planner should inform its
Regional Entity if it is not receiving
cooperation in getting the information it
requires. We note that section 39.2(d) of
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33 Order No. 693 at P 185.
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40723
our regulations requires each user,
owner or operator of the Bulk-Power
System to provide the Commission, the
ERO and the applicable Regional Entity
such information as is necessary to
implement section 215 of the FPA. If a
problem arises in obtaining information
necessary to calculate ATC, the
Commission may revisit this matter in
the future. For example, if entities are
unable to obtain the required
information under TOP–003–0, the
Commission might require the ERO,
through the Reliability Standards
development process, to develop a
provision to ensure that all
jurisdictional entities that must provide
information pursuant to TOP–003–0
because of a particular reliability need
are added to the registry, even if only to
meet the requirements of TOP–003–0.
43. The Commission denies Xcel’s
request for rehearing. As noted by Xcel,
NERC’s registry criteria state that the
ERO and Regional Entities will
‘‘generally’’ register generators greater
than 20 MVA and will ‘‘generally’’
exempt generators that are connected to
distribution facilities. The use of the
term ‘‘generally’’ allows the ERO and
Regional Entities flexibility to register a
generator meeting those descriptions if
the ERO or a Regional Entity determines
that the facility is needed for BulkPower System reliability. Further, Order
No. 693 specifically provided for such
an outcome.34 Therefore, those
generating facilities that Xcel is
concerned about, which are connected
at a distribution voltage but deliver
energy to the transmission system, may
be required to comply with Reliability
Standards depending on a possible caseby-case determination by the ERO or a
Regional Entity. Xcel does not provide
any support for its claim that this
general exclusion of facilities connected
at a distribution level creates
inappropriate incentives for entities to
interconnect generating facilities at the
distribution level rather than the
transmission level.
44. In response to TANC’s concern
that Order No. 693 appears to require all
entities subject to the Reliability
Standards to register for each
requirement applicable to transmission
owners, we disagree. This statement was
made only to ensure that there are no
gaps or unnecessary redundancies with
regard to the entity or entities
responsible for compliance. The
34 Id. at P 101. ‘‘Finally, the Commission agrees
that, despite the existence of a voltage or demand
threshold for a particular Reliability Standard, the
ERO or Regional Entity should be permitted to
include an otherwise exempt facility on a facilityby-facility basis if it determines that the facility is
needed for Bulk-Power System reliability.’’
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Commission did not intend to imply
that each user, owner and operator of
the Bulk-Power System must comply
with those Reliability Standards which
apply to transmission owners. Rather,
the Commission intended for the ERO to
ensure that there is clarity in the
registering of entities and that the
registration process results in no gaps or
unnecessary redundancies.
45. Further, the Commission clarifies
that it did not intend to change existing
contracts, agreements or other
understandings as to who is responsible
for a particular function under a
Reliability Standard.35 The Commission
believes that allowing an organization to
accept compliance responsibility on
behalf of its members should cover
TAPS’ concerns regarding a situation in
which two entities have a contract
regarding which will perform functions
under the Reliability Standards.36 NERC
has filed procedures for allowing such
agreements in Docket No. RM06–16–
003. The Commission will rule on the
particulars of those procedures in that
proceeding.
46. The Commission denies California
Cogeneration’s request for rehearing
with respect to exemption of QFs from
compliance with mandatory Reliability
Standards. As stated in Order No. 696,
for reliability purposes, there is no
meaningful distinction between QF and
non-QF generators that would warrant
generic exemption of QFs from
mandatory Reliability Standards.37
Therefore, we disagree with California
Cogeneration that Order No. 693 failed
to adequately address the unique
characteristics of QFs.
47. Whether a generation facility
should be subject to Reliability
Standards should depend on whether
electric energy from the generation
facility is needed to maintain the
reliability of the Bulk-Power System.
The registration criteria adopted by
NERC and approved by the
Commission, as well as the compliance
registry process adopted by NERC and
approved by the Commission, are
designed to ensure that only those
facilities needed to maintain the
reliability of the Bulk-Power System are
subject to the Reliability Standards. The
ultimate decision with respect to
individual generation units or plants is,
and must be, made on a case-by-case
basis. Thus, whether a particular QF or
type of QF should be exempt from
Reliability Standards is an issue that is
more appropriately raised in the context
of NERC’s establishment of registry
35 See id. at P 107.
criteria for owners and operators of
generators, and in the context of NERC’s
compliance registry process. The
reliability of the Bulk-Power System
will be better protected by addressing
this issue in the NERC compliance
registry process, which will ensure that
no generator that is needed to maintain
the reliability of the Bulk-Power System
will be exempt from Reliability
Standards, while excusing those
generators that are not needed to
maintain reliability. Therefore, the
Commission rejects California
Cogeneration’s request that it direct
NERC to immediately initiate a
stakeholder process to revise the
Reliability Standards to identify in
greater detail the entities that are
responsible for compliance and revise
requirements to recognize the
operational constraints of QF generators.
3. Use of the NERC Functional Model
48. Order No. 693 explained that
NERC has developed a ‘‘Functional
Model’’ that defines the set of functions
that must be performed to ensure the
reliability of the Bulk-Power System.
The Functional Model identifies 14
functions and the name of a
corresponding entity responsible for
fulfilling each function. While the
Commission had proposed to require
that NERC file future revisions to the
Functional Model, Order No. 693
determined that such filing was not
necessary.38 The Commission made this
determination based on the
characterization offered by numerous
commenters that the Functional Model
is an evolving guidance document that
is not intended to convey firm rights
and responsibilities. Further, the
Commission agreed with commenters
that the applicability section of a
particular Reliability Standard should
be the ultimate determinant of
applicability of each Reliability
Standard. While some commenters
asked that all revisions to the
Functional Model be developed through
NERC’s ANSI-accredited process, the
Commission left to the discretion of the
ERO the appropriate means of allowing
stakeholder input when revising the
Functional Model.
e. Requests for Rehearing
49. TANC requests rehearing of the
Commission’s determination that future
modifications of the Functional Model
do not need to be submitted to the
Commission for approval. TANC
contends that the Functional Model is
more than just a guidance document
and, rather, is fundamental to
determining the applicability of each
Reliability Standard. It asserts that the
ERO’s compliance registry process that
is used to identify users, owners and
operators of the Bulk-Power System that
must comply with Reliability Standards
relies on the Functional Model. Thus,
according to TANC, a change in the
Functional Model affects the
applicability and enforcement of each
Reliability Standard.
50. Further, TANC contends that the
Reliability Standards are not
‘‘complete,’’ a quality objective
identified by NERC in the development
of Reliability Standards, because the
Reliability Standards are dependent on
an external document. TANC is
concerned that revising the Functional
Model could result in additional entities
having to comply with Reliability
Standards without affording these
entities adequate notice of what is
expected of them. It notes that terms
used in the Functional Model are also
defined in the NERC glossary, which
was approved by the Commission. Thus,
TANC requests that the Commission
require the ERO to submit revisions to
the Functional Model for Commission
approval, either as revisions to the
Functional Model or revised terms in
the NERC glossary, after development
through the ERO’s full Reliability
Standards development process.
51. Midwest ISO contends that the
Commission erred in failing to require
NERC to define the distinct roles of the
‘‘planning coordinator’’ and ‘‘planning
authority.’’ According to Midwest ISO,
while NERC used the term planning
authority when it developed the
‘‘Version 0’’ Reliability Standards, it
was recognized that there was ‘‘[no]
common understanding of who or what
the Planning Authority was.’’ 39 Further,
Midwest ISO explains that many
Reliability Standards describe roles for
both the planning authority and
transmission planner. Midwest ISO
states that, while the latest revision to
the Functional Model substitutes the
term ‘‘planning coordinator’’ for
‘‘planning authority,’’ this has not
resolved the problem because the
responsibilities of the planning
coordinator ‘‘are both more limited and
wide-area in nature’’ and may not be
simply substituted for those of planning
authority. Midwest ISO notes that
certain Regional Entities are registering
entities based on the planning authority
function as previously defined, and
Midwest ISO asks rhetorically whether
the ERO can hold a company
accountable to a set of Reliability
36 See id. at P 107–09.
37 Order No. 696 at P 28.
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38 Order No. 693 at P 127–29.
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39 Midwest ISO at 4.
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Standards applicable to an entity that it
no longer recognizes as valid.
52. Midwest ISO maintains that the
Commission did not adequately address
Midwest ISO’s concerns when it stated
in Order No. 693 that the ERO can
address such concerns as it updates and
revises the Functional Model.
According to Midwest ISO, the
Reliability Standards state that regions
should work closely with the planning
coordinators on a common
understanding of roles and
responsibilities, but such a process will
be lengthy and perhaps futile without
Commission guidance. Further,
Midwest ISO states that, while NERC
will address this issue in the long term,
the Commission’s failure to provide
interim clarification or direct NERC to
specify the role of the planning
coordinator is an error.
f. Commission Determination
53. The Commission denies TANC’s
request for rehearing. The Commission
disagrees with TANC that the
Commission-approved Reliability
Standards are incomplete. As stated in
Order No. 693, the applicability section
of a particular Reliability Standard
should be the ultimate determinant of
applicability of each Reliability
Standard.40 Further, the Commission
notes that we required the ERO to
update the Glossary of Terms Used in
Reliability Standards through the
Reliability Standards development
process whenever a new or revised
Reliability Standard includes a new
defined term.41
54. The Commission disagrees with
TANC that the Functional Model is used
to identify users, owners and operators
of the Bulk-Power System that must
comply with Reliability Standards. The
compliance registry criteria are used to
determine which entities must be listed
on the compliance registry, and
therefore must comply with Reliability
Standards. Changes in the Functional
Model cannot require additional entities
to comply with Reliability Standards.
Consistent with our explanation in
Order No. 693, if an entity is registered
as a result of a change that emanated
from a revision of the Functional Model,
the entity would have an opportunity to
seek review by the ERO and the
Commission. Accordingly, we deny the
request for rehearing and will not
require NERC to file revisions to the
Functional Model.
55. Further, we reject Midwest ISO’s
contention that the Commission erred in
failing to provide guidance in directing
NERC to define the distinct roles of the
planning authority and planning
coordinator. First, as recognized by
Midwest ISO, NERC will address this
issue as part of its long range plan. This
is consistent with the Commission’s
statement in Order No. 693 that ‘‘given
that the Functional Model is an evolving
guidance document, the ERO can
address such concerns as it updates and
revises the Functional Model.’’ 42
Midwest ISO has provided insufficient
support for its contention that
addressing this matter may be lengthy
and futile without Commission
intervention. Moreover, consistent with
Order No. 693, any ambiguity regarding
roles and the responsibility of a
particular entity for compliance with a
particular Reliability Standard is a
matter that should be addressed in the
registration of a particular entity.
56. Finally, we disagree with Midwest
ISO’s suggestion that it is inappropriate
to register entities as planning
authorities given that the applicability
provisions of the Commission-approved
Reliability Standards refer to the
planning authority and not the planning
coordinator. Consistent with our
discussion above, revisions to the
Functional Model do not convey rights
and responsibilities but, rather, the
modification to the applicability
provision of a Reliability Standard or
NERC glossary ultimately determines an
entity’s obligations.
B. Mandatory Reliability Standards
1. Prioritizing Modifications to
Reliability Standards
57. In Order No. 693, the Commission
directed the ERO to submit a revised
Work Plan to: (1) Reflect modification
directives contained in Order No. 693;
(2) include the timeline for completion
of ATC-related Reliability Standards as
ordered in Order No. 890; and (3)
account for the views of its
stakeholders, including those raised in
this proceeding. The Commission
required that the ERO set specific
delivery dates, explaining that ‘‘[a]
Work Plan with specific target dates will
provide a valuable tool and incentive to
timely address the modifications
directed in this Final Rule.’’ 43 Further,
Order No. 693 stated that:
the ERO should make every effort to meet
such delivery dates. However, we understand
that there may be certain cases in which the
ERO is not able to meet [the] Commission’s
deadline. In those instances, the ERO must
inform the Commission of its inability to
meet the specified delivery date and explain
40 Order No. 693 at P 127.
42 Id. at P 129.
41 Id. at P 1893.
43 Id. at P 207.
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why it will not meet the deadline and when
it expects to complete its work.[44]
g. Requests for Rehearing
58. NRECA asks for clarification, or
alternatively rehearing, that Order No.
693 does not allow the imposition and
enforcement of deadlines that preclude
the ERO from satisfying the due process
requirements set forth in section 215 of
the FPA or applying its own expertise.
NRECA states that a deadline ‘‘may be
reasonable or unreasonable, and its
reasonableness needs to be determined
within context’’ taking into account the
complexity of the matter and other
considerations.45 NRECA contends that
the imposition and enforcement of an
unreasonable deadline conflicts with
section 215 as well as Order No. 672.
Thus, NRECA seeks clarification that
the Commission’s assertion of authority
to establish deadlines for ERO action
represents no more than the authority to
‘‘exhort’’ the ERO to move
expeditiously, consistent with its
statutory due process obligations.
‘‘However, if the Commission is
purporting in the Final Rule to reserve
the power to specify an unreasonable
deadline, that undermines due process
and ignores the ERO’s technical
expertise in contravention of the
requirements of section 215, then
NRECA seeks rehearing of the
Commission’s determination.’’ 46
h. Commission Determination
59. The Commission agrees that it
should not impose deadlines that
preclude the ERO from satisfying the
due process requirements set forth in
section 215 of the FPA, and has
provided in several previous orders that,
in complying with a deadline, NERC
must also meet the requirements of the
FPA and the Commission’s regulations.
In our January 2007 Compliance Order,
we made it clear that a revision to
NERC’s expedited Reliability Standards
development process must ‘‘make it
clear that the Commission can order
expedited standard development in a
specific time frame and that NERC must
adhere to that time frame and still allow
for due process.’’ 47 On rehearing, we
further clarified that ‘‘any ERO process
that provides ‘reasonable notice and
opportunity for comment, due process,
openness, and balance of interests’ as
required by section 215(c)(2)(D) of the
FPA, and that also can meet a
Commission-imposed deadline pursuant
44 Id.
45 NRECA at 17.
46 Id. at 18.
47 North American Electric Reliability Corp., 118
FERC ¶ 61,030 at P 27 (2007) (January 2007
Compliance Order) (emphasis added).
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to section 39.5(g) of the Commission’s
regulations, will comply with this
directive.’’ 48
60. Finally, in Order No. 693, the
Commission stated that the ERO should
make every effort to meet Commissionordered delivery dates. However, we
acknowledged that ‘‘there may be
certain cases in which the ERO is not
able to meet [the] Commission’s
deadline. In those instances, the ERO
must inform the Commission of its
inability to meet the specified delivery
date and explain why it will not meet
the deadline and when it expects to
complete its work.’’ 49
2. Trial Period
61. In Order No. 693, while the
Commission did not institute a formal
‘‘trial period,’’ it directed the ERO and
Regional Entities to ‘‘focus their
resources’’ on the ‘‘most serious
violations’’ during an initial period
through December 31, 2007.50 Order No.
693 stated that this use of enforcement
discretion should apply to all users,
owners and operators of the Bulk-Power
System. The Commission explained that
the goal should be to ensure that, at the
outset, the ERO and Regional Entities
can assess a monetary penalty in a
situation where, for example, an entity’s
non-compliance places Bulk-Power
System reliability at risk. This approach
would allow the ERO, Regional Entities
and other entities time to ensure that the
compliance monitoring and
enforcement processes work as intended
and that all entities have time to
implement new processes.
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i. Requests for Rehearing
62. Xcel states that, while it supports
the Commission’s decision that the ERO
and Regional Entities should have the
enforcement discretion to calculate but
not collect penalties during an initial
period, it asks that the Commission
provide greater clarity and guidance
regarding the circumstances when
penalties should be collected and when
they should not. It asks that the
Commission be as specific as possible in
defining the circumstances under which
the ERO and Regional Entities should
exercise their enforcement discretion. It
suggests that the Commission clarify
that to assess a penalty a violation must
be, at a minimum, (i) an intentional
violation of a well-understood
Reliability Standard and (ii) a violation
that causes substantial harm.
48 North American Electric Reliability Corp., 119
FERC ¶ 61,046 at P 13 (2007).
49 Order No. 693 at P 207.
50 Id. at P 221–22.
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j. Commission Determination
63. The Commission denies Xcel’s
request for clarification. First, the
Commission believes that Xcel’s
requested clarification would not
always capture the most serious
violations. Moreover, the Commission
in Order No. 693 intentionally declined
to develop a threshold that would place
limits on the ERO’s and Regional
Entities’ exercise of enforcement
discretion; and we decline to do so here
as well. Although we clearly allowed for
‘‘the ERO or a Regional Entity to take an
enforcement action against an entity
whose violation causes a significant
disturbance,’’ we also provided that the
ERO and Regional Entities can assess a
monetary penalty in a situation where,
for example, an entity’s non-compliance
places Bulk-Power System reliability at
risk.51 We did not require that there be
actual harm to the Bulk-Power System
for the ERO to assess a penalty during
the transition period.
64. The Commission believes that it is
better to allow the ERO and Regional
Entities to use their expertise in
determining which violations constitute
the most serious. Likewise, the ERO and
Regional Entities are in the best position
to know how to best use their finite
enforcement resources. This will require
case-by-case analysis of the
circumstances surrounding a situation.
Therefore, we will not stipulate a single
set of circumstances under which the
ERO and Regional Entities should use
their enforcement discretion for the
initial transition period.
C. Common Issues Pertaining to
Reliability Standards
1. Blackout Report Recommendation on
Liability Limitations
65. In Order No. 693, consistent with
Order No. 890, the Commission did not
adopt new liability protections.52 The
Commission stated that it did not
believe any further action is needed to
implement Blackout Report
Recommendation No. 8 because the
Task Force found that no further action
is needed.53 Further, the Blackout
Report indicated that some states
already have appropriate protection
51 Id.
52 Id. at P 237; Preventing Undue Discrimination
and Preference in Transmission Service, Order No.
890, 72 FR 12,266 (March 15, 2007), FERC Stats. &
Regs. ¶ 31,241 (2007) at P 1671–77.
53 U.S.-Canada Power System Outage Task Force,
Final Report on Implementation of Task Force
Recommendations at 22 (Oct. 3, 2006), available at
http://www.oe.energy.gov/news/blackout.htm
(‘‘Action Required to Fully Implement
Recommendation 8: No further action under this
recommendation is needed.’’).
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against liability suits.54 Finally, the
Commission stated that, in Order No.
888, as affirmed by Order No. 890, the
Commission declined to adopt a
uniform federal liability standard and
decided that, while it was appropriate to
protect the transmission provider
through force majeure and
indemnification provisions from
damages or liability when service is
provided by the transmission provider
without negligence, it would leave the
determination of liability in other
instances to other proceedings.55
k. Requests for Rehearing
66. Avista seeks rehearing on the
Commission’s determination not to
provide further liability limitations and
questions whether it is fair, just and
reasonable to deny transmission
operators that are not regional
transmission organizations (RTOs) or
independent system operators (ISOs) the
protections afforded to RTOs and ISOs
and at the same time impose mandatory
Reliability Standards with significant
fines and penalties as an enforcement
mechanism.56 Avista argues that the
Commission has limited the scope of
liability in the pro forma open access
transmission tariff (OATT) to instances
of gross negligence or intentional
misconduct and also limited damages
by excluding consequential, indirect or
punitive damages for RTOs and ISOs.
According to Avista, not providing these
same limitations to other transmission
operators is, on its face, arbitrary, and
may have unintended adverse
consequences to the ratepayers of any
transmission operator whose operating
employee’s decisions initiate a large
cascading outage, if available insurance
is not adequate to cover the risk. Avista
argues that enforcement of mandatory
Reliability Standards should not depend
both on risk of massive liability
exposure and upon multi-million dollar
civil fines and penalties.
l. Commission Determination
67. The Commission denies rehearing.
The Commission has already ruled that
the liability standard the Commission
has approved for RTOs and ISOs is not
54 Id. (‘‘In the United States, some state regulators
have informally expressed the view that there is
appropriate protection against liability suits for
parties who shed load according to approved
guidelines’’).
55 Order No. 888–B, 81 FERC ¶ 61,248 at 62,081
(1997), order on reh’g, Order No. 888–C, 82 FERC
¶ 61,046 (1998), aff’d in relevant part sub nom.
Transmission Access Policy Study Group v. FERC,
225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New
York v. FERC, 535 U.S. 1 (2002).
56 Avista and PSE also requested rehearing of this
issue in Docket Nos. RM05–25–001 and RM05–17–
001.
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appropriate for other transmission
providers.57 Further, we also found
without merit assertions that increased
liability protections in the pro forma
OATT should be viewed as a necessary
element of the implementation of the
Commission’s reliability authority.58 In
the Reliability Policy Statement,59 the
Commission stated that it would
consider, on a case-by-case basis,
proposals by public utilities to amend
their OATTs to include limitations on
liability. The Commission further noted
that, while this issue has not been
resolved on a standardized basis, the
Commission has entertained RTO
transmission providers’ specific
proposals to amend their OATTs to
include provisions addressing
limitations on liability.60
68. In subsequent orders, the
Commission found that the gross
negligence and intentional wrongdoing
indemnification and liability standard is
appropriate for RTOs and ISOs.
However, the Commission has declined
to extend this protection to all
transmission providers. In Southwest
Power Pool, Inc., the Commission
explicitly stated ‘‘that our acceptance
here of the gross negligence and
intentional wrongdoing indemnity
standard is limited to SPP, in its role as
an RTO, and its TOs; we do not intend
to extend such protection to all
transmission providers.’’ 61 In Southern
Company Services, Inc., the
Commission stated that:
Having considered Southern Companies’
proposed limitation on liability and
indemnification provisions pursuant to our
Reliability Policy Statement cited above, we
find that Southern Companies have not
shown that they are similarly situated to the
RTOs/ISOs they cite in support. While
Southern Companies claim that they ‘may
not be protected by any State-regulated
limitations on liability,’ Southern Companies
offer no evidence to support this concern.
The Commission has provided such liability
protection to RTOs/ISOs because they were
created by and solely regulated by the
Commission, and otherwise would be
without limitations on liability. Southern
Companies have proffered no evidence of any
change in circumstances vis-à-vis their
liability exposure post-Order No. 888.62
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69. Further, we disagree with Avista
that there is a risk of massive liability
57 Order No. 890 at P 1675. We note that this
discussion concerns civil liability only, not liability
for penalties imposed by the ERO, Regional Entities
or the Commission.
58 Id. at P 1677.
59 Policy Statement on Matters Related to Bulk
Power System Reliability, 107 FERC ¶ 61,052 (2004)
(Reliability Policy Statement).
60 Reliability Policy Statement at P 40 (citations
omitted).
61 112 FERC ¶ 61,100 at P 39 (2005).
62 113 FERC ¶ 61,239 at P 7 (2005).
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exposure. It offers no new arguments
that demonstrate that non-RTO and nonISO transmission providers are unable
to rely on state laws, i.e., the state laws
provide inadequate protection. Avista
has not persuaded us to change our
policy regarding liability protections
applicable to non-RTO and non-ISO
transmission providers. Therefore, we
deny rehearing.
2. Fill-in-the-Blank Standards
70. In Order No. 693, the Commission
required supplemental information for
any Reliability Standard that currently
requires a regional reliability
organization to fill in missing criteria or
procedures.63 The Commission
explained that, where important
information has not yet been provided,
it would not approve or remand such
Reliability Standards until the ERO
submits further information. Until such
information is provided, compliance
with the so-called fill-in-the-blank
standards should continue on a
voluntary basis, and the Commission
considers compliance with such
Reliability Standards to be a matter of
good utility practice. Further, the
Commission stated:
In our Reliability Policy Statement, we
explained that compliance with NERC
Reliability Standards (or more stringent
regional standards) is expected as a matter of
good utility practice as that term is used in
the pro forma OATT. The Commission
continues to expect compliance with such
Reliability Standards as a matter of good
utility practice. That being said, the
Commission agrees that retaining a dual
mechanism to enforce Reliability Standards
both as good utility practice and under
section 215 of the FPA is inappropriate; the
OATT only applies to entities subject to our
jurisdiction as public utilities under the FPA,
while section 215 defines more broadly our
jurisdiction with respect to mandatory
Reliability Standards. We therefore do not
intend to enforce, as an OATT violation,
compliance with any Reliability Standard
that has not been approved by the
Commission under section 215.64
m. Requests for Rehearing
71. While APPA believes that Order
No. 693 correctly deferred consideration
of the ‘‘fill-in-the-blank’’ standards, it
requests rehearing of the Commission’s
approval of other Reliability Standards
that incorporate the ‘‘fill-in-the-blank’’
standards. APPA argues that the
Commission cannot, lawfully, approve
Reliability Standards for immediate
enforcement that incorporate those same
unreviewed and unapproved regional
Reliability Standards.
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63 Order No. 693 at P 297–302.
64 Id. at P 302 (footnote omitted).
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40727
72. According to APPA, approving a
Reliability Standard that references an
unapproved fill-in-the-blank standard
requires compliance with regional
Reliability Standards that the
Commission has not reviewed or
approved. APPA asserts that the
Commission cannot determine if a
Reliability Standard that references a
pending Reliability Standard is ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest’’ for the same reasons that the
Commission articulated in determining
that it lacked important information
needed to evaluate ‘‘fill-in-the-blank’’
standards.
73. APPA also argues that the
approved Reliability Standards that
reference a fill-in-the-blank standard do
not promote uniformity and consistency
as required by Order No. 672. APPA
asserts that the Commission cannot
determine if such Reliability Standards
are justified, because the regional
standard is more stringent than
continent-wide Reliability Standards or
is necessitated by a physical difference
in the Bulk-Power System, without
reviewing the regional standard in
question to determine whether one of
those two findings is appropriate. APPA
also maintains that the Commission
cannot conclude that the processes by
which the regional practices involved in
the referenced fill-in-the-blank
standards were developed meet
statutory requirements. APPA raises
concerns about due process and
fundamental fairness, asserting that
small entities have often not been
included in past regional processes, and
may not have received prior notice of
the standards with which they must
now comply.
74. APPA also argues the Commission
is incorrect that ‘‘many of these
Reliability Standards either refer to the
process of collecting data or reference
Requirements that entities are generally
aware of because they have already been
following these Reliability Standards on
a voluntary basis.’’ According to APPA,
Reliability Standards may sweep in
many small entities that have not been
members of regional reliability
organizations and have not necessarily
complied with standards on a voluntary
basis.
75. APPA argues that the
Commission’s approval of Reliability
Standards that make enforceable
unreviewed ‘‘fill-in-the-blank’’
standards could trigger registration of a
large number of small entities.
According to APPA, unless it can be
assumed that no change in the scope or
content of the fill-in-the-blank standards
will result from the ongoing process
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NERC and the Regional Entities are
undertaking to fill in the blanks,
mandatory enforcement of the ‘‘before’’
version is likely to sweep in different
entities and subject them to different
standards than will the ‘‘after’’ version.
Further, APPA asserts that, by posing
the potential to sweep a large number of
small entities onto the compliance
registry before the applicable regional
standard is approved, the Commission’s
decision calls into question its
adherence in Order No. 693 to the
Regulatory Flexibility Act requirements
because, absent review of the
undisclosed incorporated ‘‘fill-in-theblank’’ standards, the Commission
cannot estimate the number of small
systems these Reliability Standards will
affect. Further, APPA maintains that the
Commission cannot make the requisite
determination that a small entity’s
compliance with an unapproved ‘‘fillin-the-blank’’ standard has a material
impact on reliability, and the
Commission cannot find such
compliance necessary for Bulk-Power
System reliability.
76. Finally, APPA maintains that,
even though the Commission stated that
the fact that a Reliability Standard
references a fill-in-the-blank standard
‘‘may be considered in an enforcement
action,’’ 65 the Commission should not
have approved such Reliability
Standards. According to APPA, the
ability of an entity to raise this issue in
an enforcement action occurs too late to
avoid the harm to many small entities
in being required to register and comply
with what it calls unapproved regional
underfrequency load shedding (UFLS)
programs that have not been developed
through Commission-approved
processes meeting the statutory
standard, and which may well differ
from the final standard that the
Commission approves to fill in the
blanks. Nor, according to APPA, does
the ability to raise issues relating to fillin-the-blank standards in an
enforcement action avoid the potential
for significant distraction of NERC and
Regional Entities from more crucial
reliability-related duties to instead deal
with compliance by numerous small
entities that have no material impact on
the grid with regional standards that are
in a state of flux. APPA also asserts that
this statement cannot overcome the
fundamental legal deficiency with
approving a Reliability Standard that
references a fill-in-the-blank standard—
that the Commission lacks authority to
approve regional reliability standards
that require compliance with regional
n. Commission Determination
78. The Commission denies APPA’s
request for rehearing and provides
further clarification. The Commission
continues to believe that the fact that a
Reliability Standard simply references a
Reliability Standard that was not
approved or remanded in Order No. 693
does not alone justify not approving the
former Reliability Standard. Rather,
such a reference may be considered in
an enforcement action, if relevant, but is
not a reason to delay approval of the
Reliability Standard. Further, we clarify
that, in an enforcement proceeding,
such a reference can be considered
regarding whether a particular
Requirement or part of a Requirement in
an otherwise approved Reliability
Standard is enforceable.66 The
Commission did not err in approving
Reliability Standards that reference a
pending Reliability Standard because
they contain the appropriate level of
specificity necessary to provide notice
to users, owners and operators of the
Bulk-Power System as to what is
required. We will discuss the issue
raised by APPA in regard to the
Protection and Control Systems (PRC)
group of Reliability Standards in our
discussion of individual Reliability
Standards below.
79. In approving a Reliability
Standard that references a fill-in-theblank standard, the Commission is not
requiring compliance with the
unapproved Reliability Standard.
Therefore, it is immaterial how the
regional differences discussed in the
unapproved Reliability Standard were
created. Rather, as addressed more fully
in our discussion on the PRC group of
Reliability Standards below, the
Commission, ERO and Regional Entities
66 See discussion of PRC–007, PRC–008, and
PRC–009, infra.
65 Id. at P 300.
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UFLS standards it has neither reviewed
nor approved.
77. Xcel contends that the statement
that the Commission does not intend to
enforce, as an OATT violation,
compliance with any Reliability
Standard that has not been approved by
the Commission under section 215 is
confusing. By stating that the
Commission does not intend to enforce
as an OATT violation compliance with
a Reliability Standard that has not been
approved by the Commission under
section 215, Xcel is concerned that the
Commission may intend to enforce as an
OATT violation non-compliance with a
Reliability Standard that has been
approved by the Commission under
section 215. Xcel seeks clarification or
rehearing on this issue.
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will only enforce the data requirements
and any requirement that can be
independently enforced in those
Reliability Standards, and will not
enforce compliance with regional
criteria created by a regional reliability
organization pursuant to an unapproved
fill-in-the-blank standard.67
80. APPA’s contention that approving
a Reliability Standard that references a
fill-in-the-blank standard could trigger
additional small entity registration is
speculative. At this time, registration is
governed by NERC’s definition of bulk
electric system and its compliance
registry criteria. Nothing in a Reliability
Standard can cause an entity to be
registered if it would otherwise not be
required to do so.
81. In response to Xcel, the
Commission clarifies that it does not
intend to enforce as a violation of good
utility practice non-compliance with a
Reliability Standard that has been
approved by the Commission under
section 215. However, where the OATT
contains a specific requirement that may
be related to a Reliability Standard, for
example, an independent obligation
under the OATT to calculate
transmission capacity, the Commission
does not limit its ability to take
enforcement action separately against a
violation of a Reliability Standard and a
violation of a specific OATT provision.
Such determinations will be based on
the facts of a specific circumstance.
D. Discussion of Individual Reliability
Standards
1. EOP–001–0
82. Reliability Standard EOP–001–0
requires each transmission operator and
balancing authority to develop,
maintain and implement a set of plans
to mitigate operating emergencies.
These plans must be coordinated with
other transmission operators and
balancing authorities and the reliability
coordinator.
83. Order No. 693 approved
Reliability Standard EOP–001–0. In
addition, the Commission directed the
ERO to develop a modification to EOP–
001–0 that, among other things,
includes the reliability coordinator as an
applicable entity. In pertinent part, the
Commission found the reliability
coordinator to be a necessary entity
under EOP–001–0 and directed the ERO
to modify the Reliability Standard to
include the reliability coordinator as an
67 This is similar to our action in Order No. 693,
where we approved certain Reliability Standards,
but acknowledged that a particular requirement
may be unenforceable. See Order No. 693 at P 147,
157–58.
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applicable entity.68 Recognizing the
importance NERC attributes to the
reliability coordinator in connection
with matters covered by EOP–001–0, the
Commission was persuaded that
specific responsibilities for the
reliability coordinator in the
development and coordination of
emergency plans must be included as
part of this Reliability Standard. The
Commission reasoned that, while
balancing authorities and transmission
operators are capable of developing,
maintaining and implementing plans to
mitigate operating emergencies for their
specific areas of responsibility, unlike
reliability coordinators, they do not
have a wide-area view.
o. Requests for Rehearing
84. Midwest ISO disagrees with the
Commission’s mandate to the ERO to
make EOP–001–0 applicable to the
reliability coordinator. It notes that the
Commission correctly did not provide
guidance on the reliability coordinators’
role in the emergency planning process
and appears to have left this issue up to
the industry experts. Midwest ISO
argues that the industry had already
addressed any potential role of the
reliability coordinator in emergency
planning by declining to make the
reliability coordinator an applicable
entity in EOP–001–0.
jlentini on PROD1PC65 with RULES
p. Commission Determination
85. The Commission affirms its
determination to mandate that the ERO
make EOP–001–0 applicable to the
reliability coordinator function because
it is the highest level of authority
responsible for reliable operation of the
Bulk-Power System and has a wide-area
view. Midwest ISO has not
substantively disputed that
Requirements for mitigation of
emergencies will benefit from including
a role for the entity with a wide-area
view. The ERO may consider other
equivalent alternatives and consider
industry concerns in its modification of
EOP–001–0.
2. EOP–002–2
86. EOP–002–2 applies to balancing
authorities and reliability coordinators
and is intended to ensure that they are
prepared for capacity and energy
emergencies. This Reliability Standard
requires that balancing authorities have
the authority to bring all necessary
generation on line, communicate about
energy and capacity emergencies with
the reliability coordinator and
coordinate with other balancing
authorities. EOP–002–2 includes an
attachment that describes an emergency
procedure to be initiated by a reliability
coordinator that declares one of four
energy emergency alert levels to provide
assistance to the load-serving entity.
87. Order No. 693 approved
Reliability Standard EOP–002–2. In
addition, the Commission directed the
ERO to develop a modification to EOP–
002–2 that, among other things, would
modify the Reliability Standard to
ensure that the Transmission Loading
Relief (TLR) procedure is not used to
mitigate actual Interconnection
Reliability Operating Limit (IROL)
violations. The Commission found that
the TLR procedure may be appropriate
and effective for use in managing
potential IROL violations, but that the
TLR procedure is an inappropriate and
ineffective tool for mitigating actual
IROL violations or for use in emergency
situations as called for in EOP–002–2.
Accordingly, the Commission directed
the ERO to modify the Reliability
Standard to ensure that the TLR
procedure is not used to mitigate actual
IROL violations.69
q. Requests for Rehearing
88. Midwest ISO requests that the
Commission clarify which of the
following conditions constitutes a
‘‘potential IROL’’ violation for purposes
of EOP–002–2: (1) The operating limit
has been exceeded, but 30 minutes has
not elapsed and the operator may yet
return the system to normal; or (2) the
operating limit has not been exceeded,
but appears that it may be if action is
not taken quickly. Midwest ISO believes
that the second circumstance is the one
the Commission identified as being
appropriate for TLR mitigation, but
reasons that the terminology can be
interpreted differently by different
operators applying historically different
operating practices.
r. Commission Determination
89. The Commission clarifies that a
potential IROL violation refers to the
second circumstance provided by
Midwest ISO, in which ‘‘the operating
limit has not been exceeded, but
appears that it may be if action is not
taken quickly.’’ In such a situation, use
of TLR procedures may be appropriate
depending on the circumstances.
Moreover, actions undertaken under the
TLR procedure are not fast and
predictable enough for use in situations
in which an operating security limit is
being violated.
3. EOP–008–0
90. EOP–008–0 addresses plans for
loss of control center functionality. It
requires each reliability coordinator,
transmission operator and balancing
authority to have a plan to continue
reliable operations and to maintain
situational awareness in the event its
control center is no longer operable.
91. Order No. 693 approved
Reliability Standard EOP–008–0. In
addition, the Commission directed the
ERO to develop a modification to EOP–
008–0 that, among other things,
includes a Requirement that provides
for backup capabilities that, at a
minimum, requires transmission
operators and balancing authorities that
have operational control over significant
portions of generation and load to have
minimum backup capabilities, but may
do so through contracting for these
services instead of through dedicated
backup control centers.70
s. Requests for Rehearing
92. Midwest ISO supports the
outcome of Order No. 693 with regard
to Commission mandates in EOP–008–
0. However, it notes that ambiguities
and potential misunderstandings could
result from imprecise adjectives in the
Reliability Standards. Specifically, for
purposes of EOP–008–0, Midwest ISO
advocates that the Commission should
define an amount of load or generation
that constitutes a ‘‘significant’’ portion
of generation and load that would
require entities to have minimum
backup capabilities through backup
control centers. Alternatively, Midwest
ISO proposes that NERC could be
directed to create a ‘‘safe-harbor’’ limit
below which a system would not be
considered significant unless found to
be so by the Regional Entity or the ERO.
t. Commission Determination
93. The Commission reiterates its
direction in Order No. 693 that the goal
of this Reliability Standard is to provide
the continuation of Reliable Operation
and the maintenance of situational
awareness in the event that the primary
control center is no longer
operational.71 To that end, every
registered reliability coordinator,
balancing authority, transmission
operator, and centrally dispatched
generator operator should have a plan
and means of achieving the outcome of
the plan upon the loss of their
respective control centers. The
Commission has identified three
requirements as a minimum for the
plans—independence from the primary
70 Id. at P 672.
68 Id. at P 566.
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71 See Order No. 693 at P 659.
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control center, capability to operate for
a prolonged period corresponding to the
time it would take to replace the
primary control center, and the
provision of a minimum set of tools and
facilities to replicate the critical
reliability functions of the primary
control center. The Reliability Standard
should provide specific Requirements,
based on the size or impact to Reliable
Operation, to achieve the Commission’s
requirements.
94. The Commission declines to
define a ‘‘safe harbor’’ limit requested
by Midwest ISO. We directed the ERO,
through the Reliability Standards
development process, to identify what
Requirements are necessary on which
size entities to achieve the
Commission’s directives and the goal of
this Reliability Standard. Since there are
many equally efficient ways of
achieving the Commission’s direction,
we will not identify any specific method
or safe harbor.
4. FAC–003–1
95. FAC–003–1 addresses vegetation
management on transmission rights-ofway. As proposed, FAC–003–1 would
apply to transmission lines operated at
200 kV or higher voltage (and lowervoltage transmission lines which have
been deemed critical to reliability by a
regional reliability organization). It
would require each transmission owner
to have a documented vegetation
management program in place,
including records of its implementation.
Each program must be developed for the
geographical area and specific design
configurations of the transmission
owner’s system.
96. Order No. 693 approved
Reliability Standard FAC–003–1. In
addition, while we did not direct the
ERO to submit a modification to the
general limitation on applicability to
facilities above 200 kV, we required the
ERO to address Commission concerns
regarding the applicability threshold
through the ERO’s Reliability Standards
development process.72 The
Commission was concerned that the
bright-line applicability threshold of
200 kV in this Reliability Standard
would exclude a significant number of
transmission lines that could impact
Bulk-Power System reliability. We
stated that, in proposing to require the
ERO to modify the Reliability Standard
to apply to Bulk-Power System
transmission lines that have an impact
on reliability as determined by the ERO,
we did not intend to make this
Reliability Standard applicable to fewer
facilities than it is currently, but to
72 Id. at P 735.
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extend the applicability to lower-voltage
facilities that have an impact on
reliability.
u. Requests for Rehearing
97. NRECA asks that the Commission
clarify that Order No. 693 did not
mandate that FAC–003–1 apply to lines
below 200 kV. NRECA believes that a
fair reading of Order No. 693 is that the
Commission only directed the ERO to
give additional consideration to having
FAC–003–1 apply to lines below 200 kV
and did not purport to require such a
modification.73 However, NRECA
claims that other portions of Order No.
693 appear to go further, such as where
the Commission states that it is
requiring the Reliability Standard ‘‘to
include a greater number of entities* *
*’’. 74 In view of the potential ambiguity,
NRECA requests that the Commission
clarify that it is not dictating a particular
outcome to the ERO’s deliberations, as
such a directive would be contrary to
section 215 of the FPA, Order Nos. 672
and 672–A, and other portions of Order
No. 693. Alternatively, NRECA requests
rehearing.
v. Commission Determination
98. We will grant NRECA’s request for
clarification. First, in Order No. 693, we
specifically stated that ‘‘[w]e will not
direct NERC to submit a modification to
the general limitation on applicability
[in FAC–003–1] as proposed in the
NOPR.’’ 75 Further, as a general matter,
we stated that a direction for
modification should not preclude the
consideration of viable alternatives in
the ERO’s Reliability Standards
development process.76
99. In Order No. 693, the Commission
stated that it was concerned that the
bright-line applicability threshold of
200 kV would exclude a significant
number of transmission lines that could
impact Bulk-Power System reliability.
We noted that, at that time no regional
reliability organization had used its
discretion to designate lower voltage
lines under the proposed Reliability
Standard, even though there are lower
voltage lines involving IROL.77 The
73 NRECA at 23, citing Order No. 693 at P 706
(‘‘We will not direct NERC to submit a modification
to the general limitation on applicability as
proposed in the NOPR. However, we will require
the ERO to address the proposed modification
through its Reliability Standards development
process’’).
74 NRECA at 23, citing Order No. 693 at P 711.
75 Order No. 693 at P 706.
76 Id. at P 185–86.
77 The Commission notes that the Regional
Entities have since filed their definitions of bulk
electric system and that at least one Regional Entity,
WECC, has designated lower voltage facilities that
must comply with the Reliability Standards.
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Commission was concerned that this
approach would not require all
transmission lines that could impact
Bulk-Power System reliability to be
included under this Reliability
Standard. While the Commission did
not mandate that FAC–003–1 apply to
lines below 200 kV, the Commission did
require the ERO to address the
Commission’s concerns through its
Reliability Standards development
process.
5. IRO–001–1
100. IRO–001–1 requires that a
reliability coordinator have reliability
plans, coordination agreements and the
authority to act and direct reliability
entities to maintain reliable system
operations under normal, contingency
and emergency conditions. Requirement
R3 provides that a reliability
coordinator ‘‘shall have clear decisionmaking authority to act and direct
actions to be taken’’ by applicable
entities to ‘‘preserve the integrity and
reliability of the bulk electric system
and these actions shall be taken without
delay but no longer than 30 minutes.’’
101. Order No. 693 approved
Reliability Standard IRO–001–1. In
Order No. 693, the Commission
declined to adopt a change suggested by
Santa Clara that would only require the
commencement of corrective control
action within a 30-minute limit. We
found that the requirement to take
action without delay and within the 30minute limit is important to minimize
the amount of time the system operates
in an insecure mode and is vulnerable
to cascading outages.78
w. Requests for Rehearing
102. Santa Clara seeks rehearing of the
Commission’s determination not to
order the ERO to modify Reliability
Standard IRO–001–1. Santa Clara is
concerned that the 30-minute time
period during which entities must take
remedial action under this Reliability
Standard could be too short with respect
to physical actions that must be taken
where the facilities which are subject to
these actions cannot be readily accessed
within the 30-minute time period.79
103. First, Santa Clara maintains that
the reliability coordinator could direct
that load be dropped within Silicon
Valley Power’s (SVP) service territory.80
According to Santa Clara, those
78 Id. at P 898.
79 In its comments to the NOPR, Santa Clara
requested that this requirement of IRO–001–1 be
revised to read: ‘‘Actions shall be commenced
without delay, but in any event, shall commence
within 30 minutes.’’ Santa Clara Comments,
December 28, 2006 at 30.
80 SVP is the utility division of Santa Clara.
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directives could only be implemented
through a physical activity, such as
opening breakers within certain
substations, and cannot be
accomplished at all times using an
electronic signal from SVP’s control
center. Therefore, Santa Clara claims
that, while SVP personnel would
respond to the reliability coordinator’s
directive immediately, the required
action might not be able to be
accomplished within 30 minutes.
104. As another example, Santa Clara
states that SVP has a program through
which certain SVP retail customers can
commit to reduce base load by 10
percent where an emergency exists in its
control area. However, Santa Clara
maintains that reducing load by shutting
down power to specific buildings can
take longer than 30 minutes. Santa Clara
states that it is not seeking to have the
language in IRO–001–1 modified as it
requested in comments to the NOPR.
Rather, it seeks to have the Commission
grant rehearing to direct NERC to
modify IRO–001–1 and allow Santa
Clara to work with NERC to develop
clarifications and refinements to IRO–
001–1 to remedy its concerns.
105. Avista seeks clarification of the
intent of Order No. 693 as to whether
the authority of a reliability coordinator
to issue directives to reliability entities
arises out of (i) reliability coordinator
contracts or (ii) Commission-approved
Reliability Standards without reliance
on reliability coordinator contracts.
According to Avista, if the authority of
a reliability coordinator is noncontractual and arises out of
Commission-approved Reliability
Standards, the Commission must make
sure that such authority is accompanied
by equitable treatment of reliability
entities. For example, Avista states that
the Commission should require
equitable compensation for re-dispatch
of generation required by the reliability
coordinator and emphasizes the need
for fair and impartial procedures and
methodologies are adopted to ensure
that such equitable treatment is
provided.
106. Avista states the Commission’s
statement in Order No. 693 that it
‘‘clarifies that it did not intend to
change existing contracts, impose new
organizational structures or otherwise
affect existing agreements that set forth
the responsibilities of various
entities’’ 81 applies to existing
agreements that affect reliability
coordinator functions. According to
Avista, provisions of IRO–001–1 seem to
imply that, as to the source and scope
of authority for a reliability coordinator
81 Order No. 693 at P 141.
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to issue directives, existing contracts
may have been superseded, or rendered
moot or unnecessary, by Order No. 693.
In particular, Avista contends that
Requirement R8 of IRO–001–1 seems to
suggest that contracts are unnecessary to
authorize reliability coordinators to
issue directives.82
107. Avista asserts that, if
transmission operators or balancing
authorities or other reliability entities
are subject to a non-contractual duty
imposed by the Commission under
Order No. 693 to comply with the
directives of a reliability coordinator,
the Commission should clearly indicate
such a requirement. It notes that, in
another proceeding, Western Electricity
Coordinating Council (WECC) seems to
suggest that it believes that when the
reliability coordination Reliability
Standards become mandatory, the
existing contracts regarding reliability or
security coordination no longer will be
relevant and will not be necessary to
authorize reliability coordinators to
issue mandatory directives to reliability
entities.83
108. On the other hand, Avista
maintains that additional provisions of
IRO–001–1 suggest that reliability
coordinators must have contracts or
other written evidence in place that
delineate and evidence their authority
over reliability entities. For example,
Avista cites measure M2 of IRO–001–1,
which states that each reliability
coordinator shall have and provide
upon request evidence that could
include, but is not limited to, job
descriptions, signed agreements, an
authority letter signed by an officer of
the company, or other equivalent
evidence that will be used to confirm
that the reliability coordinator has the
authority to act as described in
Requirement 3. According to Avista,
82 Requirement R8 states: ‘‘R8. Transmission
Operators, Balancing Authorities, Generator
Operators, Transmission Service Providers, LoadServing Entities, and Purchasing-Selling Entities
shall comply with Reliability Coordinator directives
unless such actions would violate safety,
equipment, or regulatory or statutory requirements.
Under these circumstances, the Transmission
Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Load-Serving
Entity, or Purchasing-Selling Entity shall
immediately inform the Reliability Coordinator of
the inability to perform the directive so that the
Reliability Coordinator may implement alternate
remedial actions.’’
83 Supplemental Comments of the Western
Electricity Coordinating Council (WECC) filed
March 12, 2007, in Docket No. RR06–3–001 at 13
(‘‘Currently the BAs [balancing authorities] and
TOPs [transmission operators] have a contractual
obligation to comply with such directives, except in
narrow, enumerated circumstances. Once the
reliability standards are mandatory, BAs and TOPs
must obey such directives or be subject to major
penalties or other sanctions.’’) (footnote omitted).
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this provision suggests that the source of
authority to issue directives lies in a
contractual relationship between the
reliability coordinator and each
reliability entity covered by the
requirements of Requirement R3.84 In
Avista’s view, the language in the
Purpose section indicates that the
purpose of IRO–001–1 is to establish
authority of reliability coordinators over
reliability entities through contracts, in
addition to establishing internal
authority through delegations of
authority and plans presumably through
Requirement R2.
109. Avista asserts that the security
coordinator in the Pacific Northwest,
PNSC, does not have contractual
relationships with reliability entities
other than control area operators. Avista
contends that, if the authority of a
reliability coordinator to issue directives
to reliability entities arises out of
reliability coordinator contracts, the
reliability coordinator will need to enter
into contractual relationships with each
of the reliability entities within its
area—which would expand the scope of
and parties to the current PNSC
contracts. Further, Avista states that
existing contracts may not contain
provisions regarding the authority of
reliability coordinators to issue
directives to reliability entities that fully
track the Reliability Standards.85
110. Therefore, Avista requests
rehearing and asks that the Commission
require that (1) reliability coordinators
develop and file contracts or tariffs that
govern their reliability coordination
authority and activities, and (2) such
contracts or tariffs ensure equitable
treatment of reliability entities by
reliability coordinators and provide
adequate procedures and methodologies
to help ensure such equitable treatment.
Avista also seeks rehearing for the
purpose of expanding the time to
transition from the current, voluntary
contractual arrangements to the
arrangements contemplated by Order
No. 693.
111. Specifically, Avista asserts that
the Commission should require
reliability coordinators to file such
contracts or tariffs under section 205 of
the FPA. In this regard, Avista states
that the Commission should, as a first
84 Requirement R3 states, ‘‘The Reliability
Coordinator shall have clear decision-making
authority to act and to direct actions to be taken by
Transmission Operators, Balancing Authorities,
Generation Operators, Transmission Service
Providers, Load Serving Entities and PurchasingSelling Entities within its Reliability Coordinator
Area to preserve the integrity and reliability of the
Bulk Electric System.’’
85 For example, Avista contends that
Requirements R8 and R3 of IRO–001–1, when read
together, contain very broad language.
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step, require reliability coordinators to
submit for filing their existing contracts,
such as the contracts between PNSC and
the control area operators. According to
Avista, filing of these contracts or tariffs
under section 205 should ensure the
equitable treatment of reliability
entities, provide a mechanism for
redress in the event of inequitable
treatment, and provide a basis for the
Commission’s determination that the
Reliability Standards approved by Order
No. 693 are just and reasonable.
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x. Commission Determination
112. In response to Avista, the
Commission clarifies that a reliability
coordinator’s authority to issue
directives arises out of the
Commission’s approval of Reliability
Standards that mandate compliance
with such directives. Avista is correct
that contracts are unnecessary to
authorize reliability coordinators to
issue directives. Under the voluntary
reliability scheme in place prior to
section 215 of the FPA, a contractual
basis was needed to assure that entities
would comply with a reliability
coordinator’s directive. Pursuant to the
current, mandatory reliability scheme
established by statute, contracts are no
longer needed. We view the concerns
raised by Avista as part of the transition
from a voluntary to mandatory scheme.
Although, as noted by Avisa, IRO–001–
1 retains references to contracts, we
view these as vestiges of an earlier
program that no longer control given the
current, mandatory mechanism.
113. Avista’s assertion that, if
transmission operators, balancing
authorities or other reliability entities
are subject to a non-contractual duty
imposed by the Commission under
Order No. 693 to comply with the
directives of a reliability coordinator,
the Commission should have clearly
indicated such a requirement, is not
justified. First, the Commission believes
that this duty was clearly laid out in the
Reliability Standards themselves.
However, the duty to comply with
Reliability Standards is imposed by
section 215 of the FPA, not by contract.
The Reliability Standards approved by
the Commission include requirements
that certain users, owners and operators
of the Bulk-Power System follow
directions given by the reliability
coordinators.86 The duty to follow such
86 For example, Requirement R9 of IRO–001–1
states that transmission operators, balancing
authorities, generator operators, transmission
service providers, load-serving entities, and
purchasing-selling entities shall comply with
Reliability Coordinator directives unless such
actions would violate safety, equipment, or
regulatory or statutory requirements.
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directions lies in the duty to comply
with Reliability Standards as laid out in
section 215 of the FPA and the
Commission’s regulations.
114. The Commission notes that
Avista uses the Commission’s statement
that it ‘‘clarifies that it did not intend to
change existing contracts, impose new
organizational structures or otherwise
affect existing agreements that set forth
the responsibilities of various
entities’’ 87 for the proposition that the
Commission did not intend to change or
otherwise affect existing agreements
about reliability coordinator functions.
We disagree with Avista on this point.
The Commission made this statement
regarding the responsibility for
functions in the Functional Model,
especially regarding ISOs, RTOs or any
organizations that pool resources. In
that statement, we clarified that we were
not changing any contract to which an
ISO, RTO or pooled resource
organization is a party as to who must
comply with specific requirements of
the Reliability Standards.
115. In response to Avista’s arguments
regarding Measure M2 of IRO–001–1,
the Commission does not believe that
this measure imposes a requirement that
reliability coordinators must have
contracts in place. Measure M–2 of IRO–
001–1 requires each reliability
coordinator to have and provide upon
request evidence that it has the
authority to have clear decision-making
authority to act and to direct actions to
be taken by certain users, owners and
operators within its area to preserve the
integrity and reliability of the bulk
electric system. Neither the Reliability
Standard nor the Commission
prescribed the form of such evidence.
116. Avista’s concerns regarding
whether existing contracts, including
those regarding the contracts with
PNSC, and whether contracts, generally,
have been superseded or rendered moot
or unnecessary by Order No. 693 are
beyond the scope of this proceeding.
This proceeding established mandatory
Reliability Standards, including those
pertaining to directions by reliability
coordinators. Reliability coordinator
contracts are not before the Commission
in this proceeding. Therefore, the
Commission cannot rule here on any
issue regarding such contracts.
117. The Commission denies Avista’s
request that the Commission require
reliability coordinators to develop and
file contracts or tariffs that govern their
reliability coordination authority and
activities. The Commission understands
that reliability must be a primary goal.
Each user, owner and operator of the
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Bulk-Power System must be in
compliance with the Reliability
Standards so that everyone can have the
benefits of using the system. As stated
above, the Reliability Standards do not
prescribe the form through which each
reliability coordinator must provide
evidence of its clear decision-making
authority to act and to direct actions to
be taken by certain entities. To that end,
it is unnecessary to require each
reliability coordinator to file a contract
or tariff.
118. We deny Santa Clara’s request for
rehearing. In Order No. 693, the
Commission noted that various
commenters provided specific
suggestions to improve or otherwise
modify a Reliability Standard that
address issues not raised in the NOPR.
In such circumstances, the Commission
directed the ERO to consider such
comments as it modifies the Reliability
Standards during the three-year review
cycle contemplated by NERC’s Work
Plan through the ERO Reliability
Standards development process. The
Commission, however, did not direct
any outcome other than that the
comments receive consideration.88
119. However, the Commission
denied Santa Clara’s specific request to
modify Requirement R3 of IRO–001–1,
explaining that, when system integrity
or reliability is jeopardized, e.g., when
IROLs or SOLs are exceeded, the
relevant reliability entities must take
corrective control actions to return the
system to a secure and reliable state as
soon as possible but not longer than 30
minutes.89 The Commission believes
that this reaction time has been vetted
through the industry and that the 30minute time limit for action is important
to minimize the amount of time the
system operates in an insecure mode
and is vulnerable to cascading outages.
6. IRO–005–1 and IRO–005–2
120. IRO–005–1 ensures energy
balance and transmission reliability for
the current day by identifying tasks that
reliability coordinators must perform
throughout the day. Order No. 693
approved Reliability Standard IRO–005–
1.
y. Requests for Rehearing
121. TANC requests clarification as to
whether the Commission intended to
approve IRO–005–1 or IRO–005–2 in
Order No. 693. Although the
Commission states that it approves IRO–
005–1,90 TANC notes that NERC
submitted a later version, IRO–005–2, in
88 See id. at P 188.
89 Id. at P 898.
87 Order No. 693 at P 141.
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90 See Id. at P 945, 951.
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its November filing. Therefore, TANC
seeks clarification that the Commission
intended to approve IRO–005–1, rather
than the more recently filed IRO–005–
2.
z. Commission Determination
122. The Commission grants TANC’s
request for clarification. As stated in
Order No. 693, the Commission
approved version one of IRO–005.91
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7. MOD–013–1
123. MOD–013–1 requires the
regional reliability organizations within
an Interconnection to develop
comprehensive dynamics data
requirements and reporting procedures
needed to model and analyze the
dynamic behavior and response of each
Interconnection. More specifically, the
regional reliability organization, in
coordination with its transmission
owners, transmission planners,
generator owners and resource planners
within an Interconnection, is required
to: (1) Participate in development of
documentation for their Interconnection
data requirements and reporting
procedures; (2) participate in the review
of those data requirements and reporting
procedures at least every five years; and
(3) make the data requirements and
reporting procedures available to NERC
and other specified entities upon
request.
124. Because MOD–013–1 is a fill-inthe-blank standard, the Commission
stated that it will not approve or remand
MOD–013–1 until the ERO submits
additional information. However, the
Commission directed the ERO to
develop a modification to MOD–013–1
to (1) permit entities to estimate
dynamics data if they are unable to
obtain unit specific data for any reason;
(2) require verification of the dynamic
models with actual disturbance data and
(3) expand the applicability section to
include the planning authority,
transmission operator and transmission
planner.
aa. Requests for Rehearing
125. TANC requests that the
Commission clarify that it erred in
directing the ERO to apply MOD–013–
1 to transmission operators and
transmission planners. Although the
Commission left Reliability Standard
MOD–013–1 pending, TANC asserts that
the Commission stated that it would
adopt the NOPR proposal to expand the
applicability section to include
planning authorities, but in a later
summary paragraph directed the ERO to
apply the standard to transmission
operators and transmission planners, in
addition to planning authorities.92
TANC states that the inclusion of
transmission operators and transmission
planners was neither mentioned in the
NOPR nor discussed in Order No. 693.
In the alternative, TANC requests
rehearing.
126. ISO-New England requests
rehearing of the Commission’s
determination to (1) permit entities to
estimate dynamics data if they are
unable to obtain unit specific data for
any reason; (2) require verification of
the dynamic models with actual
disturbance data; and (3) expand the
applicability section to include the
planning authority, transmission
operator and transmission planner. ISONew England states that the
Commission’s direction to the ERO to
modify MOD–013–1 appears internally
inconsistent with other positions the
Commission took in Order No. 693.
First, ISO-New England notes that the
Commission required the ERO to modify
MOD–013–1 because it would allow the
use of estimated data but, at the same
time, required ‘‘verification of the
dynamic models with actual
disturbance data.’’
127. Second, ISO-New England
observes that the Commission stated in
Order No. 693 that ‘‘[f]ailure to provide
the data needed for dynamics system
modeling and simulation would halt
regional reliability assessment processes
and impede planners from accurately
predicting future system conditions,
which would be detrimental to system
reliability.’’ 93 Further, ISO-New
England points to the Commission’s
statement in Order No. 693 that it
believes ‘‘to achieve the goal of this
Reliability Standard of having the
ability to accurately model and analyze
the dynamic behavior and response of
each Interconnection, it is necessary to
have accurate data.’’ 94 In sum, ISO-New
England argues that just as the
Commission has recognized the
importance of accurate data with respect
to the administration of other NERC
Reliability Standards, the Commission
should equally recognize the
importance with regard to MOD–013–1.
128. Further, ISO-New England argues
that the Blackout Report suggests that
actual data should be required.95
Specifically, ISO-New England points to
the Blackout Report’s recommendation
40733
to improve the quality of system
modeling data and data exchange
practices. ISO-New England notes that
the Blackout Report indicates that
‘‘after-the-fact models developed to
simulate August 14 conditions and
events found that the dynamic modeling
assumptions for generator and load
power factors in regional planning and
operating models were frequently
inaccurate.’’ 96 Further, ISO-New
England states that the Task Force
commented that, during the
investigation process, it too found that
data was frequently not available.97
Consequently, ISO-New England
maintains that the Task Force
recommended the collection of
validated data.98
129. Finally, ISO-New England states
that Order No. 693 leaves too much
unclear in terms of its direction that
entities should be permitted to estimate
dynamics data if unit specific data is
unavailable ‘‘for any reason.’’ According
to ISO-New England, this exemption
appears ‘‘overbroad’’ and could serve as
the basis for an asset owner’s rejection
of any reasonable request for the unit
specific data. ISO-New England requests
that, if the Commission retains its
direction to permit entities to estimate
dynamics data, that it narrow the scope
of the exemption that asset owners may
employ in providing unit specific data.
bb. Commission Determination
130. The Commission denies TANC’s
request for rehearing. TANC correctly
identifies that the Commission did not
approve or remand MOD–013–1, but
provided direction to the ERO
concerning the addition of entities not
already identified in the Reliability
Standard. Although we acknowledge
that Order No. 693 did not include a
discussion of the addition of
transmission operators and transmission
planners in the applicability section of
this Reliability Standard, in directing
the ERO to apply MOD–013–1 to
transmission operators and transmission
planners, we recognized that
transmission operators and transmission
planners would be required to perform
coordination functions under
Requirement R1 of MOD–013–1.
Therefore, the Commission directed the
ERO to specifically include
transmission operators and transmission
planners in the applicability section of
MOD–013–1 so as to be clear what the
Commission considers to be the
minimum applicability of this
92 Compare Order No. 693 at P 1199; 1200.
91 The Commission notes that many provisions of
93 Id. at P 1177.
96 Blackout Report at 160.
IRO–005–2 only become effective when BAL–002 is
retired. If and when NERC proposes to retire BAL–
002, we will make a determination on IRO–005–2.
94 Id. at P 1188.
97 Id. at 161.
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95 ISO-New England at 4, citing Blackout Report
at 160–61.
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98 ISO-New England at 4, citing Blackout Report
at 160–61.
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Reliability Standard and to make the
Reliability Standard internally
consistent.
131. In response to ISO-New
England’s concerns, the Commission
notes that the data referenced in
Requirement R1.1 include ‘‘items such
as inertia constant, damping coefficient,
saturation parameters, and direct and
quadrature axis reactances and time
constants, excitation systems, voltage
regulators, turbine-governor systems,
power system stabilizers, and other
associated generation equipment.’’
Much of these data will be estimated
from similar classes of facilities prior to
the facilities going into service. The
Commission clarifies that its
determination to permit entities to
estimate dynamics data if they are
unable to obtain unit specific data for
any reason is limited to the initial
analysis of dynamics data. While we
continue to believe that ‘‘[a]chieving the
most accurate possible picture of the
dynamic behavior of the
Interconnection requires the use of
actual data,’’ 99 we acknowledge that, in
certain circumstances, actual data may
not be initially available and only
obtained through ‘‘verification of the
dynamic models with actual
disturbance data.’’ In addition, in Order
No. 693, we determined that ‘‘the
Reliability Standard should include
Requirements that such estimates be
based on sound engineering principles
and be subject to technical review and
approval of any estimates at the regional
level.’’ 100 This procedure would allow
peer review and approval at a regional
level such that an entity could not avoid
using sound engineering principles in
obtaining the initial data for the model.
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8. PRC–007–0, PRC–008–0, and PRC–
009–0
132. PRC–007–0 requires transmission
owners, transmission operators, loadserving entities and distribution
providers to provide, and annually
update, their underfrequency data to
facilitate the regional reliability
organization’s maintenance of the UFLS
program database.101 PRC–008–0
requires transmission owners and
distribution providers to implement
UFLS equipment maintenance and
testing programs and provide program
results to the regional reliability
organization. PRC–009–0 ensures that
the performance of a UFLS system is
analyzed and documented following an
99 Order No. 693 at P 1197.
100 Id.
101 A UFLS program is a ‘‘safety net’’ that will
automatically drop load at specific locations in the
power system in an effort to re-establish the balance
between generation and load to avoid cascading.
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underfrequency event by requiring the
transmission owner, transmission
operator, load-serving entity and
distribution provider to document the
deployment of their UFLS systems in
accordance with the regional reliability
organization’s program. Order No. 693
approved Reliability Standards PRC–
007–0, PRC–008–0,102 and PRC–009–
0.103
133. These Reliability Standards
reference PRC–006–0, which the
Commission did not approve or remand
because the regional procedures
required by the Reliability Standard had
not been submitted and because it
applies to regional reliability
organizations.104 The Commission
reasoned that since PRC–007–0, PRC–
008–0, and PRC–009–0 are existing
Reliability Standards that have been
followed on a voluntary basis,
transmission owners, transmission
operators, distribution providers and
load-serving entities are generally aware
of their requirements. In addition, the
Commission stated that a reference in an
approved Reliability Standard to an
unapproved Reliability Standard may be
considered in an enforcement action,
but is not a reason to delay approving
and enforcing this Reliability Standard.
cc. Request for Rehearing
134. APPA requests rehearing of
Commission approval of PRC–007–0,
PRC–008–0, and PRC–009–0. As
discussed more fully in the section
concerning ‘‘Fill-in-the-Blank Standards
above,105 APPA believes that each of
these three Reliability Standards cannot
be approved because it references a fillin-the-blank standard that was not
approved or remanded by the
Commission.
135. According to APPA, PRC–006–0
is the Reliability Standard that requires
the development of regional UFLS
programs and contains detailed and
exacting requirements that the regions
develop and apply to applicable
entities. According to APPA, PRC–006–
0 is the source of the design and
documentation of regional UFLS
programs and is not merely
administrative or a simple codification
of established industry practice. Rather,
102 The Commission also directed the ERO to
develop a modification to PRC–008–0 that includes
a requirement that maintenance and testing of a
protection system must be carried out within a
maximum allowable interval that is appropriate to
the type of the protection system and its impact on
the reliability of the Bulk-Power System. The
Commission’s direction to modify PRC–008–0 is not
at issue in this proceeding.
103 Order No. 693 at P 1484, 1491, and 1498.
104 Id. at P 1479.
105 See section II.C.2., 2. Fill-in-the-Blank
Standards, supra.
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APPA asserts that PRC–006–0 sets forth
very specific requirements that each
regional UFLS program must meet.
136. APPA asserts that PRC–007–0,
PRC–008–0 and PRC–009–0 go much
further than imposing data
requirements. APPA states that PRC–
007–0 requires, among other things, that
any transmission owner and
distribution provider with a UFLS
program must ensure that its UFLS
program is consistent with its regional
reliability organization’s UFLS program
requirements. PRC–008–0 requires
transmission owners and distribution
providers to implement UFLS
equipment maintenance and testing
programs and provide program results
to the regional reliability organization.
Finally, APPA maintains that PRC–
009–0 requires a transmission owner,
transmission operator, load-serving
entity, and distribution provider that
owns or operates a UFLS program to
analyze performance under that
unapproved program. According to
APPA, because the required UFLS
program has not been approved or
reviewed by the Commission under
PRC–006–0, users, owners and operators
of the Bulk-Power System cannot be
required to have a program consistent
with it.
137. APPA maintains that the fact that
these three Reliability Standards apply
to specific users, owners and operators
of the Bulk-Power System, rather than a
regional reliability organization, does
not justify approval of a reliability
standard that requires users, owners and
operators of the Bulk-Power System to
comply with regional UFLS programs
that have not been approved by NERC,
and have not been shown to meet the
procedural and substantive
requirements of section 215 of the FPA
and Order No. 672 for Reliability
Standards that qualify for approval and
enforcement by the ERO and this
Commission. Further, APPA contends
that, although the Commission appears
to have approved these Reliability
Standards in part because they have
‘‘been followed on a voluntary basis,’’
many small entities have often not been
part of regional reliability organizations
and have not necessarily been aware of,
much less followed, regional programs
on a voluntary basis.
dd. Commission Determination
138. We deny APPA’s request for
rehearing and affirm our approval of
Reliability Standards PRC–007–0, PRC–
008–0 and PRC–009–0. However, as
explained below, we clarify that the
limited provisions that relate to the
regional UFLS program developed
under PRC–006–0 are not enforceable
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until the Commission approves PRC–
006–0.106 Specifically, any entity that is
responsible for compliance with PRC–
007–0, PRC–008–0 or PRC–009–0 that
currently does not have a UFLS program
is not required to develop such a
program until PRC–006–0 is approved.
Likewise, a responsible entity with an
existing UFLS program is not required
to comply with a regional UFLS
program until the Commission approves
PRC–006–0. An explanation for this
determination follows.
139. Each of the requirements in PRC–
007–0, PRC–008–0 and PRC–009–0,
with the exception of Requirement R1 in
PRC–007–0, apply only to those entities
that have a UFLS program. Therefore,
contrary to APPA’s assertion, PRC–007–
0, PRC–008–0 and PRC–009–0 do not
require any entity that does not have a
UFLS program to develop one. That
requirement would fall under PRC–006–
0. To be clear, the Commission will not
impose a penalty for the failure to have
a UFLS program until such time as
PRC–006–0 or a suitable substitute, and
the attendant regional UFLS programs,
are approved.
140. However, we disagree with
APPA that the fact that Requirement R1
references the regional UFLS program
precludes us from approving PRC–007–
0, PRC–008–0 and PRC–009–0, which
provide for updating an entity’s UFLS
program (PRC–007–0), maintaining the
entity’s UFLS facilities (PRC–008–0),
and reporting on events that involve the
entity’s UFLS (PRC–009–0). Rather, we
uphold our earlier decision to approve
these three Reliability Standards with
the clarification that Requirement R1 of
PRC–007–0 is not enforceable until the
Commission approves PRC–006–0. We
further clarify, consistent with our
discussion above, that, until PRC–006–
0 is approved, an entity that does not
currently have a UFLS program is not
required to develop one or to comply
with PRC–007–0, PRC–008–0 and PRC–
009–0. However, an applicable entity
that currently has a UFLS program must
continue to maintain that program as
required by these three Reliability
Standards. As discussed below, the
Requirements of PRC–007–0, PRC–008–
0 and PRC–009–0 are necessary for
Bulk-Power System reliability and are
not dependent on PRC–006–0.
141. PRC–007–0, Requirement R2
states that the applicable entities ‘‘shall
provide, and annually update, its
underfrequency data as necessary for its
Regional Reliability Organization to
maintain and update a UFLS program
106 Such provisions would similarly be
enforceable if NERC develops and the Commission
approves a substitute for PRC–006–0.
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database.’’ 107 It is vital to maintain this
safety net that each registered
transmission owner, transmission
operator, distribution provider and loadserving entity with a UFLS system has
a program to annually review the
location of their UFLS devices and the
magnitude of load that can be
collectively activated as necessary.108
The reason for the annual review is that
it is not unusual for loads to be
switched among distribution feeders
and, with load growth, additional
distribution feeders may need to be
included to meet the requirements of
the entities’ UFLS program. In addition,
it is necessary to verify that sensitive
and critical loads such as hospitals and
high impact facilities continue to be
excluded from the load shedding
program. While it may be necessary to
shed load to preserve the Bulk-Power
System, it is also good public policy to
limit the nature of the facilities that
could be interrupted.
142. PRC–008–0, Requirement R1
states that the applicable entities ‘‘shall
have a UFLS equipment maintenance
and testing program in place.’’ These
programs are in place to assure that this
last resort system, which has been
proven to be necessary to limit the
geographic scope of blackouts, operates
as expected when required to in
accordance with the reliability
assessments.
143. PRC–009–0, Requirement R1
identifies what analysis must be
completed by the applicable entities
after an underfrequency event. It states
that ‘‘[t]he analysis shall address the
performance of UFLS equipment and
program effectiveness following system
events resulting in system frequency
excursions below the initializing set
points of the UFLS program.’’ This
requirement assures that actual data on
the operation of the UFLS system can be
correlated with simulations to provide a
check on how well the UFLS system is
performing its last resort function.
144. Requirement R1 of PRC–007–0
requires the transmission owner and
distribution provider to ‘‘ensure that its
UFLS program is consistent with its
Regional Reliability Organization’s
UFLS program requirements.’’ Because
the regional UFLS program would be
developed pursuant to PRC–006–0, and
the Commission has not approved or
remanded that Reliability Standard, we
agree with APPA that Requirement R1
cannot be enforced as written until the
107 While Requirement R2 identifies the regional
reliability organization, we note that this
information should go to the Regional Entity or the
ERO as the entities with statutory authority under
section 215 of the FPA.
108 Blackout Report at 62.
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40735
Commission approves PRC–006–0,
because Requirement R1 would
essentially require compliance with an
unapproved Reliability Standard.
Because Requirement R1 of PRC–007–0
is not enforceable until the Commission
approves PRC–006–0, a transmission
owner’s or distribution provider’s UFLS
program cannot be judged for
compliance with the unapproved
regional UFLS program.
145. While the Commission will not
enforce compliance with PRC–006–0,
the possible reduction in the amount of
load available for underfrequency load
shedding can negatively impact the
Reliable Operation of the Bulk-Power
System. Because of the importance of
the UFLS programs and the fact that
there currently are no Commissionapproved Reliability Standards by
which to judge individual UFLS
programs, the Commission believes it is
important to monitor the current UFLS
programs so that we can consider if they
provide an adequate safety net for the
Bulk-Power System. Therefore, the
Commission directs the ERO to collect
the frequency and magnitude of load in
UFLS systems from applicable entities
for this summer, from date of order
through September 30, 2007, and
perform an analysis as to the ability of
the existing system to provide the
required last resort function within 90
days of this order. This analysis should
consider if the existing UFLS plans
together provide an adequate safety net
for the Bulk-Power System.
146. In discussing potential
ambiguities in the proposed Reliability
Standards in Order No. 693, the
Commission stated that, even if some
clarification of a particular Reliability
Standard would be desirable at the
outset, making it mandatory allows the
ERO and the Regional Entities to
provide that clarification on a goingforward basis while still requiring
compliance with Reliability Standards
that have an important reliability
goal.109 We believe that this principle
applies equally to a Reliability Standard
where one Requirement may not be
enforceable, but the Reliability Standard
must be approved to enable enforcement
of other Requirements.
147. The reliability goal of PRC–007–
0, PRC–008–0 and PRC–009–0 is to
provide last resort system preservation
measures by implementing an UFLS
program. The Commission believes that
this is an important reliability goal. The
Commission understands that, until
109 Order No. 693 at P 277. See also Order No. 693
at P 147, 157–58, explaining that the Commission
was approving and requiring modification to five
Reliability Standards that apply partially to a
regional reliability organization.
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PRC–006–0 is approved, the UFLS
program implemented will not be the
one envisioned in PRC–006–0. We
believe that, where a user, owner or
operator does have a UFLS program, the
data retention and reporting
requirements incorporated in these
Reliability Standards serve an extremely
important goal of providing last resort
system preservation measures. NERC
can analyze the information to monitor
whether the last resort system
preservation measures are sufficient in
the aggregate for the entire Bulk-Power
System. Although the ERO and Regional
Entities cannot penalize a user, owner
or operator for an insufficient UFLS
program until the Commission approves
PRC–006–0, collection, analysis and
submission of the UFLS information
described above will provide NERC and
the Commission with invaluable
information regarding the reliability of
the Bulk-Power System.
148. We further believe that, other
than R1 in Reliability Standard PRC–
007–0, the Requirements in the PRC
Reliability Standards are independently
enforceable. For example, R2 of
Reliability Standard PRC–007–0
requires a transmission owner or
distribution provider with a UFLS
program to provide, and annually
update, its underfrequency data.
Although R2 contains the phrase ‘‘(as
required by its Regional Reliability
Organization),’’ the Commission
believes that it is of vital importance for
the transmission owner and distribution
provider to update its UFLS data
annually and provide it to the ERO.
Because we have not approved any
regional programs, this parenthetical
currently has no meaning in the context
of the approved Reliability Standard.
Therefore, the Commission believes that
these three Reliability Standards only
apply to those entities that have a UFLS
program, irrespective of whether a
region requires it.
149. The Commission also denies
rehearing of our approval of PRC–008–
0. This Reliability Standard requires
each transmission owner and
distribution provider with a UFLS
program to have a UFLS program in
place that includes UFLS equipment
identification and the schedule for
UFLS equipment testing and
maintenance. PRC–008–0 further
requires each transmission owner and
distribution provider with a UFLS
program to implement its UFLS
equipment maintenance and testing
program and provide UFLS
maintenance and testing program results
to its regional reliability organization
and NERC on request. In this Reliability
Standard, any transmission owner or
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distribution provider that already has a
UFLS program must develop its own
equipment maintenance and testing
program that complies with PRC–008–0.
The Commission believes it is of great
importance to Bulk-Power System
reliability for such entities to perform
such maintenance and testing. Because
the maintenance and testing programs
do not rely on regional reliability
organization requirements, but are,
rather, developed by the applicable
entity itself, the Commission continues
to believe that this Reliability Standard
is enforceable regardless of whether the
Commission has approved PRC–006–0.
150. Finally, the Commission does not
believe that the fact that PRC–006–0 has
not been approved or remanded
necessitates granting rehearing of our
approval of PRC–009–0. This Reliability
Standard requires a transmission owner,
transmission operator, load-serving
entity and distribution provider that
owns or operates a UFLS program to
analyze and document its UFLS
program performance in accordance
with its regional reliability
organization’s UFLS program. The
Commission acknowledges, as stated
above, that currently there is no
Commission-approved UFLS program.
However, R1 of PRC–009–0 also
includes independent criteria by which
a user, owner or operator of the BulkPower System must analyze its UFLS
program. R1 states that:
The analysis shall address the performance
of UFLS equipment and program
effectiveness following system events
resulting in system frequency excursions
below the initializing set points of the UFLS
program. The analysis shall include, but not
be limited to:
R1.1. A description of the event including
initiating conditions.
R1.2. A review of the UFLS set points and
tripping times.
R1.3. A simulation of the event.
R1.4. A summary of the findings.
151. R2 of PRC–009–0 further requires
the transmission owner, transmission
operator, load-serving entity and
distribution provider to provide
documentation of the analysis of the
UFLS program to its regional reliability
organization and NERC on request after
a system event. This analysis will better
enable NERC to analyze system events
and determine what actions need to be
taken to ensure the Reliability of the
Bulk-Power System.
152. Therefore, the Commission
denies rehearing of our approval of
PRC–007–0, PRC–008–0 and PRC–009–
0. To be clear, we recognize that R1 of
PRC–007–0 is not enforceable until the
Commission approves PRC–006–0.
Because, prior to that approval of PRC–
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006–0, PRC–007–0, PRC–008–0 and
PRC–009–0 only apply to those entities
that already have a UFLS program, these
Reliability Standards do not require any
entity that does not have a UFLS
program to develop one, and the
Commission will not impose a penalty
for an entity’s failure to have a UFLS
program until the Commission approves
PRC–006–0. Further, until PRC–006–0
has been approved, a UFLS program
cannot be judged for compliance with
an unapproved regional UFLS program.
Therefore, the Commission clarifies
that, until PRC–006-has been approved,
only the data retention and reporting
requirements, as well as the
requirements for maintenance, testing
requirements and analysis of UFLS
performance following a triggering event
in PRC–007–0, PRC–008–0 and PRC–
009–0, are mandatory and enforceable.
9. TOP–008–1
153. TOP–008–1 requires a
transmission operator to take immediate
steps to mitigate System Operating
Limit (SOL) and Interconnection
Reliability Operating Limit (IROL)
violations. Order No. 693 approved
Reliability Standard TOP–008–1.110
Order No. 693 summarized TOP–008–1
as requiring a transmission owner to
take immediate steps to mitigate SOL
and IROL violations.111
ee. Requests for Rehearing
154. TANC requests clarification that
the Commission intended to use the
term transmission operator, rather than
transmission owner, as the correct
applicable entity in Reliability Standard
TOP–008–1.112 TANC states that the
text of the ERO-proposed Reliability
Standard lists the transmission operator
as the only entity to which TOP–008–
1 applies. Alternatively, TANC requests
rehearing.
ff. Commission Determination
155. The Commission will grant
TANC’s request for clarification. TANC
is correct that the Commission’s use of
the term transmission owner, rather
than transmission operator, was in error.
The transmission operator is the correct
applicable entity in Reliability Standard
TOP–008–1.
III. Information Collection Statement
156. Order No. 693 contains
information collection requirements for
which the Commission obtained
approval from the Office of Management
and Budget (OMB). Given that this
110 Id. at P 1679.
111 See id. at P 1675.
112 See id.
E:\FR\FM\25JYR1.SGM
25JYR1
Federal Register / Vol. 72, No. 142 / Wednesday, July 25, 2007 / Rules and Regulations
Order on Rehearing does not revise the
regulation text of Order No. 693 and
makes only minor clarifications to Order
No. 693, OMB approval for this order is
not necessary. However, the
Commission will send a copy of this
order to OMB for informational
purposes.
IV. Document Availability
157. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the Internet through
FERC’s Home Page (http://www.ferc.gov)
and in FERC’s Public Reference Room
during normal business hours (8:30 a.m.
to 5 p.m. Eastern time) at 888 First
Street, NE., Room 2A, Washington, DC
20426.
158. 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.
159. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from our Help
line at (202) 502–8222 or the Public
Reference Room at (202) 502–8371 Press
0, TTY (202) 502–8659. E-Mail the
Public Reference Room at
public.referenceroom@ferc.gov.
By the Commission.
Kimberly D. Bose,
Secretary.
[FR Doc. E7–14340 Filed 7–24–07; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF HOMELAND
SECURITY
Bureau of Customs and Border
Protection
19 CFR Part 173
[CBP Dec. 07–62]
Technical Correction: Voluntary
Reliquidation of Deemed Liquidated
Entries
AGENCY: Customs and Border Protection,
jlentini on PROD1PC65 with RULES
Homeland Security.
ACTION: Final rule.
SUMMARY: This document amends title
19 of the Code of Federal Regulations by
making technical corrections to § 173.3,
which provides for voluntary
VerDate Aug<31>2005
16:55 Jul 24, 2007
Jkt 211001
reliquidations. These technical
corrections conform § 173.3 to 19 U.S.C.
1501, as amended by section 2107 of the
Miscellaneous Trade and Technical
Corrections Act of 2004, which permits
Customs and Border Protection to
voluntarily reliquidate entries that are
deemed liquidated by operation of law.
DATES: Effective Date: July 25, 2007.
FOR FURTHER INFORMATION CONTACT:
Richard B. Wallio, Office of
International Trade, Customs and
Border Protection, Tel. (202) 344–2556.
SUPPLEMENTARY INFORMATION:
Background
This document makes technical
corrections to § 173.3 of title 19 of the
Code of Federal Regulations (19 CFR
173.3) to conform to changes to that
section’s underlying statutory authority.
Section 173.3 concerns the
voluntarily reliquidation of entries and
provides that within 90 days from the
date notice of the original liquidation is
given to the importer, consignee, or
agent, the port director may reliquidate
on his own initiative a liquidation or
reliquidation to correct errors in
appraisement, classification, or any
other element entering into the
liquidation or reliquidation.
Section 501 of the Tariff Act of 1930,
as amended (19 U.S.C. 1501), provides
the statutory authority for voluntary
reliquidations and states that Customs
and Border Protection (CBP) may
reliquidate an entry within 90 days from
the date on which notice of the original
liquidation is given or transmitted to the
importer, his consignee or agent.
Section 1501 was amended by section
2107 of the Miscellaneous Trade and
Technical Corrections Act of 2004 (Pub.
L. 108–429, 118 Stat. 2598) to include
‘‘deemed liquidations’’ of 19 U.S.C.
1504 as among the types of liquidations
CBP is authorized to voluntarily
reliquidate. The date of original
liquidation of an entry that liquidated
by operation of law is the date of
deemed liquidation.
This document makes technical
corrections to § 173.3 to conform to the
broadened scope of 19 U.S.C. 1501, as
amended, which authorizes CBP to
voluntarily reliquidate entries that have
been deemed liquidated by operation of
law pursuant to 19 U.S.C. 1504.
Examples of types of entries which may
be deemed liquidated by operation of
law are countervailing duty (CVD),
antidumping (AD), or drawback entries.
Inapplicability of Public Notice and
Comment Requirement and Delayed
Effective Date Requirement
Because the technical corrections to
19 CFR 173.3 set forth in this document
PO 00000
Frm 00027
Fmt 4700
Sfmt 4700
40737
merely conform to the statutory
amendments to 19 U.S.C. 1501 effected
by section 2107 of the Miscellaneous
Trade and Technical Corrections Act of
2004, pursuant to 5 U.S.C. 553(b)(B),
CBP finds that good cause exists for
dispensing with notice and public
procedure as unnecessary. For this same
reason, pursuant to 5 U.S.C. 553(d)(3),
CBP finds that good cause exists for
dispensing with the requirement for a
delayed effective date.
The Regulatory Flexibility Act
Because this document is not subject
to the notice and public procedure
requirements of 5 U.S.C. 553, it is not
subject to the provisions of the
Regulatory Flexibility Act (5 U.S.C. 601
et seq.).
Executive Order 12866
These amendments do not meet the
criteria for a ‘‘significant regulatory
action’’ as specified in E.O. 12866.
Signing Authority
This document is being issued in
accordance with 19 CFR 0.1(a)(1).
List of Subjects in 19 CFR Part 173
Administrative practice and
procedure, Customs duties and
inspection.
Amendment to the Regulations
■ For the reasons stated above, part 173
of title 19 of the Code of Federal
Regulations is amended as set forth
below.
PART 173—ADMINISTRATIVE REVIEW
IN GENERAL
■ 1. The authority citation for part 173
continues to read as follows:
Authority: 19 U.S.C. 66, 1501, 1520, 1624.
*
*
*
*
*
■ 2. In § 173.3, paragraph (a) is amended
by revising the first sentence to read as
follows:
§ 173.3
This text is long and has been trimmed here. Open the source document for the complete record.
This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.