Modification of Interchange and Transmission Loading Relief Reliability Standards; and Electric Reliability Organization Interpretation of Specific Requirements of Four Reliability Standards, 22856-22867 [E8-9013]
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2007, with minor corrections applied on
November 16, 2007);
(11) Business Practices for Open
Access Same-Time Information Systems
(OASIS) Implementation Guide, Version
1.4 (WEQ–013, Version 001, October 31,
2007, with minor corrections applied on
November 16, 2007).
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Note: The following statement will not
appear in the Code of Federal Regulations.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. RM05–5–005]
Standards for Business Practices and
Communication Protocols for Public
Utilities
April 21, 2008.
WELLINGHOFF, Commissioner,
concurring:
Today, the Commission issues a
Notice of Proposed Rulemaking (NOPR)
proposing to amend its regulations
under the Federal Power Act 43 to
incorporate by reference, among other
matters, the latest version of certain
business practice standards concerning
the Open Access Same-Time
Information Systems (OASIS) adopted
by the Wholesale Electric Quadrant
(WEQ) of the North American Energy
Standards Board (NAESB).44 I
appreciate NAESB’s leadership and the
work of the industry in developing these
business practice standards.
One of the business practice standards
addressed in this NOPR, WEQ–001
Version 1.4, revises NAESB’s Business
Practices for OASIS and, among other
matters, addresses the information that
is to be posted on OASIS. This
information includes posting of
ancillary service offerings and prices
and the process for customers to procure
ancillary services.
43 16
U.S.C. 791a, et. seq.
addition, the Commission proposes in this
NOPR to incorporate by reference NAESB’s new
business practices standards on transmission
loading relief (TLR) for the Eastern Interconnection.
I note my concurrence to the separate, concurrently
issued NOPR in Docket No. RM08–7–000, in which
the Commission proposes to approve, among other
matters, modified Reliability Standard IRO–006–4
pertaining to TLR procedures to which the NAESB
business practice we address herein relates.
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44 In
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I write separately to note that in Order
No. 890, the Commission determined
that many ancillary services may be
provided by generating units as well as
other non-generation resources such as
demand resources where appropriate.45
Nothing in WEQ–001 precludes such a
role for demand resources, but the
definition of certain ancillary services in
the standard also does not specifically
reflect that possible role.
To remove any confusion between the
pro forma tariff that the Commission
adopted in Order No. 890 and the
business practice standards for offering
and procuring ancillary services on
OASIS, I encourage NAESB and its
stakeholders to amend WEQ–001, as
soon as possible, to reflect that the
above-noted ancillary services may be
provided by non-generation resources
such as demand resources. This will
facilitate implementation of this aspect
of the pro forma OATT.
For this reason, I concur with this
NOPR.
Jon Wellinghoff,
Commissioner.
[FR Doc. E8–9046 Filed 4–25–08; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM08–7–000]
Modification of Interchange and
Transmission Loading Relief Reliability
Standards; and Electric Reliability
Organization Interpretation of Specific
Requirements of Four Reliability
Standards
Issued April 21, 2008.
Federal Energy Regulatory
Commission, DOE.
ACTION: Notice of proposed rulemaking.
AGENCY:
SUMMARY: Pursuant to section 215 of the
Federal Power Act, the Federal Energy
Regulatory Commission proposes to
approve six modified Reliability
Standards submitted to the Commission
for approval by the North American
Electric Reliability Corporation (NERC).
Five modified Reliability Standards
pertain to interchange scheduling and
coordination and one pertains to
transmission loading relief procedures.
In addition, the Commission proposes to
approve NERC’s proposed
interpretations of five specific
requirements of Commission-approved
Reliability Standards.
DATES:
Comments are due June 12, 2008.
You may submit comments,
identified by docket number by any of
the following methods:
• Agency Web Site: https://
www.ferc.gov. Documents created
electronically using word processing
software should be filed in native
applications or print-to-PDF format and
not in a scanned format.
• Mail/Hand Delivery: Commenters
unable to file comments electronically
must mail or hand deliver an original
and 14 copies of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
ADDRESSES:
FOR FURTHER INFORMATION CONTACT:
Patrick Harwood (Technical
Information), Office of Electric
Reliability, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426.
Christopher Daignault (Legal
Information), Office of the General
Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426.
SUPPLEMENTARY INFORMATION:
45 See Order No. 890 at P 888 (addressing the
following ancillary services: Reactive Supply and
Voltage Control, Regulation and Frequency
Response, Energy Imbalances, Spinning Reserves,
Supplemental Reserves, and Generator Imbalances
(Schedules 2, 3, 4, 5, 6, and 9, respectively, of the
pro forma OATT)).
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TABLE OF CONTENTS
I. Background ..........................................................................................................................................................................................
A. EPAct 2005 and Mandatory Reliability Standards ...................................................................................................................
B. NERC Filings ...............................................................................................................................................................................
II. Discussion ..........................................................................................................................................................................................
A. NERC’s December 19, 2007 Filing: Interpretations ..................................................................................................................
1. BAL–001–0—Real Power Balancing Control Performance and BAL–003–0—Frequency Response and Bias ..............
a. Background ....................................................................................................................................................................
i. Reliability Standard BAL–001–0 ...........................................................................................................................
ii. Reliability Standard BAL–003–0 ..........................................................................................................................
b. NERC’s Proposed Interpretations .................................................................................................................................
i. Reliability Standard BAL–001–0 ...........................................................................................................................
ii. Reliability Standard BAL–003–0 ..........................................................................................................................
c. Commission Proposal ...................................................................................................................................................
2. BAL–005–0—Automatic Generation Control .....................................................................................................................
a. NERC’s Proposed Interpretation ...................................................................................................................................
b. Commission Proposal ...................................................................................................................................................
3. VAR–002–1—Generator Operation for Maintaining Network Voltage Schedules ...........................................................
a. NERC’s Proposed Interpretation ...................................................................................................................................
b. Commission Proposal ...................................................................................................................................................
B. NERC’s December 21, 2007 Filing: Modification of TLR Procedure .......................................................................................
1. NERC’s Proposed Reliability Standard ...............................................................................................................................
a. Background ....................................................................................................................................................................
b. NERC Filing ..................................................................................................................................................................
c. Commission Proposal ...................................................................................................................................................
i. Requirements ..........................................................................................................................................................
ii. Violation Risk Factors ...........................................................................................................................................
C. NERC’s December 26, 2007 Filing: Modification to Five ‘‘Interchange and Scheduling’’ Reliability Standards ................
1. INT–001–3—Interchange Information and INT–004–2—Dynamic Interchange Transaction Modifications .................
a. Background ....................................................................................................................................................................
b. NERC’s Proposed Modifications ..................................................................................................................................
c. Commission Proposal ...................................................................................................................................................
2. INT–005–2—Interchange Authority Distributes Arranged Interchange ...........................................................................
a. INT–006–2—Response to Interchange Authority, and INT–008–2—Interchange Authority Distributes Status .....
i. Background .............................................................................................................................................................
ii. NERC’s Proposed Modifications ...........................................................................................................................
b. Commission Proposal ...................................................................................................................................................
III. Information Collection Statement ....................................................................................................................................................
IV. Environmental Analysis ...................................................................................................................................................................
V. Regulatory Flexibility Act Analysis ..................................................................................................................................................
VI. Comment Procedures .......................................................................................................................................................................
VII. Document Availability ....................................................................................................................................................................
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1. Pursuant to section 215 of the
Federal Power Act (FPA),1 the Federal
Energy Regulatory Commission
(Commission) proposes to approve six
modified Reliability Standards
submitted to the Commission for
approval by the North American Electric
Reliability Corporation (NERC). Five
modified Reliability Standards pertain
to interchange scheduling and
coordination, and one pertains to
transmission loading relief procedures.2
In addition, the Commission proposes to
approve NERC’s proposed
interpretations of five specific
requirements of Commission-approved
Reliability Standards.
1 16
U.S.C. 824o (Supp. V 2005).
2 The Commission is not proposing any new or
modified text to its regulations. Rather, as set forth
in 18 CFR Part 40, a proposed Reliability Standard
will not become effective until approved by the
Commission, and the ERO must post on its Web site
each effective Reliability Standard.
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I. Background
A. EPAct 2005 and Mandatory
Reliability Standards
2. Section 215 of the FPA requires a
Commission-certified Electric
Reliability Organization (ERO) to
develop mandatory and enforceable
Reliability Standards, which are subject
to Commission review and approval.
Once approved, the Reliability
Standards may be enforced by the ERO,
subject to Commission oversight, or by
the Commission independently.3
3. Pursuant to section 215 of the FPA,
the Commission established a process to
select and certify an ERO 4 and,
subsequently, certified NERC as the
3 See FPA 215(e)(3), 16 U.S.C. 824o(e)(3) (Supp.
V 2005).
4 Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the
Establishment, Approval and Enforcement of
Electric Reliability Standards, Order No. 672, FERC
Stats. & Regs. ¶ 31,204, order on reh’g, Order No.
672–A, FERC Stats. & Regs. ¶ 31,212 (2006).
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ERO.5 On April 4, 2006, as modified on
August 28, 2006, NERC submitted to the
Commission a petition seeking approval
of 107 proposed Reliability Standards.
On March 16, 2007, the Commission
issued a final rule, Order No. 693,
approving 83 of these 107 Reliability
Standards and directing other action
related to these Reliability Standards.6
In addition, pursuant to section
215(d)(5) of the FPA, the Commission
directed NERC to develop modifications
to 56 of the 83 approved Reliability
Standards.7
5 North American Electric Reliability Corp., 116
FERC ¶ 61,062 (ERO Certification Order), order on
reh’g & compliance, 117 FERC ¶ 61,126 (ERO
Rehearing Order) (2006), appeal docketed sub nom.
Alcoa, Inc. v. FERC, No. 06–1426 (D.C. Cir. Dec. 29,
2006).
6 Mandatory Reliability Standards for the BulkPower System, Order No. 693, FERC Stats. & Regs.
¶ 31,242, order on reh’g, Order No. 693–A, 120
FERC ¶ 61,053 (2007).
7 16 U.S.C. 824o(d)(5) (Supp. V 2005). Section
215(d)(5) provides, ‘‘The Commission * * * may
order the Electric Reliability Organization to submit
to the Commission a proposed reliability standard
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4. In April 2007, the Commission
approved delegation agreements
between NERC and each of the eight
Regional Entities, including the Western
Electricity Coordinating Council
(WECC).8 Pursuant to such agreements,
the ERO delegated responsibility to the
Regional Entities to carry out
compliance monitoring and
enforcement of the mandatory,
Commission-approved Reliability
Standards. In addition, the Commission
approved as part of each delegation
agreement a Regional Entity process for
developing regional Reliability
Standards.
5. NERC’s Rules of Procedure provide
that a person that is ‘‘directly and
materially affected’’ by Bulk-Power
System reliability may request an
interpretation of a Reliability Standard.9
The ERO’s ‘‘standards process manager’’
will assemble a team with relevant
expertise to address the clarification and
also form a ballot pool. NERC’s Rules
provide that, within 45 days, the team
will draft an interpretation of the
Reliability Standard, with subsequent
balloting. If approved by ballot, the
interpretation is appended to the
Reliability Standard and filed with the
applicable regulatory authority for
regulatory approval.
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B. NERC Filings
6. This rulemaking proceeding
consolidates and addresses three NERC
filings.
7. On December 19, 2007, NERC
submitted for Commission approval
interpretations of requirements in four
Commission-approved Reliability
Standards: BAL–001–0 (Real Power
Balancing Control Performance),
Requirement R1; BAL–003–0
(Frequency Response and Bias),
Requirement R3; BAL–005–0
(Automatic Generation Control),
Requirement R17; and VAR–002–1
(Generator Operation for Maintaining
Network Voltage Schedules),
Requirements R1 and R2.10
8. On December 21, 2007, NERC
submitted for Commission approval
modifications to Reliability Standard
IRO–006–4 (Reliability Coordination—
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.’’
8 See North American Electric Reliability Corp.,
119 FERC ¶ 61,060, order on reh’g, 120 FERC ¶
61,260 (2007).
9 NERC Rules of Procedure, Appendix 3A
(Reliability Standards Development Procedure), at
26–27.
10 In its filing, NERC identifies the Reliability
Standards together with NERC’s proposed
interpretations as BAL–001–0a, BAL–003–0a, BAL–
005–0a, and VAR–002–1a.
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Transmission Loading Relief) that
applies to balancing authorities,
reliability coordinators, and
transmission operators. NERC states that
the modifications ‘‘extract’’ from the
Reliability Standard the business
practices and commercial requirements
from the current IRO–006–3 Reliability
Standard. The business practices and
commercial requirements have been
transferred to a North American Energy
Standards Board (NAESB) business
practices document. The NAESB
business practices and commercial
requirements have been included in
Version 001 of the NAESB Wholesale
Electric Quadrant (WEQ) Standards
which NAESB filed with the
Commission on the same day, December
21, 2007.11 Further, NERC states that the
modified Reliability Standard includes
changes directed by the Commission in
Order No. 693 related to the
appropriateness of using the
transmission loading relief (TLR)
procedure to mitigate violations of
interconnection reliability operating
limits (IROLs).12
9. On December 26, 2007, NERC
submitted for Commission approval
modifications to five Reliability
Standards from the ‘‘Interchange
Scheduling’’ group of Reliability
Standards: INT–001–3 (Interchange
Information); INT–004–2 (Dynamic
Interchange Transaction Modifications);
INT–005–2 (Interchange Authority
Distributes Arranged Interchange); INT–
006–2 (Response to Interchange
Authority); and INT–008–2 (Interchange
Authority Distributes Status). NERC
states that the modifications to INT–
001–3 and INT–004–2 eliminate waivers
requested in 2002 under the voluntary
Reliability Standards regime for entities
in the WECC region. According to
NERC, modifications to INT–005–2,
INT–006–2, and INT–008–2 adjust
reliability assessment time frames for
proposed transactions within WECC.13
10. Each Reliability Standard that the
ERO proposes to interpret or modify in
this proceeding was approved by the
Commission in Order No. 693.
II. Discussion
11. The Commission discusses below
the ERO’s proposed interpretations and
proposed modifications, and the
11 NAESB December 21, 2007 Filing, Docket No.
RM05–5–005.
12 An IROL is a system operating limit that, if
violated, could lead to instability, uncontrolled
separation, or cascading outages that adversely
impact the reliability of the Bulk-Power System.
13 The proposed, modified Reliability Standard
addressed in this notice of proposed rulemaking is
available on the Commission’s eLibrary document
retrieval system in Docket No. RM08–7–000 and
also on NERC’s Web site, https://www.nerc.com.
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Commission’s proposed disposition of
each.
A. NERC’s December 19, 2007 Filing:
Interpretations
12. As mentioned above, NERC
submitted for Commission approval
interpretations of four Commissionapproved Reliability Standards.
1. BAL–001–0–Real Power Balancing
Control Performance and BAL–003–0–
Frequency Response and Bias
a. Background
i. Reliability Standard BAL–001–0
13. The purpose of Reliability
Standard BAL–001–0 is to maintain
interconnection steady-state frequency
within defined limits by balancing real
power demand and supply in realtime.14 Requirement R1 of BAL–001–0
defines the limits on area control error
(ACE), which essentially is the
mismatch between generation and load
(i.e., the mismatch between supply and
demand) within the footprint of a
balancing authority, measured by the
difference between the balancing
authority’s net actual interchange and
scheduled interchange with neighboring
balancing authorities, after taking into
account effects of deviations in
interconnection frequency.15 The ability
to constantly match load and generation
within a certain tolerance directly
affects the electrical state and control of
the Bulk-Power System.16 Each
balancing authority thus monitors the
extent of its ACE in real-time and takes
appropriate action also in real-time to
rebalance supply and demand.17
Requirement R1 obliges each balancing
authority, on a rolling twelve-month
14 See Reliability Standard BAL–001–0. Each
Reliability Standard developed by the ERO includes
a ‘‘Purpose’’ statement.
15 Generally, a balancing authority within an
interconnection has an obligation to do its part to
maintain the desired 60 Hertz (Hz) frequency. To
achieve this, each balancing authority must keep its
generation output (including net imports from
neighboring balancing authorities) and load in
balance within its footprint. A deviation from the
60 Hz baseline system frequency signals an
imbalance in supply and demand. To prevent this
imbalance from propagating throughout the
interconnection, steps are taken to adjust regulating
reserves (generation output and demand-side
management) in response to deviations from the 60
Hz optimum. See North American Electric
Reliability Corp., 121 FERC ¶ 61,179, at P 17 (2007)
(November 16, 2007 Order).
16 If generation and load is not matched within a
balancing authority’s area, the resulting imbalance
could result in an undue burden on adjacent
balancing authorities and, if additional
contingencies from disturbances are experienced,
may compromise the ability of the Bulk-Power
System to recover from those disturbances. See
November 16, 2007 Order, 121 FERC ¶ 61,179 at P
28.
17 See November 16, 2007 Order, 121 FERC ¶
61,179 at P 20.
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basis, to maintain its clock-minute
averages of ACE within a specific limit.
14. A supply/demand imbalance
between the interconnection’s
generation output (including net
imports) and load on a real-time basis
will result in a deviation from the
desired 60 Hz optimum operating
frequency of the interconnection. All of
the balancing authorities within an
interconnection must work together to
correct a deviation.18 They do this by
including a frequency bias component
in their ACE calculation which
indicates how many more or fewer
megawatts a balancing authority would
have interchanged with neighboring
balancing authorities if the actual
frequency had been exactly maintained
so as to equal to the scheduled
frequency. Thus, balancing authorities
calculate what their total interchange
would have been if the actual frequency
had been exactly maintained so as to
equal to the scheduled frequency. With
this information, the balancing authority
can increase or decrease generation
within the balancing authority’s area to
maintain the correct scheduled
interchange. The total supply and the
demand within an interconnection is
balanced by the collective effort of all
the balancing authorities in that
interconnection to maintain the correct
scheduled interchange. In this manner,
frequency deviations are minimized,
thereby protecting reliability without
causing undue burden on any balancing
authorities.
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ii. Reliability Standard BAL–003–0
15. The purpose of Reliability
Standard BAL–003–0 is to provide a
consistent method for calculating the
frequency bias component of ACE. To
accomplish this purpose, it is necessary
to rely on historic data from a balancing
authority’s automatic generation
control.19 Automatic generation control
is the equipment that calculates ACE on
an ongoing basis and serves as a
‘‘governor’’ that adjusts a balancing
authority’s generation, and demand-side
resources where available, from a
central location to minimize
unscheduled interchange with its
neighboring balancing authorities in
order to balance ACE. There are several
ways that automatic generation control
could be set to balance the supply and
demand within the balancing authority
18 See
id. P 31.
generation control refers to an
automatic process whereby a balancing authority’s
mix and output of its generation and demand-side
management is varied to offset the extent of supply
and demand imbalances reflected in its ACE.
November 16, 2007 Order, 121 FERC ¶ 61,179 at P
19 n.14.
19 Automatic
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area. One method is called the ‘‘tie-line
frequency bias’’ mode of operation.
Collective operation in this mode allows
balancing authorities’ automatic
generation control to calculate ACE and
adjust the generation in the balancing
authority area in a manner that
maintains the interconnection frequency
and does not result in an undue burden
for any balancing authority. In addition,
operation in this mode allows a
balancing authority to continuously
collect its tie-line and frequency data
that must be used when the balancing
authority annually reviews the
frequency bias component of its ACE
calculation as specified by BAL–003–0.
Requirement R3 of BAL–003–0 requires
the use of the tie-line frequency bias
mode of operation of automatic
generation control, unless such
operation is adverse to system
interconnection reliability.
b. NERC’s Proposed Interpretations
16. NERC further states that, on June
1, 2007, WECC requested that NERC
provide a formal interpretation that
addresses Requirement R1 of BAL–001–
0 and Requirement R3 of BAL–003–0. In
particular, WECC asked whether the use
of WECC’s existing automatic time error
correction procedure, which is currently
proposed as a regional Reliability
Standard, violates Requirement R1 of
BAL–001–0 or Requirement R3 of BAL–
003–0.
i. Reliability Standard BAL–001–0
17. Requirement R1 of BAL–001–0
provides:
Each Balancing Authority shall operate
such that, on a rolling 12-month basis, the
average of the clock-minute averages of the
Balancing Authority’s Area Control Error
(ACE) divided by 10B (B is the clock-minute
average of the Balancing Authority Area’s
Frequency Bias) times the corresponding
clock-minute averages of the
Interconnection’s Frequency Error is less
than a specific limit. This limit e12 is a
constant derived from a targeted frequency
bound (separately calculated for each
Interconnection) that is reviewed and set as
necessary by the NERC Operating Committee.
18. NERC’s proposed interpretation of
BAL–001–0 Requirement R1 reads:
• The [WECC automatic time error
correction or WATEC] procedural
documents ask Balancing Authorities to
maintain raw ACE for [control
performance standard or CPS] reporting
and to control via WATEC-adjusted
ACE.
• As long as Balancing Authorities
use raw (unadjusted for WATEC) ACE
for CPS reporting purposes, the use of
WATEC for control is not in violation of
BAL–001 Requirement 1.
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(NERC December 19, 2007 Filing, Ex. A–
2.)
19. As context to its interpretation,
NERC explains that BAL–001–0 uses a
formula for the ACE calculation equal to
the difference in actual and scheduled
interchange, less a component based on
the frequency bias to adjust for the
difference in actual and scheduled
frequency, less the meter error.20 NERC
also explains that the WECC automatic
time error correction procedure uses the
same formula for ACE as defined in
BAL–001–0 except with two additional
components.21
20. NERC maintains that the use of
the WECC automatic time error
correction procedure for control does
not result in a violation of BAL–001–0
Requirement 1, provided that (1)
WECC’s balancing authorities use the
raw and unadjusted ACE for control
performance reporting purposes and (2)
the raw, unadjusted ACE complies with
Requirement R1.
ii. Reliability Standard BAL–003–0
21. Requirement R3 of BAL–003–0
provides:
Each Balancing Authority shall operate its
Automatic Generation Control (AGC) on Tie
Line Frequency Bias, unless such operation
is adverse to system or Interconnection
Reliability.
NERC’s proposed interpretation of
BAL–003–0 Requirement R3 reads:
• Tie-Line Frequency Bias is one of
the three foundational control modes
available in a Balancing Authority’s
energy management system. (The other
two are flat-tie and flat-frequency.)
Many Balancing Authorities layer other
control objectives on top of their basic
control mode, such as automatic
inadvertent payback, [control
performance standard] optimization,
time control (in single [balancing
authority] interconnections).22
• As long as Tie-Line Frequency Bias
is the underlying control mode and
CPS1 is measured and reported on the
associated ACE equation,23 there is no
violation of BAL–003–0 Requirement 3:
ACE = (NIA—NIS)—10B (FA—FS)—IME
(NERC December 19, 2007 Filing, Ex. A–
3.)
20 See
NERC December 19, 2007 Filing at 8–9.
id.
22 The ‘‘flat frequency’’ control mode would
increase or decrease generation solely based on the
interconnection frequency. The ‘‘flat tie’’ mode
would increase or decrease generation within a
balancing authority area depending solely on that
balancing authority’s total interchange. The ‘‘tieline frequency bias’’ mode combines the flat
frequency and flat tie modes and adjusts generation
based on the balancing authority’s net interchange
and the interconnection frequency.
23 ‘‘CPS1’’ refers to Requirement R1 of BAL–001–
0.
21 See
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22. NERC explains that there is no
violation of BAL–003–0 Requirement
R3, provided that a balancing authority
uses the tie-line frequency bias mode as
the underlying control mode and the
control performance standard (CPS1),
per BAL–001–0 Requirement R1, is
measured and reported on the
associated ACE equation.
c. Commission Proposal
23. The Commission proposes to
approve the ERO’s formal interpretation
of Requirement R1 of BAL–001–0 and
Requirement R3 of BAL–003–0.
24. The ERO’s interpretation is
reasonable because it clarifies that raw
ACE must be used in NERC compliance
reporting. Reporting of raw ACE is
essential because a balancing authority
could exceed ACE limits in BAL–001–
0 if allowed to report an adjusted ACE
that adds or subtracts amounts from the
equation. This interpretation upholds
the reliability goal of BAL–001–0,
Requirement R1 to minimize the
frequency deviation of the
interconnection by constantly balancing
supply and demand. The interpretation
also clarifies that an entity may use
automatic generation control modes
layered on top of the tie-line frequency
bias mode as long as the raw ACE is
used in NERC compliance reporting.
This would permit WECC to implement
more stringent time error correction
procedures that rely on additional
control modes layered on top of the tieline frequency bias mode of automatic
generation control, provided they do not
report adjusted ACE which, if reported,
could produce ambiguous data used for
frequency bias calculations. The
interpretation maintains the goal of
BAL–003–0, Requirement R3, by
providing accurate historic data for
frequency bias calculations and by using
ACE calculations in automatic
generation control that will adjust the
generation, or demand-side resources
where available, in the balancing
authority area in a manner that
maintains the interconnection frequency
and does not result in an undue burden
for any balancing authority. The
Commission proposes to approve the
ERO’s interpretation based on the
understanding that a balancing
authority, in operating automatic
generation control, must use tie-line
frequency bias as its underlying control
mode unless to do so is adverse to
system or interconnection reliability.
25. In Order No. 693, the Commission
stated that, according to the available
data, the WECC automatic time error
correction procedure is more effective in
minimizing time error corrections and
inadvertent interchange than the
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Reliability Standard BAL–004–0.24
Therefore, the ERO’s interpretation
provides balancing authorities using the
WECC automatic time error correction
procedure with necessary clarification
and certainty in accordance with the
continent-wide Reliability Standards
BAL–001–0 and BAL–003–0.
Accordingly, this interpretation appears
to be just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
devices are included in the requirement.
On April 15, 2008, the ERO submitted
another interpretation of Requirement
R17 of BAL–005–0 and sought to
withdraw its request for Commission
approval of the interpretation of
Requirement R17 filed in this
proceeding on December 19, 2007.
Accordingly, the Commission does not
plan to act on the initial interpretation.
The Commission will act on the April
15 interpretation in a future proceeding.
2. BAL–005–0—Automatic Generation
Control
3. VAR–002–1—Generator Operation for
Maintaining Network Voltage Schedules
a. NERC’s Proposed Interpretation
26. Requirement R17 of Reliability
Standard BAL–005–0 (Automatic
Generation Control) is intended to
annually check and calibrate the time
error and frequency devices under the
control of the balancing authority that
feed data into automatic generation
control necessary to calculate ACE.
Requirement R17 mandates that the
balancing authority must adhere to an
annual calibration program for time
error and frequency devices. The
Requirement states that a balancing
authority must adhere to minimum
accuracies in terms of ranges specified
in Hertz, volts, amps, etc., for various
listed devices, such as digital frequency
transducers, voltage transducers, remote
terminal unit, potential transformers,
and current transformers.
27. On December 21, 2006, NERC
received a request to provide a formal
interpretation of Requirement R17
asking whether the only devices that
need to be annually calibrated under
this requirement are time error and
frequency devices, and whether the list
of device accuracy is simply the design
accuracy of the devices listed and that
those devices do not need to be
calibrated on an annual basis (except
the digital frequency transducer which
is covered as a ‘‘frequency device’’).
NERC provided an interpretation
clarifying that the intent of BAL–005–0,
Requirement R17 is to annually check
and calibrate a balancing authority’s
time error and frequency devices
located in the control room against the
common reference, and this requirement
does not apply to any such devices
located outside of the operations control
center.
a. NERC’s Proposed Interpretation
29. The stated purpose of Reliability
Standard VAR–002–1 is to ensure that
generators provide reactive and voltage
control necessary to ensure that voltage
levels, reactive flows, and reactive
resources are maintained within
applicable facility ratings to protect
equipment and the reliable operation of
the interconnection.25 Specifically,
Requirement R1 of Reliability Standard
VAR–002–1 provides:
b. Commission Proposal
28. On July 31, 2007, the ERO
received a second request for an
interpretation of Requirement R17 of
BAL–005–0, which asked the ERO to
further clarify the ambiguity of what
24 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 377.
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The Generator Operator shall operate each
generator connected to the interconnected
transmission system in the automatic voltage
control mode (automatic voltage regulator in
service and controlling voltage) unless the
Generator Operator has notified the
Transmission Operator.
Requirement R2 of this Reliability
Standard provides:
Unless exempted by the Transmission
Operator, each Generator Operator shall
maintain the generator voltage or Reactive
Power output (within applicable Facility
Ratings) as directed by the Transmission
Operator.
30. NERC states that it received a
request to provide a formal
interpretation of Requirements R1 and
R2 on January 24, 2007. The request for
interpretation first asked whether
automatic voltage regulator (AVR)
operation in the constant power factor
or constant Mvar modes complies with
Requirement R1.26 Secondly, the
25 Most bulk electric power is generated,
transported, and consumed in alternating current
(AC) networks. AC systems supply (or produce) and
consume (or absorb or lose) two kinds of power:
real power and reactive power. Real power
accomplishes useful work (e.g., runs motors and
lights lamps). Reactive power supports the voltages
that must be controlled for system reliability. FERC,
Principles for Efficient and Reliable Reactive Power
Supply and Consumption, Docket No. AD05–1–000,
at 17 (2005), available at https://www.ferc.gov/legal/
staff-reports.asp (Reactive Power Principles).
26 ‘‘Power factor’’ is a measure of real power in
relation to reactive power. A high power factor
means that relatively more useful power is being
taken or produced relative to the amount of reactive
power. A lower power factor means that there is
relatively more reactive power taken than real
power. ‘‘Mvar’’ is a measure of reactive power equal
to one million reactive volt-amperes. Reactive
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request asked the ERO whether
Requirement R2 gives the transmission
operator the option of directing the
generation owner to operate the AVR in
the constant power factor or constant
Mvar modes rather than the constant
voltage mode.
31. The AVR is designed to
automatically adjust generator voltage
and/or power-factor to ensure proper
grid operational characteristics.
Constant voltage mode is the normal
mode of operation for AVR and
maintains the output voltage at a
constant level. The constant power
factor mode is a setting of the AVR that
causes the generator to output a set ratio
of real power to reactive power, whereas
the constant Mvar mode is a setting that
causes the generator to maintain an
output with a constant amount of
reactive power.
32. NERC’s formal interpretation
provides that AVR operation in the
constant power factor or constant Mvar
modes does not comply with
Requirement R1.27 The interpretation
rests on the assumption that the
generator has the physical equipment
that will allow such operation and that
the transmission operator has not
directed the generator to run in a mode
other than constant voltage. The
interpretation also provides that
Requirement R2 does give the
transmission operator the option of
directing the generation operator to
operate the AVR in the constant power
factor or constant Mvar modes rather
than the constant voltage mode.28
33. In its transmittal letter, NERC
explains that, with respect to the
interpretation of Requirement R1,
Reliability Standard VAR–002–1 clearly
states that the generator operator shall
Power Principles, supra note 16, at 7, 12, 41, 119,
120.
27 NERC’s proposed interpretation of VAR–002–1
Requirement R1 reads:
1. First, does AVR operation in the constant PF
or constant Mvar modes comply with R1?
Interpretation: No, only operation in constant
voltage mode meets this requirement. This answer
is predicated on the assumption that the generator
has the physical equipment that will allow such
operation and that the Transmission Operator has
not directed the generator to run in a mode other
than constant voltage.
2. Second, does R2 give the Transmission
Operator the option of directing the Generation
Owner (sic) to operate the AVR in the constant Pf
or constant Mvar modes rather than the constant
voltage mode?
Interpretation: Yes, if the Transmission Operator
specifically directs a Generator Operator to operate
the AVR in a mode other than constant voltage
mode, then that directed mode of AVR operation is
allowed.
NERC December 19, 2007 Filing, Ex. C–2.
28 We note, as does NERC, the requesting party’s
apparent error when it references ‘‘Generation
Owner’’ instead of the generator operator.
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operate with the automatic voltage
regulator in service and controlling
voltage. The interpretation specifies that
this can only be accomplished by using
the constant voltage control mode, and
using the constant power factor or
constant Mvar control is not a true
method to control voltage even though
it may have some effect on voltage. In
addition, NERC explains that
Requirement R2 provides for an
exemption to this baseline mode of
operation to allow the transmission
operator the ability to direct the
generator operator to use another mode
of operation.
b. Commission Proposal
34. The Commission proposes to
approve the ERO’s interpretation of
Requirement R1 and Requirement R2 of
VAR–002–1. These interpretations
appear to be reasonable and do not
appear to change or conflict with the
stated responsibilities set forth in the
two requirements as approved in Order
No. 693. Therefore, this interpretation
appears to be just, reasonable, not
unduly discriminatory or preferential,
and in the public interest.
B. NERC’s December 21, 2007 Filing:
Modification of TLR Procedure
1. NERC’s Proposed Reliability Standard
35. As mentioned above, on December
21, 2007, NERC submitted for
Commission approval proposed
Reliability Standard IRO–006–4, to
modify the current Commissionapproved Reliability Standard, IRO–
006–3.
a. Background
36. In Order No. 693, the Commission
approved the current version of this
Reliability Standard, IRO–006–3. This
Reliability Standard ensures that a
reliability coordinator has a coordinated
transmission service curtailment and
reconfiguration method that can be used
along with other alternatives, such as
redispatch or demand-side management,
to avoid transmission limit violations
when the transmission system is
congested. Reliability Standard IRO–
006–3 establishes a detailed TLR
process for use in the Eastern
Interconnection to alleviate loadings on
the system by curtailing or changing
transactions based on their priorities
and the severity of the transmission
congestion.29
29 The equivalent interconnection-wide TLR
procedures for use in WECC and Electric Reliability
Council of Texas (ERCOT) are known as ‘‘WSCC
Unscheduled Flow Mitigation Plan’’ and section 7
of the ‘‘ERCOT Protocols,’’ respectively.
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37. In addition to approving IRO–
006–3, the Commission in Order No.
693 directed the ERO to modify the
Reliability Standard to: (1) Include a
clear warning that the TLR procedure is
an inappropriate and ineffective tool to
mitigate actual IROL violations; 30 and
(2) identify in a requirement the
available alternatives to mitigate an
IROL violation other than use of the
TLR procedure.31 These directives
reflect an observation from the U.S.Canada Power System Outage Task
Force in the August 14, 2003 Blackout
Report, which identified that the TLR
procedure is often too slow for use in
situations where the system has already
violated IROLs.32 In setting forth these
directives, the Commission stated that it
did not have concerns with the use of
the TLR procedure to avoid potential
IROL violations.33
b. NERC Filing
38. According to NERC, the
modifications embodied in proposed
Reliability Standard IRO–006–4
represent the first phase of a three-phase
project intended to improve the overall
quality of IRO–006. In the first phase,
NERC extracted the business practices
and commercial requirements from the
existing IRO–006–3 Reliability Standard
and proposes to transfer them into the
NAESB business practices.34 NERC’s
filing does not seek to modify the
remaining reliability requirements of
IRO–006, with the exception that the
Reliability Standard has been clarified
to include the Commission’s Order No.
693 directive that using the TLR
procedure is not effective to mitigate an
actual IROL violation.
39. According to NERC, the second
phase of the IRO–006 project will
address possible changes to the regional
differences associated with the
congestion management process used by
the PJM Interconnection, L.L.C., the
30 An IROL is a system operating limit that, if
violated, could lead to instability, uncontrolled
separation, or cascading outages that adversely
impact the reliability of the Bulk-Power System.
31 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 964.
32 U.S.-Canada Power System Outage Task Force,
Final Report on the August 14, 2003 Blackout in the
United States and Canada: Causes and
Recommendations, at 163 (April 2004) (Final
Blackout Report), available at https://
reports.energy.gov/.
33 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 962.
34 The NAESB business practices and commercial
requirements have been included in Version 001 of
the NAESB Wholesale Electric Quadrant standards
and filed with the Commission on December 21,
2007. The NAESB filing is the subject of a separate
rulemaking in Docket No. RM05–5–005. A notice of
proposed rulemaking addressing the NAESB filing
is being issued concurrently with the immediate
NOPR.
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Midwest Independent System Operator,
Inc., and the Southwest Power Pool, Inc.
In the third phase, NERC plans to
completely redraft the Reliability
Standard to incorporate further
enhancements and changes beyond the
separation of reliability and business
practices.
40. In its filing, NERC explains that
the filed Reliability Standard IRO–006–
4 meets the guidance outlined in Order
No. 672, used to determine whether a
Reliability Standard is just, reasonable,
not unduly discriminatory or
preferential, and in the public interest.35
In addition, IRO–006–4 includes
violation risk factors and violation
severity levels that were not provided
with IRO–006–3.
41. NERC’s proposed IRO–006–4
Reliability Standard consists of five
requirements. Proposed Requirement R1
obligates a reliability coordinator
experiencing a potential or actual
system operating limit (SOL) or IROL
violation within its reliability
coordinator area to select one or more
procedures to provide transmission
loading relief. The requirement also
identifies the regional TLR procedures
in WECC and Electric Reliability
Council of Texas (ERCOT). The
requirement includes a warning that the
TLR procedure alone is an inappropriate
and ineffective tool to mitigate an IROL
violation and provides alternatives.
42. Proposed Requirement 2 mandates
that the reliability coordinator only use
a congestion management procedure to
which the transmission operator
experiencing the SOL or IROL is a party.
NERC explains that Requirement R1 and
Requirement R2 are assigned a violation
risk factor of ‘‘lower’’ because they are
administrative in nature and are merely
intended to describe how a reliability
coordinator may choose a procedure to
implement TLR.36 According to NERC,
these Requirements are not intended to
duplicate the requirements of other
Reliability Standards that ensure the
system is operated within SOL and
IROL limits such as Requirements R3
and R5 of IRO–005–1, which have
‘‘high’’ violation risk factors.37 NERC
adds that, provided the reliability
coordinator is adhering to the
requirements in IRO–005–1, there is no
significant risk to the reliability of the
Bulk-Power System as a result of a
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35 Order
No. 672, FERC Stats. & Regs. ¶ 31,204 at
P 326.
36 Exhibit A (Reliability Standard Proposed for
Approval) of NERC’s December 21, 2007 filing,
however, contains the violation risk factor of
‘‘medium’’ for these requirements, but NERC
indicates elsewhere that it is ‘‘lower.’’ NERC
December 21, 2007 Filing at 12–13.
37 Id. at 13.
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violation of Requirement R1 of IRO–
006–4.
43. Proposed Requirement R3
establishes that a reliability coordinator
with a TLR obligation from an
interconnection-wide procedure follow
the curtailments as directed by the
interconnection-wide procedure. The
requirement includes that a reliability
coordinator desiring to use a local
procedure as a substitute for
curtailments as directed by the
interconnection-wide procedure shall
obtain prior approval of the local
procedure from the ERO. NERC states
that a violation risk factor of ‘‘lower’’ for
Requirement R3 is appropriate because
it is intended that an entity could
choose alternate actions for relief other
than curtailments specified by this
requirement to ensure reliability.
44. Proposed Requirement R4
mandates that each reliability
coordinator comply with
interconnection-wide procedures, once
they are implemented, to curtail
transactions that cross interconnection
boundaries.
45. Proposed Requirement R5 directs
balancing authorities and reliability
coordinators to comply with applicable
interchange-related Reliability
Standards during the implementation of
TLR procedures. NERC proposes
‘‘medium’’ violation risk factors for
Requirement R4 and Requirement R5
explaining that, while failure to comply
with these requirements could lead the
system to an unbalanced scenario, such
failure would not pose a ‘‘high’’ risk to
the system.
46. Finally, NERC explains that four
violation severity levels have been
assigned to Requirement R1 of IRO–
006–4 based on the number of violations
of interconnection-wide procedure
requirements, and these levels are
intended to base violation severity on
the degree of deviation from the
requirements by the violator. NERC
states that there is a single violation
severity level for each of the remaining
requirements (i.e., R2, R3, R4, and R5),
because an entity simply either ‘‘passes’’
or ‘‘fails’’ each of these requirements.
i. Requirements
48. NERC’s proposal implements the
Commission’s directives (1) to include a
clear warning that the TLR procedure is
an inappropriate and ineffective tool to
mitigate actual IROL violations; and (2)
to identify in a requirement the
available alternatives to mitigate an
IROL violation. Specifically,
Requirement R1.1 of IRO–006–4 states,
‘‘The TLR procedure alone is an
inappropriate and ineffective tool to
mitigate an IROL violation due to the
time required to implement the
procedure. Other acceptable and more
effective procedures to mitigate actual
IROL violations include:
reconfiguration, redispatch, or load
shedding.’’ The Commission proposes to
approve this standard based on the
interpretation that using a TLR
procedure alone to mitigate an IROL
violation is a violation of the Reliability
Standard.
49. Further, the proposed division
between NERC and NAESB business
practices seems to be reasonable and
appears to pose no harm to reliability.
The Commission has long supported the
coordination of business practices and
Reliability Standards. As early as May
2002, the Commission urged the
industry expeditiously to establish the
procedures for ensuring coordination
between NAESB and NERC.38 The
Commission asks for comments on
whether any compromise in the
reliability of the Bulk-Power System
may result from the removal and
transfer to NAESB of the businessrelated issues formerly contained in
Reliability Standard IRO–006.
c. Commission Proposal
38 Electricity Market Design and Structure, 99
FERC ¶ 61,171, at P 22 (2002); see also Standards
for Business Practices and Communication
Protocols for Public Utilities, Order No. 676, FERC
Stats. & Regs. ¶ 31,216, at P 6 (2006).
39 The definitions of ‘‘high,’’ ‘‘medium,’’ and
‘‘lower’’ are provided in North American Electric
Reliability Corp., 119 FERC ¶ 61,145, at P 9
(Violation Risk Factor Order), order on reh’g, 120
FERC ¶ 61,145 (2007) (Violation Risk Factor
Rehearing).
40 The guidelines are: (1) Consistency with the
conclusions of the Blackout Report; (2) consistency
47. The Commission proposes to
approve Reliability Standard IRO–006–
4 as just, reasonable, not unduly
discriminatory or preferential, and in
the public interest. In addition, the
Commission proposes to direct the ERO
to modify certain violation risk factors
that correspond to the Requirements of
the Reliability Standard.
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ii. Violation Risk Factors
50. Violation risk factors delineate the
relative risk to the Bulk-Power System
associated with the violation of each
Requirement and are used by NERC and
the Regional Entities to determine
financial penalties for violating a
Reliability Standard. NERC assigns a
lower, medium, or high violation risk
factor for each mandatory Reliability
Standard Requirement.39 The
Commission also established guidelines
for evaluating the validity of each
Violation Risk Factor assignment.40
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51. The Commission is concerned
regarding the violation risk factors
submitted with IRO–006–4. While the
approved violation risk factors for IRO–
006–0 Requirement R2 through
Requirement R6 are all ‘‘high,’’ 41 NERC
proposes to revise violation risk factors
for similarly-worded Requirements R1
through R5 of IRO–006–4 to ‘‘lower’’ or
‘‘medium.’’ Sub-requirements R1.1
through R1.3 are explanatory text;
therefore, we propose that a violation
risk factor need not be assigned to them.
For consistency with the Commission’s
five guidelines discussed above, the
Commission proposes to direct the ERO
to modify the violation risk factors
assigned to Requirements R1 through R4
to ‘‘high.’’ We discuss our concerns
below.
52. The Commission disagrees with
the ERO that Requirement R1 is
administrative in nature in describing
how a reliability coordinator may
choose a procedure to provide
transmission loading relief.
Requirement R1, as well as Requirement
R2 through R4, goes beyond merely
providing procedural choices for
transmission loading relief, as the ERO
asserts. Requirements R1 through R4
require that a reliability coordinator
choose and follow the appropriate
procedure to provide relief. If the
reliability coordinator chooses an
unapproved and ineffective procedure
for relief or fails to choose a procedure
entirely, potential or actual IROLs will
not be mitigated as intended by the
reliability coordinator. Failure to
implement the proper TLR procedure
likely would lead to IROL violations,
which could lead to cascading outages.
The implementation of the TLR
procedure shares a similar reliability
goal as other Reliability Standard
requirements that keep the transmission
system within IROLs, thus presenting a
similar reliability risk and violation risk
factor, if violated.
53. With respect to IRO–006–4,
Requirement R1, the ERO states that,
provided the reliability coordinator is
adhering to the requirements in IRO–
005–1, there is no significant risk to the
reliability of the Bulk-Power System as
within a Reliability Standard; (3) consistency
among Reliability Standards; (4) consistency with
NERC’s definition of the violation risk factor level;
and (5) treatment of requirements that co-mingle
more than one obligation. The Commission also
explained that this list was not necessarily allinclusive and that it retains the flexibility to
consider additional guidelines in the future. A
detailed explanation is provided in Violation Risk
Factor Rehearing, 120 FERC ¶ 61,145 at P 8–13.
41 The violation risk factors for these
requirements were submitted by NERC on February
23, 2007, and they were approved in the Violation
Risk Factor Order.
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a result of a violation of Requirement R1
of IRO–006–4. We disagree. The
violation risk factor of a requirement
represents the risk a violation of that
requirement presents to the reliability of
the Bulk-Power System. Violation risk
factors should not be assigned
differently for requirements in separate
Reliability Standards based on
compliance with another standard. Two
requirements either achieve separate
reliability goals and, therefore, violation
of them represents independent risks, or
two requirements share the same
reliability goal. As stated in Guideline 3
of the Violation Risk Factor Order,42 the
Commission expects that the assignment
of violation risk factors corresponding to
requirements that address similar
reliability goals in different Reliability
Standards would be treated comparably.
54. Furthermore, a ‘‘high’’ violation
risk factor assignment for Requirements
R1 through R4 is consistent with
findings of the Final Blackout Report.
The report highlights that, generally,
‘‘TLRs are intended as a tool to prevent
the system from being operated in an
unreliable state and are not applicable
in real-time emergency situations.’’ 43
As a result, Recommendation No. 31 in
the Final Blackout Report was
developed to clarify that the TLR
procedure should not be used in
situations involving an actual violation
of an operating security limit.
55. A medium or lower violation risk
factor has been approved for the
Reliability Standards in the Interchange
Scheduling and Coordination (INT)
family of Reliability Standards.
Requirement R5 of IRO–006–4
complements the INT group of
Reliability Standards and, thus, appears
to be appropriately assigned a medium
violation risk factor.
56. The added ‘‘Measures’’ and other
revisions embedded in proposed
Reliability Standard IRO–006–4 do not
appear to substantively change the
earlier, Commission-approved version
(i.e., IRO–006–3).
57. In summary, proposed Reliability
Standard IRO–006–4 appears to be just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest. Accordingly, the Commission
proposes to approve Reliability
Standard IRO–006–4 as mandatory and
enforceable. In addition, the
Commission proposes to direct the ERO
to modify the violation risk factors, as
described above.44
42 119
FERC ¶ 61,145 at P 25.
Blackout Report at 62.
44 Although ‘‘time horizons,’’ which relate to the
immediacy of the risk posed by a violation of a
requirement, are included in this Reliability
43 Final
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C. NERC’s December 26, 2007 Filing:
Modification to Five ‘‘Interchange and
Scheduling’’ Reliability Standards
58. NERC submitted for Commission
approval proposed modifications to five
Reliability Standards from the INT
group of Reliability Standards.
1. INT–001–3—Interchange Information
and INT–004–2—Dynamic Interchange
Transaction Modifications
a. Background
59. The Interchange Scheduling and
Coordination or ‘‘INT’’ group of
Reliability Standards address
interchange transactions, which occur
when electricity is transmitted from a
seller to a buyer across the power grid.
Reliability Standard INT–001 applies to
purchasing-selling entities and
balancing authorities. The stated
purpose of this Reliability Standard is to
‘‘ensure that Interchange Information is
submitted to the NERC-identified
reliability analysis service.’’ Reliability
Standard INT–004 is intended to
‘‘ensure Dynamic Transfers are
adequately tagged to be able to
determine their reliability impacts.’’
60. In Order No. 693, the Commission
approved the currently applicable
version of these Reliability Standards,
INT–001–2 and INT–004–1.45 Further,
when NERC initially submitted these
two Reliability Standards for
Commission approval, NERC also asked
the Commission to approve a ‘‘regional
difference’’ that would exempt WECC
from requirements related to tagging
dynamic schedules and inadvertent
payback provisions of INT–001–2 and
INT–004–1. The Commission, in Order
No. 693, stated that it did not have
sufficient information to address the
ERO’s proposed regional difference and
directed the ERO to submit a filing
either withdrawing the regional
difference or providing additional
information needed for the Commission
to make a determination on the matter.46
The effect of NERC’s December 26, 2007
filing is to withdraw the regional
difference with respect to WECC.
Standard, we do not propose to rule on the time
horizons in this rulemaking. On March 3, 2008, in
Docket No. RR08–4–000, NERC submitted proposed
violation severity levels corresponding to the
Requirements of 83 Commission-approved
Reliability Standards. The Commission will address
the violation severity levels regarding IRO–006–4 in
that proceeding.
45 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 821, 843. In addition, the Commission directed
that the ERO develop modifications to INT–001–2
and INT–004–1 that address the Commission’s
concerns.
46 Id. P 825.
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b. NERC’s Proposed Modifications
61. In May 2007, WECC requested that
NERC rescind the regional difference,
referred to as e-tagging waivers,47 for
Reliability Standards INT–001–2 and
INT–004–1. According to NERC, WECC
has developed business practices for
dynamic schedules and has taken the
steps needed to comply with the etagging of inadvertent payback
interchange schedules. Thus, WECC
determined that it no longer needs the
e-tagging waivers.
62. NERC processed WECC’s request
through NERC’s Reliability Standard
Development Procedure, using its
urgent action process.48 NERC states
that, by rescinding the e-tagging
waivers, NERC maintains uniformity
and makes no structural changes to the
requirements in the current
Commission-approved version of the
Reliability Standards.
c. Commission Proposal
63. NERC states that simply
rescinding these waivers will not result
in structural changes to the
requirements in the current
Commission-approved version of the
Reliability Standards and will maintain
uniformity. Further, we note that WECC
agrees that it no longer needs to retain
the waivers.49 Accordingly, the
Commission proposes to approve INT–
001–3 and INT–004–2.
2. INT–005–2—Interchange Authority
Distributes Arranged Interchange
a. INT–006–2—Response to Interchange
Authority, and INT–008–2—Interchange
Authority Distributes Status
rwilkins on PROD1PC63 with PROPOSALS
i. Background
64. In Order No. 693, the Commission
approved the entire group of INT
Reliability Standards.50
65. Reliability Standard INT–005–1
applies to the interchange authority.
The stated purpose of proposed
Reliability Standard INT–005–1 is to
‘‘ensure that the implementation of
Interchange between Source and Sink
Balancing Authorities is distributed by
47 An E-tag represents a transaction on the North
American bulk electricity market scheduled to flow
within, between, or across electric utility company
territories electronically. This is done so that
transmission system operators can ascertain all of
the transactions impacting their local system and
take any corrective actions to alleviate situations
that could put the power grid at risk of damage or
collapse.
48 NERC December 26, 2007 Filing at 5–6.
49 Id.
50 In addition, the Commission directed the ERO
to develop modifications to INT–006–1. The
Commission-directed modifications are not
included in the immediate filing; rather, the ERO
will develop such modifications pursuant to its
Reliability Standards Development Plan 2008–2010.
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an Interchange Authority such that
Interchange information is available for
reliability assessments.’’
66. Reliability Standard INT–006–1
applies to balancing authorities and
transmission service providers. The
stated purpose of the Reliability
Standard is to ‘‘ensure that each
Arranged Interchange is checked for
reliability before it is implemented.’’
67. Reliability Standard INT–008–1
applies to the interchange authority.
The stated purpose of the Reliability
Standard is to ‘‘ensure that the
implementation of Interchange between
Source and Sink Balancing Authorities
is coordinated by an Interchange
Authority.’’ This means that it is the
interchange authorities’ responsibility to
oversee and coordinate the interchange
from one balancing authority to another.
ii. NERC’s Proposed Modifications
68. In its December 26, 2007 filing,
NERC addresses a specific reliability
need identified by WECC in its urgent
action request.
69. Requirement R1.4 of INT–007–1
requires that each balancing authority
and transmission service provider
provide confirmation to the interchange
authority that it has approved the
transactions for implementation. NERC
states that for WECC the timeframe
allotted for this assessment is five
minutes in the original version of the
Commission-approved Reliability
Standards.
70. NERC explains that the proposed
Reliability Standards for INT–005–2,
INT–006–2, and INT–008–2 would
increase the timeframe for applicable
WECC entities to perform the reliability
assessment from five to ten minutes for
next hour interchange tags submitted in
the first thirty minutes of the hour
before. According to NERC, this
modification is needed because the
majority of next-hour tags in WECC are
submitted between xx:00 and xx:30.
NERC explains that the existing five
minute assessment window makes it
nearly impossible for balancing
authorities and transmission service
providers to review each tag before the
five minute assessment time expires.
NERC maintains that, when the time
expires, the tags are denied and must be
resubmitted.
71. NERC states that WECC has
experienced numerous instances of
transactions being denied because one
or more applicable reliability entities
did not actively approve the tag. In
NERC’s view, the current structure
causes frustration and inefficiencies for
entities involved in this process, as
requestors are required to re-create tags
that are denied. Further, NERC states
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Fmt 4702
Sfmt 4702
that there is no reliability basis for a five
minute assessment period for tags
submitted at least thirty minutes ahead
of the ramp-in period.
72. NERC notes that, prior to January
1, 2007, when the new INT group of
Reliability Standards was implemented,
WECC had a ten-minute reliability
assessment period for next-hour tags.
NERC states that the urgent action
request restores assessment times back
to ten minutes.
73. Apart from the extension of the
reliability assessment period from five
to ten minutes for WECC entities, NERC
avers that it makes no substantive
changes to the requirements in the
current Commission-approved version
of the Reliability Standards.
b. Commission Proposal
74. The Commission proposes to
approve INT–005–2, INT–006–2, and
INT–008–2. The only change proposed
to these Reliability Standards is the
reliability assessment period for
WECC.51
III. Information Collection Statement
75. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain reporting and
recordkeeping (collections of
information) imposed by an agency.52
The information contained here is also
subject to review under section 3507(d)
of the Paperwork Reduction Act of
1995.53 As stated above, the
Commission previously approved, in
Order No. 693, each of the Reliability
Standards that are the subject of the
current rulemaking. The proposed
modifications to the Reliability
Standards are minor and the proffered
interpretations relate to existing
Reliability Standards; therefore, they do
not add to or increase entities’ current
reporting burden. Thus, the current
proposal would not materially affect the
burden estimates relating to the
currently effective version of the
Reliability Standards presented in Order
No. 693.54
76. For example, the proposed
interpretation of BAL–001–0 and BAL–
003–0 does not modify or otherwise
affect the collection of information
already in place. With respect to BAL–
001–0, the interpretation merely
clarifies the rule that is already in place,
that the time error correction
51 The Commission notes that NERC’s compliance
with Order No. 693, with respect to Reliability
Standard INT–006–1, is ongoing. See Order No.
693, FERC Stats. & Regs. ¶ 31,242 at P 866.
52 5 CFR 1320.11.
53 44 U.S.C. 3507(d).
54 See Order No. 693, FERC Stats. & Regs. ¶
31,242 at P 1905–07.
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rwilkins on PROD1PC63 with PROPOSALS
component of the WECC automatic time
error correction calculation of ACE is
not to be used in NERC performance
reporting. With respect to BAL–003–0,
the interpretation clarifies that layering
additional control modes on top of the
tie-line frequency bias mode of
automatic generation control is
acceptable. Layering additional control
modes on top of the tie-line frequency
bias mode of automatic generation
control does not change the information
that a balancing authority reports
because the same logs, data, or
measurements would be maintained.
77. The proposed removal of business
practice-related requirements from
Reliability Standard IRO–006–4 will
likely decrease, not increase, the
reporting burden associated with the
current, Commission-approved version
of the Reliability Standard. Nor would
the proposed revision to certain
Reliability Standards to allow WECC an
additional five minutes to perform a
reliability assessment regarding
interchange transactions impact the
reporting burden. Further, the proposal
to rescind the requested waivers from
the e-tagging obligation under
Reliability Standards INT–001–3 and
INT–004–2 for entities in the WECC
region does not change the reporting
burden because NERC was never
granted its requested waiver to exempt
WECC from requirements related to
tagging dynamic schedules and
inadvertent payback.55 In addition,
WECC already has business practice
standards in place that fulfill the
dynamic transfer e-tagging reporting and
record keeping obligations set forth in
these Reliability Standards.56
78. Thus, the proposed modifications
to the current Reliability Standards and
interpretations effected by this proposed
rule will not increase the reporting
burden nor impose any additional
information collection requirements.
79. The Commission does not foresee
any additional impact on the reporting
burden for small businesses, because the
proposed modifications are minor and
the interpretations do not increase the
existing burden. However, we will
submit this proposed rule to OMB for
informational purposes.
Title: Modification of Interchange and
Transmission Loading Relief Reliability
Standards; and Electric Reliability
Organization Interpretation of Specific
55 See Order No. 693, FERC Stats. & Regs. ¶
31,242 at P 822, 825 (directing ERO either to
withdraw regional difference or provide additional
information).
56 See Business Practice Standard INT–BPS–008–
1 (Dynamic Transfer E-Tagging Requirements),
available at https://www.wecc.biz.
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Requirements of Four Reliability
Standards.
Action: Proposed Collection.
OMB Control No.: 1902–0244.
Respondents: Businesses or other forprofit institutions; not-for-profit
institutions.
Frequency of Responses: On
Occasion.
Necessity of the Information: This
proposed rule would approve six
modified Reliability Standards, five of
which pertain to interchange scheduling
and coordination and one that pertains
to transmission loading relief
procedures. In addition, this proposed
rule would approve interpretations of
five specific requirements of
Commission-approved Reliability
Standards. The proposed rule would
find the Reliability Standards and
interpretations just, reasonable, not
unduly discriminatory or preferential,
and in the public interest.
Internal Review: The Commission has
reviewed the proposed Reliability
Standards and interpretations and made
a determination that these requirements
are necessary to implement section 215
of the FPA. These requirements conform
to the Commission’s plan for
interchange scheduling and
coordination as well as transmission
loading relief procedures within the
energy industry.
80. Interested persons may obtain
information on the reporting
requirements by contacting the
following: Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426 [Attention:
Michael Miller, Office of the Executive
Director, Phone: (202) 502–8415, fax:
(202) 273–0873, e-mail:
michael.miller@ferc.gov].
81. For submitting comments
concerning the collection(s) of
information and the associated burden
estimate(s), please send your comments
to the contact listed above and to the
Office of Information and Regulatory
Affairs, Office of Information and
Regulatory Affairs, Washington, DC
20503 [Attention: Desk Officer for the
Federal Energy Regulatory Commission,
phone (202) 395–4650, fax: (202) 395–
7285, e-mail:
oira_submission@omb.eop.gov].
IV. Environmental Analysis
82. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.57 The Commission has
57 Regulations Implementing the National
Environmental Policy Act, Order No. 486, FERC
Stats. & Regs. ¶ 30,783 (1987).
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Fmt 4702
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22865
categorically excluded certain actions
from this requirement as not having a
significant effect on the human
environment. Included in the exclusion
are rules that are clarifying, corrective,
or procedural or that do not
substantially change the effect of the
regulations being amended.58 The
actions proposed herein fall within this
categorical exclusion in the
Commission’s regulations.
V. Regulatory Flexibility Act Analysis
83. The Regulatory Flexibility Act of
1980 (RFA) 59 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. The RFA mandates
consideration of regulatory alternatives
that accomplish the stated objectives of
a proposed rule and that minimize any
significant economic impact on a
substantial number of small entities.
The Small Business Administration’s
Office of Size Standards develops the
numerical definition of a small
business. (See 13 CFR 121.201.) For
electric utilities, a firm is small if,
including its affiliates, it is primarily
engaged in the transmission, generation
and/or distribution of electric energy for
sale and its total electric output for the
preceding twelve months did not exceed
four million megawatt hours. The RFA
is not implicated by this proposed rule
because the minor modifications and
interpretations discussed herein will not
have a significant economic impact on
a substantial number of small entities.
VI. Comment Procedures
84. The Commission invites interested
persons to submit comments on the
matters and issues proposed in this
notice to be adopted, including any
related matters or alternative proposals
that commenters may wish to discuss.
Comments are due 45 days from
publication in the Federal Register.
Comments must refer to Docket No.
RM08–7–000, and must include the
commenter’s name, the organization
they represent, if applicable, and their
address in their comments.
85. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
Web site at https://www.ferc.gov. The
Commission accepts most standard
word processing formats. Documents
created electronically using word
processing software should be filed in
native applications or print-to-PDF
format and not in a scanned format.
58 18
59 5
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CFR 380.4(a)(2)(ii).
U.S.C. 601–12.
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Commenters filing electronically do not
need to make a paper filing.
86. Commenters that are not able to
file comments electronically must send
an original and 14 copies of their
comments to: Federal Energy Regulatory
Commission, Secretary of the
Commission, 888 First Street, NE.,
Washington, DC, 20426.
87. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters.
Commissioners Wellinghoff and Kelly
concurring jointly with a separate statement.
Kimberly D. Bose,
Secretary.
Department of Energy
Federal Energy Regulatory Commission
[Docket No. RM08–7–000]
Modification of Interchange and
Transmission Loading Relief Reliability
Standards; and Electric Reliability
Organization Interpretation of Specific
Requirements of Four Reliability
Standards
Issued April 21, 2008.
WELLINGHOFF and KELLY,
Commissioners, concurring:
Today, the Commission issues a
VII. Document Availability
Notice of Proposed Rulemaking (NOPR)
proposing to approve, among other
88. In addition to publishing the full
matters, modified Reliability Standard
text of this document in the Federal
IRO–006–4 pertaining to transmission
Register, the Commission provides all
loading relief (TLR) procedures that can
interested persons an opportunity to
be used to prevent or manage potential
view and/or print the contents of this
or actual transmission line limit
document via the Internet through
FERC’s Home Page (https://www.ferc.gov) violations when the transmission
system is congested. An earlier version
and in FERC’s Public Reference Room
of this Reliability Standard, IRO–006–3,
during normal business hours (8:30 a.m.
was approved in Order No. 693 subject
to 5 p.m. Eastern time) at 888 First
to modification.60 This Reliability
Street, NE., Room 2A, Washington DC
Standard establishes a detailed TLR
20426.
process for use in the Eastern
89. From FERC’s Home Page on the
Interconnection to alleviate loadings on
Internet, this information is available on the system by curtailing or changing
transmission transactions based on their
eLibrary. The full text of this document
priorities and the severity of the
is available on eLibrary in PDF and
transmission congestion. However, the
Microsoft Word format for viewing,
printing, and/or downloading. To access Commission directed the ERO 61 to
modify the Reliability Standard to: (1)
this document in eLibrary, type the
Include a clear warning that the TLR
docket number excluding the last three
procedure is an inappropriate and
digits of this document in the docket
ineffective tool to mitigate actual IROL
number field.
violations, and (2) identify in a
90. User assistance is available for
requirement the available alternatives to
eLibrary and the FERC’s website during mitigate an IROL violation other than
normal business hours from FERC
use of the TLR procedure.62
Online Support at (202) 502–6652 (toll
Reliability Standard IRO–006–4
free at 1–866–208–3676) or e-mail at
contains the required warning that the
ferconlinesupport@ferc.gov, or the
TLR procedure alone is an inappropriate
Public Reference Room at (202) 502–
and ineffective tool to mitigate an IROL
8371, TTY (202) 502–8659. E-mail the
violation due to the time required to
implement the procedure. It furthers
Public Reference Room at
states that other acceptable and more
public.referenceroom@ferc.gov.
effective procedures to mitigate actual
List of Subjects in 18 CFR Part 40
IROL violations include reconfiguration,
redispatch, or load shedding. Load
Electric power, Electric utilities,
Reporting and recordkeeping
60 Mandatory Reliability Standards for the Bulkrequirements.
Power System, Order No. 693, FERC Stats. & Regs.
rwilkins on PROD1PC63 with PROPOSALS
By direction of the Commission.
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17:54 Apr 25, 2008
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¶ 31,242, order on reh’g, Order No. 693–A, 120
FERC ¶ 61,053 at P 964 (2007).
61 The Commission designated the North
American Electric Reliability Corp. (NERC) as the
nation’s electric reliability organization (ERO) in
2006.
62 An IROL is a system operating limit that, if
violated, could lead to instability, uncontrolled
separation, or cascading outages that adversely
impact the reliability of the Bulk-Power System.
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Sfmt 4702
shedding reduces customers’ demand
involuntarily.
We write separately to note that
demand-side management (DSM), or
voluntary demand reduction, is not
explicitly included in IRO–006–4
among the acceptable alternatives to
TLR procedures. Nothing in the
proposed standard precludes the use of
DSM that can respond quickly to
emergencies as an alternative to TLR
procedures. Nor is there any indication
that NERC intended this to be an
exhaustive list of alternatives. We
understand that DSM technologies used
currently to provide operating reserve
(for instance, in the operating reserve
markets of ISO and RTOs) would, in
fact, be deployed as quick response to
IROL violations and in most cases
would be deployed prior to involuntary
load shedding. Indeed, voluntary
demand response could be a better
alternative than involuntary load
shedding, which, as we indicated above,
IRO–006–4 identifies as an acceptable
alternative to TLR procedures.
In Order No. 693, the Commission
directed modifications to Reliability
Standards BAL–002–0 (Disturbance
Control Performance), EOP–002–2
(Capacity and Energy Emergencies),
VAR–001–1 (Voltage and Reactive
Control), and the sensitivity studies of
the TPL (Transmission Planning)
standards to explicitly provide that
DSM may be used as a resource to meet
the requirements of those Standards.
The Commission clarified that DSM
should be treated on a comparable basis
and must meet similar technical
requirements as other resources
providing this service.63 The
Commission also addressed why
explicit identification in the Reliability
Standard is necessary, stating:
The Commission disagrees with APPA that
we should not explicitly identify any type of
capacity as a resource for meeting reserve
contingencies. The Commission believes that
listing the types of resources that can be used
to meet contingency reserves makes the
Reliability Standard clearer, provides users,
owners and operators of the Bulk-Power
System a set of options to meet contingency
reserves, and treats DSM on a comparable
basis with other resources.
Many commenters argue that the
Commission’s proposed directive that would
explicitly allow DSM as a resource for
contingency reserves is too prescriptive.
Concerns in this area generally fall into three
categories: (1) That DSM should be treated on
a comparable basis as other resources; (2) that
the Reliability Standard should be based on
meeting an objective as opposed to stating
how that objective is met and (3) that DSM
63 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 335.
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Federal Register / Vol. 73, No. 82 / Monday, April 28, 2008 / Proposed Rules
may not be technically capable of providing
this service.
With regard to the first concern, the
Commission clarifies that the purpose of the
proposed directive is to ensure comparable
treatment of DSM with conventional
generation or any other technology and to
allow DSM to be considered as a resource for
contingency reserves on this basis without
requiring the use of any particular
contingency reserve option. The proposed
directive as written achieves that goal. With
regard to the second concern, we believe that
this Reliability Standard is objective-based
and we reiterate that we are simply
attempting to make it inclusive of other
technologies that may be able to provide
contingency reserves, and are not directing
the use of any particular type of resource. By
specifying DSM as a potential resource for
contingency reserves, the Commission is
clarifying the substance of the Reliability
Standard.64
Thus, in the interest of clarity and
comparability, we would prefer to see
DSM included among the list of
alternatives to TLR procedures.
Therefore, we would be interested in
comments regarding the inclusion of
DSM that is capable of responding
quickly to emergencies among the
alternatives to TLR procedures for
mitigating transmission line limit
violations to maintain system reliability.
For these reasons, we concur with this
NOPR.
Jon Wellinghoff,
Commissioner.
Suedeen G. Kelly,
Commissioner.
[FR Doc. E8–9013 Filed 4–25–08; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 382
[Docket No. AD08–7–000]
Annual Charges Assessments for
Public Utilities
April 21, 2008.
Federal Energy Regulatory
Commission, DOE.
ACTION: Notice of Inquiry.
AGENCY:
In this Notice of Inquiry, the
Commission is seeking comments on its
current methodology for the assessment
of electric annual charges to public
utilities, in particular, whether that
methodology remains fair and equitable,
and on alternative methodologies. As
provided in its current regulations, the
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SUMMARY:
64 Id
at P 331–33.
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17:54 Apr 25, 2008
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Commission recovers the costs of its
electric regulatory program through
filing fees and, as particularly relevant
here, annual charges assessed to public
utilities that provide transmission
service, based on the volume of
electricity transmitted. This
methodology reflects that regulation of
transmission providers, transmission
facilities and transmission service is
central to Commission regulation, and
that the transmission grid is the
interstate highway system for wholesale
power sales. This Notice will enable the
Commission to determine whether its
current methodology remains fair and
equitable, and to review alternative
methodologies.
DATES: Comments are due May 28, 2008.
ADDRESSES: Interested persons may
submit comments, identified by Docket
No. AD08–7–000, by any of the
following methods:
• eFiling: Comments may be filed
electronically via the eFiling link on the
Commission’s Web site at https://
www.ferc.gov. Documents created
electronically using word processing
software should be filed in the native
application or print-to-PDF format and
not in a scanned format. This will
enhance document retrieval for both the
Commission and the public. The
Commission accepts most standard
word processing formats and
commenters may attach additional files
with supporting information in certain
other file formats. Attachments that
exist only in paper form may be
scanned. Commenters filing
electronically should not make a paper
filing. Service of rulemaking (or Notice
of Inquiry) comments is not required.
• Mail/Hand Delivery: Commenters
that are not able to file electronically
must mail or hand deliver an original
and 14 copies of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
FOR FURTHER INFORMATION CONTACT: For
further information contact:
Lawrence R. Greenfield (Legal
Information), Office of the General
Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
6415.
Richard M. Wartchow (Legal
Information), Office of the General
Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
8744.
Troy D. Cole (Technical Information),
Director, Division of Financial
Services, Office of the Executive
Director, Federal Energy Regulatory
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22867
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
6161.
SUPPLEMENTARY INFORMATION:
1. In this Notice of Inquiry, the
Commission is seeking comments on its
current methodology for the assessment
of electric annual charges to public
utilities, in particular, whether that
methodology remains fair and equitable,
and on alternative methodologies.1 As
provided in its current regulations, the
Commission recovers the costs of its
electric regulatory program through
filing fees and, as particularly relevant
here, annual charges assessed to public
utilities that provide transmission
service, based on the volume of
electricity transmitted. This
methodology reflects that regulation of
transmission providers, transmission
facilities and transmission service is
central to Commission regulation, and
that the transmission grid is the
interstate highway system for wholesale
power sales. This Notice will enable the
Commission to determine whether its
current methodology remains fair and
equitable, and to review alternative
methodologies.
2. Although the Commission has held
in the past that industry concerns did
not justify a change to the annual
charges methodology, in response to
continued expressions of concern the
Commission is issuing this Notice of
Inquiry to seek comment on whether the
existing methodology remains an
appropriate means to recover the costs
of the Commission’s electric regulatory
program or whether there is another
more appropriate alternative. The
Commission seeks to ascertain whether
those industry concerns, although not
determinative previously, may now be
more valid and, if so, to review
alternative proposals for the recovery of
the Commission’s electric regulatory
program costs. The Commission also
invites interested parties to submit in
this proceeding their views on other
possible changes to the Commission’s
annual charges regulations.
1 This Notice of Inquiry is limited to the
assessment of annual charges to public utilities
regulated under Parts II and III of the Federal Power
Act (FPA). It does not, therefore, address the
assessment of charges for the Commission’s
hydroelectric, natural gas or oil pipeline regulatory
programs. It also does not address recovery of
Federal power marketing agency (PMA)-related
costs or electric filing fees (the latter are separately
charged for, among other things, petitions for
declaratory orders, Commission staff interpretations
and certain qualifying facility-related filings).
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]]>Agencies
[Federal Register Volume 73, Number 82 (Monday, April 28, 2008)]
[Proposed Rules]
[Pages 22856-22867]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-9013]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM08-7-000]
Modification of Interchange and Transmission Loading Relief
Reliability Standards; and Electric Reliability Organization
Interpretation of Specific Requirements of Four Reliability Standards
Issued April 21, 2008.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Notice of proposed rulemaking.
-----------------------------------------------------------------------
SUMMARY: Pursuant to section 215 of the Federal Power Act, the Federal
Energy Regulatory Commission proposes to approve six modified
Reliability Standards submitted to the Commission for approval by the
North American Electric Reliability Corporation (NERC). Five modified
Reliability Standards pertain to interchange scheduling and
coordination and one pertains to transmission loading relief
procedures. In addition, the Commission proposes to approve NERC's
proposed interpretations of five specific requirements of Commission-
approved Reliability Standards.
DATES: Comments are due June 12, 2008.
ADDRESSES: You may submit comments, identified by docket number by any
of the following methods:
Agency Web Site: https://www.ferc.gov. Documents created
electronically using word processing software should be filed in native
applications or print-to-PDF format and not in a scanned format.
Mail/Hand Delivery: Commenters unable to file comments
electronically must mail or hand deliver an original and 14 copies of
their comments to: Federal Energy Regulatory Commission, Secretary of
the Commission, 888 First Street, NE., Washington, DC 20426.
FOR FURTHER INFORMATION CONTACT:
Patrick Harwood (Technical Information), Office of Electric
Reliability, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426.
Christopher Daignault (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426.
SUPPLEMENTARY INFORMATION:
[[Page 22857]]
Table of Contents
Paragraph
numbers
I. Background.............................................. 2
A. EPAct 2005 and Mandatory Reliability Standards...... 2
B. NERC Filings........................................ 6
II. Discussion............................................. 11
A. NERC's December 19, 2007 Filing: Interpretations.... 12
1. BAL-001-0--Real Power Balancing Control 13
Performance and BAL-003-0--Frequency Response and
Bias..............................................
a. Background.................................. 13
i. Reliability Standard BAL-001-0.......... 13
ii. Reliability Standard BAL-003-0......... 15
b. NERC's Proposed Interpretations............. 16
i. Reliability Standard BAL-001-0.......... 17
ii. Reliability Standard BAL-003-0......... 21
c. Commission Proposal......................... 23
2. BAL-005-0--Automatic Generation Control......... 26
a. NERC's Proposed Interpretation.............. 26
b. Commission Proposal......................... 28
3. VAR-002-1--Generator Operation for Maintaining 29
Network Voltage Schedules.........................
a. NERC's Proposed Interpretation.............. 29
b. Commission Proposal......................... 34
B. NERC's December 21, 2007 Filing: Modification of TLR 35
Procedure.............................................
1. NERC's Proposed Reliability Standard............ 35
a. Background.................................. 36
b. NERC Filing................................. 38
c. Commission Proposal......................... 47
i. Requirements............................ 48
ii. Violation Risk Factors................. 50
C. NERC's December 26, 2007 Filing: Modification to 58
Five ``Interchange and Scheduling'' Reliability
Standards.............................................
1. INT-001-3--Interchange Information and INT-004- 59
2--Dynamic Interchange Transaction Modifications..
a. Background.................................. 59
b. NERC's Proposed Modifications............... 61
c. Commission Proposal......................... 63
2. INT-005-2--Interchange Authority Distributes 64
Arranged Interchange..............................
a. INT-006-2--Response to Interchange 64
Authority, and INT-008-2--Interchange
Authority Distributes Status..................
i. Background.............................. 64
ii. NERC's Proposed Modifications.......... 68
b. Commission Proposal......................... 74
III. Information Collection Statement...................... 75
IV. Environmental Analysis................................. 82
V. Regulatory Flexibility Act Analysis..................... 83
VI. Comment Procedures..................................... 84
VII. Document Availability................................. 88
1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Federal Energy Regulatory Commission (Commission) proposes to approve
six modified Reliability Standards submitted to the Commission for
approval by the North American Electric Reliability Corporation (NERC).
Five modified Reliability Standards pertain to interchange scheduling
and coordination, and one pertains to transmission loading relief
procedures.\2\ In addition, the Commission proposes to approve NERC's
proposed interpretations of five specific requirements of Commission-
approved Reliability Standards.
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\1\ 16 U.S.C. 824o (Supp. V 2005).
\2\ The Commission is not proposing any new or modified text to
its regulations. Rather, as set forth in 18 CFR Part 40, a proposed
Reliability Standard will not become effective until approved by the
Commission, and the ERO must post on its Web site each effective
Reliability Standard.
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I. Background
A. EPAct 2005 and Mandatory Reliability Standards
2. Section 215 of the FPA requires a Commission-certified Electric
Reliability Organization (ERO) to develop mandatory and enforceable
Reliability Standards, which are subject to Commission review and
approval. Once approved, the Reliability Standards may be enforced by
the ERO, subject to Commission oversight, or by the Commission
independently.\3\
3. Pursuant to section 215 of the FPA, the Commission established a
process to select and certify an ERO \4\ and, subsequently, certified
NERC as the ERO.\5\ On April 4, 2006, as modified on August 28, 2006,
NERC submitted to the Commission a petition seeking approval of 107
proposed Reliability Standards. On March 16, 2007, the Commission
issued a final rule, Order No. 693, approving 83 of these 107
Reliability Standards and directing other action related to these
Reliability Standards.\6\ In addition, pursuant to section 215(d)(5) of
the FPA, the Commission directed NERC to develop modifications to 56 of
the 83 approved Reliability Standards.\7\
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\3\ See FPA 215(e)(3), 16 U.S.C. 824o(e)(3) (Supp. V 2005).
\4\ Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval and
Enforcement of Electric Reliability Standards, Order No. 672, FERC
Stats. & Regs. ] 31,204, order on reh'g, Order No. 672-A, FERC
Stats. & Regs. ] 31,212 (2006).
\5\ North American Electric Reliability Corp., 116 FERC ] 61,062
(ERO Certification Order), order on reh'g & compliance, 117 FERC ]
61,126 (ERO Rehearing Order) (2006), appeal docketed sub nom. Alcoa,
Inc. v. FERC, No. 06-1426 (D.C. Cir. Dec. 29, 2006).
\6\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, FERC Stats. & Regs. ] 31,242, order on reh'g, Order
No. 693-A, 120 FERC ] 61,053 (2007).
\7\ 16 U.S.C. 824o(d)(5) (Supp. V 2005). Section 215(d)(5)
provides, ``The Commission * * * 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.''
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[[Page 22858]]
4. In April 2007, the Commission approved delegation agreements
between NERC and each of the eight Regional Entities, including the
Western Electricity Coordinating Council (WECC).\8\ Pursuant to such
agreements, the ERO delegated responsibility to the Regional Entities
to carry out compliance monitoring and enforcement of the mandatory,
Commission-approved Reliability Standards. In addition, the Commission
approved as part of each delegation agreement a Regional Entity process
for developing regional Reliability Standards.
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\8\ See North American Electric Reliability Corp., 119 FERC ]
61,060, order on reh'g, 120 FERC ] 61,260 (2007).
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5. NERC's Rules of Procedure provide that a person that is
``directly and materially affected'' by Bulk-Power System reliability
may request an interpretation of a Reliability Standard.\9\ The ERO's
``standards process manager'' will assemble a team with relevant
expertise to address the clarification and also form a ballot pool.
NERC's Rules provide that, within 45 days, the team will draft an
interpretation of the Reliability Standard, with subsequent balloting.
If approved by ballot, the interpretation is appended to the
Reliability Standard and filed with the applicable regulatory authority
for regulatory approval.
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\9\ NERC Rules of Procedure, Appendix 3A (Reliability Standards
Development Procedure), at 26-27.
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B. NERC Filings
6. This rulemaking proceeding consolidates and addresses three NERC
filings.
7. On December 19, 2007, NERC submitted for Commission approval
interpretations of requirements in four Commission-approved Reliability
Standards: BAL-001-0 (Real Power Balancing Control Performance),
Requirement R1; BAL-003-0 (Frequency Response and Bias), Requirement
R3; BAL-005-0 (Automatic Generation Control), Requirement R17; and VAR-
002-1 (Generator Operation for Maintaining Network Voltage Schedules),
Requirements R1 and R2.\10\
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\10\ In its filing, NERC identifies the Reliability Standards
together with NERC's proposed interpretations as BAL-001-0a, BAL-
003-0a, BAL-005-0a, and VAR-002-1a.
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8. On December 21, 2007, NERC submitted for Commission approval
modifications to Reliability Standard IRO-006-4 (Reliability
Coordination--Transmission Loading Relief) that applies to balancing
authorities, reliability coordinators, and transmission operators. NERC
states that the modifications ``extract'' from the Reliability Standard
the business practices and commercial requirements from the current
IRO-006-3 Reliability Standard. The business practices and commercial
requirements have been transferred to a North American Energy Standards
Board (NAESB) business practices document. The NAESB business practices
and commercial requirements have been included in Version 001 of the
NAESB Wholesale Electric Quadrant (WEQ) Standards which NAESB filed
with the Commission on the same day, December 21, 2007.\11\ Further,
NERC states that the modified Reliability Standard includes changes
directed by the Commission in Order No. 693 related to the
appropriateness of using the transmission loading relief (TLR)
procedure to mitigate violations of interconnection reliability
operating limits (IROLs).\12\
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\11\ NAESB December 21, 2007 Filing, Docket No. RM05-5-005.
\12\ An IROL is a system operating limit that, if violated,
could lead to instability, uncontrolled separation, or cascading
outages that adversely impact the reliability of the Bulk-Power
System.
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9. On December 26, 2007, NERC submitted for Commission approval
modifications to five Reliability Standards from the ``Interchange
Scheduling'' group of Reliability Standards: INT-001-3 (Interchange
Information); INT-004-2 (Dynamic Interchange Transaction
Modifications); INT-005-2 (Interchange Authority Distributes Arranged
Interchange); INT-006-2 (Response to Interchange Authority); and INT-
008-2 (Interchange Authority Distributes Status). NERC states that the
modifications to INT-001-3 and INT-004-2 eliminate waivers requested in
2002 under the voluntary Reliability Standards regime for entities in
the WECC region. According to NERC, modifications to INT-005-2, INT-
006-2, and INT-008-2 adjust reliability assessment time frames for
proposed transactions within WECC.\13\
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\13\ The proposed, modified Reliability Standard addressed in
this notice of proposed rulemaking is available on the Commission's
eLibrary document retrieval system in Docket No. RM08-7-000 and also
on NERC's Web site, https://www.nerc.com.
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10. Each Reliability Standard that the ERO proposes to interpret or
modify in this proceeding was approved by the Commission in Order No.
693.
II. Discussion
11. The Commission discusses below the ERO's proposed
interpretations and proposed modifications, and the Commission's
proposed disposition of each.
A. NERC's December 19, 2007 Filing: Interpretations
12. As mentioned above, NERC submitted for Commission approval
interpretations of four Commission-approved Reliability Standards.
1. BAL-001-0-Real Power Balancing Control Performance and BAL-003-0-
Frequency Response and Bias
a. Background
i. Reliability Standard BAL-001-0
13. The purpose of Reliability Standard BAL-001-0 is to maintain
interconnection steady-state frequency within defined limits by
balancing real power demand and supply in real-time.\14\ Requirement R1
of BAL-001-0 defines the limits on area control error (ACE), which
essentially is the mismatch between generation and load (i.e., the
mismatch between supply and demand) within the footprint of a balancing
authority, measured by the difference between the balancing authority's
net actual interchange and scheduled interchange with neighboring
balancing authorities, after taking into account effects of deviations
in interconnection frequency.\15\ The ability to constantly match load
and generation within a certain tolerance directly affects the
electrical state and control of the Bulk-Power System.\16\ Each
balancing authority thus monitors the extent of its ACE in real-time
and takes appropriate action also in real-time to rebalance supply and
demand.\17\ Requirement R1 obliges each balancing authority, on a
rolling twelve-month
[[Page 22859]]
basis, to maintain its clock-minute averages of ACE within a specific
limit.
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\14\ See Reliability Standard BAL-001-0. Each Reliability
Standard developed by the ERO includes a ``Purpose'' statement.
\15\ Generally, a balancing authority within an interconnection
has an obligation to do its part to maintain the desired 60 Hertz
(Hz) frequency. To achieve this, each balancing authority must keep
its generation output (including net imports from neighboring
balancing authorities) and load in balance within its footprint. A
deviation from the 60 Hz baseline system frequency signals an
imbalance in supply and demand. To prevent this imbalance from
propagating throughout the interconnection, steps are taken to
adjust regulating reserves (generation output and demand-side
management) in response to deviations from the 60 Hz optimum. See
North American Electric Reliability Corp., 121 FERC ] 61,179, at P
17 (2007) (November 16, 2007 Order).
\16\ If generation and load is not matched within a balancing
authority's area, the resulting imbalance could result in an undue
burden on adjacent balancing authorities and, if additional
contingencies from disturbances are experienced, may compromise the
ability of the Bulk-Power System to recover from those disturbances.
See November 16, 2007 Order, 121 FERC ] 61,179 at P 28.
\17\ See November 16, 2007 Order, 121 FERC ] 61,179 at P 20.
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14. A supply/demand imbalance between the interconnection's
generation output (including net imports) and load on a real-time basis
will result in a deviation from the desired 60 Hz optimum operating
frequency of the interconnection. All of the balancing authorities
within an interconnection must work together to correct a
deviation.\18\ They do this by including a frequency bias component in
their ACE calculation which indicates how many more or fewer megawatts
a balancing authority would have interchanged with neighboring
balancing authorities if the actual frequency had been exactly
maintained so as to equal to the scheduled frequency. Thus, balancing
authorities calculate what their total interchange would have been if
the actual frequency had been exactly maintained so as to equal to the
scheduled frequency. With this information, the balancing authority can
increase or decrease generation within the balancing authority's area
to maintain the correct scheduled interchange. The total supply and the
demand within an interconnection is balanced by the collective effort
of all the balancing authorities in that interconnection to maintain
the correct scheduled interchange. In this manner, frequency deviations
are minimized, thereby protecting reliability without causing undue
burden on any balancing authorities.
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\18\ See id. P 31.
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ii. Reliability Standard BAL-003-0
15. The purpose of Reliability Standard BAL-003-0 is to provide a
consistent method for calculating the frequency bias component of ACE.
To accomplish this purpose, it is necessary to rely on historic data
from a balancing authority's automatic generation control.\19\
Automatic generation control is the equipment that calculates ACE on an
ongoing basis and serves as a ``governor'' that adjusts a balancing
authority's generation, and demand-side resources where available, from
a central location to minimize unscheduled interchange with its
neighboring balancing authorities in order to balance ACE. There are
several ways that automatic generation control could be set to balance
the supply and demand within the balancing authority area. One method
is called the ``tie-line frequency bias'' mode of operation. Collective
operation in this mode allows balancing authorities' automatic
generation control to calculate ACE and adjust the generation in the
balancing authority area in a manner that maintains the interconnection
frequency and does not result in an undue burden for any balancing
authority. In addition, operation in this mode allows a balancing
authority to continuously collect its tie-line and frequency data that
must be used when the balancing authority annually reviews the
frequency bias component of its ACE calculation as specified by BAL-
003-0. Requirement R3 of BAL-003-0 requires the use of the tie-line
frequency bias mode of operation of automatic generation control,
unless such operation is adverse to system interconnection reliability.
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\19\ Automatic generation control refers to an automatic process
whereby a balancing authority's mix and output of its generation and
demand-side management is varied to offset the extent of supply and
demand imbalances reflected in its ACE. November 16, 2007 Order, 121
FERC ] 61,179 at P 19 n.14.
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b. NERC's Proposed Interpretations
16. NERC further states that, on June 1, 2007, WECC requested that
NERC provide a formal interpretation that addresses Requirement R1 of
BAL-001-0 and Requirement R3 of BAL-003-0. In particular, WECC asked
whether the use of WECC's existing automatic time error correction
procedure, which is currently proposed as a regional Reliability
Standard, violates Requirement R1 of BAL-001-0 or Requirement R3 of
BAL-003-0.
i. Reliability Standard BAL-001-0
17. Requirement R1 of BAL-001-0 provides:
Each Balancing Authority shall operate such that, on a rolling
12-month basis, the average of the clock-minute averages of the
Balancing Authority's Area Control Error (ACE) divided by 10B (B is
the clock-minute average of the Balancing Authority Area's Frequency
Bias) times the corresponding clock-minute averages of the
Interconnection's Frequency Error is less than a specific limit.
This limit [egr]1\2\ is a constant derived from a
targeted frequency bound (separately calculated for each
Interconnection) that is reviewed and set as necessary by the NERC
Operating Committee.
18. NERC's proposed interpretation of BAL-001-0 Requirement R1
reads:
The [WECC automatic time error correction or WATEC]
procedural documents ask Balancing Authorities to maintain raw ACE for
[control performance standard or CPS] reporting and to control via
WATEC-adjusted ACE.
As long as Balancing Authorities use raw (unadjusted for
WATEC) ACE for CPS reporting purposes, the use of WATEC for control is
not in violation of BAL-001 Requirement 1.
(NERC December 19, 2007 Filing, Ex. A-2.)
19. As context to its interpretation, NERC explains that BAL-001-0
uses a formula for the ACE calculation equal to the difference in
actual and scheduled interchange, less a component based on the
frequency bias to adjust for the difference in actual and scheduled
frequency, less the meter error.\20\ NERC also explains that the WECC
automatic time error correction procedure uses the same formula for ACE
as defined in BAL-001-0 except with two additional components.\21\
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\20\ See NERC December 19, 2007 Filing at 8-9.
\21\ See id.
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20. NERC maintains that the use of the WECC automatic time error
correction procedure for control does not result in a violation of BAL-
001-0 Requirement 1, provided that (1) WECC's balancing authorities use
the raw and unadjusted ACE for control performance reporting purposes
and (2) the raw, unadjusted ACE complies with Requirement R1.
ii. Reliability Standard BAL-003-0
21. Requirement R3 of BAL-003-0 provides:
Each Balancing Authority shall operate its Automatic Generation
Control (AGC) on Tie Line Frequency Bias, unless such operation is
adverse to system or Interconnection Reliability.
NERC's proposed interpretation of BAL-003-0 Requirement R3 reads:
Tie-Line Frequency Bias is one of the three foundational
control modes available in a Balancing Authority's energy management
system. (The other two are flat-tie and flat-frequency.) Many Balancing
Authorities layer other control objectives on top of their basic
control mode, such as automatic inadvertent payback, [control
performance standard] optimization, time control (in single [balancing
authority] interconnections).\22\
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\22\ The ``flat frequency'' control mode would increase or
decrease generation solely based on the interconnection frequency.
The ``flat tie'' mode would increase or decrease generation within a
balancing authority area depending solely on that balancing
authority's total interchange. The ``tie-line frequency bias'' mode
combines the flat frequency and flat tie modes and adjusts
generation based on the balancing authority's net interchange and
the interconnection frequency.
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As long as Tie-Line Frequency Bias is the underlying
control mode and CPS1 is measured and reported on the associated ACE
equation,\23\ there is no violation of BAL-003-0 Requirement 3:
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\23\ ``CPS1'' refers to Requirement R1 of BAL-001-0.
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ACE = (NIA--NIS)--10B (FA--FS)--IME
(NERC December 19, 2007 Filing, Ex. A-3.)
[[Page 22860]]
22. NERC explains that there is no violation of BAL-003-0
Requirement R3, provided that a balancing authority uses the tie-line
frequency bias mode as the underlying control mode and the control
performance standard (CPS1), per BAL-001-0 Requirement R1, is measured
and reported on the associated ACE equation.
c. Commission Proposal
23. The Commission proposes to approve the ERO's formal
interpretation of Requirement R1 of BAL-001-0 and Requirement R3 of
BAL-003-0.
24. The ERO's interpretation is reasonable because it clarifies
that raw ACE must be used in NERC compliance reporting. Reporting of
raw ACE is essential because a balancing authority could exceed ACE
limits in BAL-001-0 if allowed to report an adjusted ACE that adds or
subtracts amounts from the equation. This interpretation upholds the
reliability goal of BAL-001-0, Requirement R1 to minimize the frequency
deviation of the interconnection by constantly balancing supply and
demand. The interpretation also clarifies that an entity may use
automatic generation control modes layered on top of the tie-line
frequency bias mode as long as the raw ACE is used in NERC compliance
reporting. This would permit WECC to implement more stringent time
error correction procedures that rely on additional control modes
layered on top of the tie-line frequency bias mode of automatic
generation control, provided they do not report adjusted ACE which, if
reported, could produce ambiguous data used for frequency bias
calculations. The interpretation maintains the goal of BAL-003-0,
Requirement R3, by providing accurate historic data for frequency bias
calculations and by using ACE calculations in automatic generation
control that will adjust the generation, or demand-side resources where
available, in the balancing authority area in a manner that maintains
the interconnection frequency and does not result in an undue burden
for any balancing authority. The Commission proposes to approve the
ERO's interpretation based on the understanding that a balancing
authority, in operating automatic generation control, must use tie-line
frequency bias as its underlying control mode unless to do so is
adverse to system or interconnection reliability.
25. In Order No. 693, the Commission stated that, according to the
available data, the WECC automatic time error correction procedure is
more effective in minimizing time error corrections and inadvertent
interchange than the Reliability Standard BAL-004-0.\24\ Therefore, the
ERO's interpretation provides balancing authorities using the WECC
automatic time error correction procedure with necessary clarification
and certainty in accordance with the continent-wide Reliability
Standards BAL-001-0 and BAL-003-0. Accordingly, this interpretation
appears to be just, reasonable, not unduly discriminatory or
preferential, and in the public interest.
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\24\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 377.
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2. BAL-005-0--Automatic Generation Control
a. NERC's Proposed Interpretation
26. Requirement R17 of Reliability Standard BAL-005-0 (Automatic
Generation Control) is intended to annually check and calibrate the
time error and frequency devices under the control of the balancing
authority that feed data into automatic generation control necessary to
calculate ACE. Requirement R17 mandates that the balancing authority
must adhere to an annual calibration program for time error and
frequency devices. The Requirement states that a balancing authority
must adhere to minimum accuracies in terms of ranges specified in
Hertz, volts, amps, etc., for various listed devices, such as digital
frequency transducers, voltage transducers, remote terminal unit,
potential transformers, and current transformers.
27. On December 21, 2006, NERC received a request to provide a
formal interpretation of Requirement R17 asking whether the only
devices that need to be annually calibrated under this requirement are
time error and frequency devices, and whether the list of device
accuracy is simply the design accuracy of the devices listed and that
those devices do not need to be calibrated on an annual basis (except
the digital frequency transducer which is covered as a ``frequency
device''). NERC provided an interpretation clarifying that the intent
of BAL-005-0, Requirement R17 is to annually check and calibrate a
balancing authority's time error and frequency devices located in the
control room against the common reference, and this requirement does
not apply to any such devices located outside of the operations control
center.
b. Commission Proposal
28. On July 31, 2007, the ERO received a second request for an
interpretation of Requirement R17 of BAL-005-0, which asked the ERO to
further clarify the ambiguity of what devices are included in the
requirement. On April 15, 2008, the ERO submitted another
interpretation of Requirement R17 of BAL-005-0 and sought to withdraw
its request for Commission approval of the interpretation of
Requirement R17 filed in this proceeding on December 19, 2007.
Accordingly, the Commission does not plan to act on the initial
interpretation. The Commission will act on the April 15 interpretation
in a future proceeding.
3. VAR-002-1--Generator Operation for Maintaining Network Voltage
Schedules
a. NERC's Proposed Interpretation
29. The stated purpose of Reliability Standard VAR-002-1 is to
ensure that generators provide reactive and voltage control necessary
to ensure that voltage levels, reactive flows, and reactive resources
are maintained within applicable facility ratings to protect equipment
and the reliable operation of the interconnection.\25\ Specifically,
Requirement R1 of Reliability Standard VAR-002-1 provides:
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\25\ Most bulk electric power is generated, transported, and
consumed in alternating current (AC) networks. AC systems supply (or
produce) and consume (or absorb or lose) two kinds of power: real
power and reactive power. Real power accomplishes useful work (e.g.,
runs motors and lights lamps). Reactive power supports the voltages
that must be controlled for system reliability. FERC, Principles for
Efficient and Reliable Reactive Power Supply and Consumption, Docket
No. AD05-1-000, at 17 (2005), available at https://www.ferc.gov/
legal/staff-reports.asp (Reactive Power Principles).
The Generator Operator shall operate each generator connected to
the interconnected transmission system in the automatic voltage
control mode (automatic voltage regulator in service and controlling
voltage) unless the Generator Operator has notified the Transmission
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Operator.
Requirement R2 of this Reliability Standard provides:
Unless exempted by the Transmission Operator, each Generator
Operator shall maintain the generator voltage or Reactive Power
output (within applicable Facility Ratings) as directed by the
Transmission Operator.
30. NERC states that it received a request to provide a formal
interpretation of Requirements R1 and R2 on January 24, 2007. The
request for interpretation first asked whether automatic voltage
regulator (AVR) operation in the constant power factor or constant Mvar
modes complies with Requirement R1.\26\ Secondly, the
[[Page 22861]]
request asked the ERO whether Requirement R2 gives the transmission
operator the option of directing the generation owner to operate the
AVR in the constant power factor or constant Mvar modes rather than the
constant voltage mode.
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\26\ ``Power factor'' is a measure of real power in relation to
reactive power. A high power factor means that relatively more
useful power is being taken or produced relative to the amount of
reactive power. A lower power factor means that there is relatively
more reactive power taken than real power. ``Mvar'' is a measure of
reactive power equal to one million reactive volt-amperes. Reactive
Power Principles, supra note 16, at 7, 12, 41, 119, 120.
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31. The AVR is designed to automatically adjust generator voltage
and/or power-factor to ensure proper grid operational characteristics.
Constant voltage mode is the normal mode of operation for AVR and
maintains the output voltage at a constant level. The constant power
factor mode is a setting of the AVR that causes the generator to output
a set ratio of real power to reactive power, whereas the constant Mvar
mode is a setting that causes the generator to maintain an output with
a constant amount of reactive power.
32. NERC's formal interpretation provides that AVR operation in the
constant power factor or constant Mvar modes does not comply with
Requirement R1.\27\ The interpretation rests on the assumption that the
generator has the physical equipment that will allow such operation and
that the transmission operator has not directed the generator to run in
a mode other than constant voltage. The interpretation also provides
that Requirement R2 does give the transmission operator the option of
directing the generation operator to operate the AVR in the constant
power factor or constant Mvar modes rather than the constant voltage
mode.\28\
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\27\ NERC's proposed interpretation of VAR-002-1 Requirement R1
reads:
1. First, does AVR operation in the constant PF or constant Mvar
modes comply with R1? Interpretation: No, only operation in constant
voltage mode meets this requirement. This answer is predicated on
the assumption that the generator has the physical equipment that
will allow such operation and that the Transmission Operator has not
directed the generator to run in a mode other than constant voltage.
2. Second, does R2 give the Transmission Operator the option of
directing the Generation Owner (sic) to operate the AVR in the
constant Pf or constant Mvar modes rather than the constant voltage
mode?
Interpretation: Yes, if the Transmission Operator specifically
directs a Generator Operator to operate the AVR in a mode other than
constant voltage mode, then that directed mode of AVR operation is
allowed.
NERC December 19, 2007 Filing, Ex. C-2.
\28\ We note, as does NERC, the requesting party's apparent
error when it references ``Generation Owner'' instead of the
generator operator.
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33. In its transmittal letter, NERC explains that, with respect to
the interpretation of Requirement R1, Reliability Standard VAR-002-1
clearly states that the generator operator shall operate with the
automatic voltage regulator in service and controlling voltage. The
interpretation specifies that this can only be accomplished by using
the constant voltage control mode, and using the constant power factor
or constant Mvar control is not a true method to control voltage even
though it may have some effect on voltage. In addition, NERC explains
that Requirement R2 provides for an exemption to this baseline mode of
operation to allow the transmission operator the ability to direct the
generator operator to use another mode of operation.
b. Commission Proposal
34. The Commission proposes to approve the ERO's interpretation of
Requirement R1 and Requirement R2 of VAR-002-1. These interpretations
appear to be reasonable and do not appear to change or conflict with
the stated responsibilities set forth in the two requirements as
approved in Order No. 693. Therefore, this interpretation appears to be
just, reasonable, not unduly discriminatory or preferential, and in the
public interest.
B. NERC's December 21, 2007 Filing: Modification of TLR Procedure
1. NERC's Proposed Reliability Standard
35. As mentioned above, on December 21, 2007, NERC submitted for
Commission approval proposed Reliability Standard IRO-006-4, to modify
the current Commission-approved Reliability Standard, IRO-006-3.
a. Background
36. In Order No. 693, the Commission approved the current version
of this Reliability Standard, IRO-006-3. This Reliability Standard
ensures that a reliability coordinator has a coordinated transmission
service curtailment and reconfiguration method that can be used along
with other alternatives, such as redispatch or demand-side management,
to avoid transmission limit violations when the transmission system is
congested. Reliability Standard IRO-006-3 establishes a detailed TLR
process for use in the Eastern Interconnection to alleviate loadings on
the system by curtailing or changing transactions based on their
priorities and the severity of the transmission congestion.\29\
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\29\ The equivalent interconnection-wide TLR procedures for use
in WECC and Electric Reliability Council of Texas (ERCOT) are known
as ``WSCC Unscheduled Flow Mitigation Plan'' and section 7 of the
``ERCOT Protocols,'' respectively.
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37. In addition to approving IRO-006-3, the Commission in Order No.
693 directed the ERO to modify the Reliability Standard to: (1) Include
a clear warning that the TLR procedure is an inappropriate and
ineffective tool to mitigate actual IROL violations; \30\ and (2)
identify in a requirement the available alternatives to mitigate an
IROL violation other than use of the TLR procedure.\31\ These
directives reflect an observation from the U.S.-Canada Power System
Outage Task Force in the August 14, 2003 Blackout Report, which
identified that the TLR procedure is often too slow for use in
situations where the system has already violated IROLs.\32\ In setting
forth these directives, the Commission stated that it did not have
concerns with the use of the TLR procedure to avoid potential IROL
violations.\33\
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\30\ An IROL is a system operating limit that, if violated,
could lead to instability, uncontrolled separation, or cascading
outages that adversely impact the reliability of the Bulk-Power
System.
\31\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 964.
\32\ U.S.-Canada Power System Outage Task Force, Final Report on
the August 14, 2003 Blackout in the United States and Canada: Causes
and Recommendations, at 163 (April 2004) (Final Blackout Report),
available at https://reports.energy.gov/.
\33\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 962.
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b. NERC Filing
38. According to NERC, the modifications embodied in proposed
Reliability Standard IRO-006-4 represent the first phase of a three-
phase project intended to improve the overall quality of IRO-006. In
the first phase, NERC extracted the business practices and commercial
requirements from the existing IRO-006-3 Reliability Standard and
proposes to transfer them into the NAESB business practices.\34\ NERC's
filing does not seek to modify the remaining reliability requirements
of IRO-006, with the exception that the Reliability Standard has been
clarified to include the Commission's Order No. 693 directive that
using the TLR procedure is not effective to mitigate an actual IROL
violation.
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\34\ The NAESB business practices and commercial requirements
have been included in Version 001 of the NAESB Wholesale Electric
Quadrant standards and filed with the Commission on December 21,
2007. The NAESB filing is the subject of a separate rulemaking in
Docket No. RM05-5-005. A notice of proposed rulemaking addressing
the NAESB filing is being issued concurrently with the immediate
NOPR.
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39. According to NERC, the second phase of the IRO-006 project will
address possible changes to the regional differences associated with
the congestion management process used by the PJM Interconnection,
L.L.C., the
[[Page 22862]]
Midwest Independent System Operator, Inc., and the Southwest Power
Pool, Inc. In the third phase, NERC plans to completely redraft the
Reliability Standard to incorporate further enhancements and changes
beyond the separation of reliability and business practices.
40. In its filing, NERC explains that the filed Reliability
Standard IRO-006-4 meets the guidance outlined in Order No. 672, used
to determine whether a Reliability Standard is just, reasonable, not
unduly discriminatory or preferential, and in the public interest.\35\
In addition, IRO-006-4 includes violation risk factors and violation
severity levels that were not provided with IRO-006-3.
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\35\ Order No. 672, FERC Stats. & Regs. ] 31,204 at P 326.
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41. NERC's proposed IRO-006-4 Reliability Standard consists of five
requirements. Proposed Requirement R1 obligates a reliability
coordinator experiencing a potential or actual system operating limit
(SOL) or IROL violation within its reliability coordinator area to
select one or more procedures to provide transmission loading relief.
The requirement also identifies the regional TLR procedures in WECC and
Electric Reliability Council of Texas (ERCOT). The requirement includes
a warning that the TLR procedure alone is an inappropriate and
ineffective tool to mitigate an IROL violation and provides
alternatives.
42. Proposed Requirement 2 mandates that the reliability
coordinator only use a congestion management procedure to which the
transmission operator experiencing the SOL or IROL is a party. NERC
explains that Requirement R1 and Requirement R2 are assigned a
violation risk factor of ``lower'' because they are administrative in
nature and are merely intended to describe how a reliability
coordinator may choose a procedure to implement TLR.\36\ According to
NERC, these Requirements are not intended to duplicate the requirements
of other Reliability Standards that ensure the system is operated
within SOL and IROL limits such as Requirements R3 and R5 of IRO-005-1,
which have ``high'' violation risk factors.\37\ NERC adds that,
provided the reliability coordinator is adhering to the requirements in
IRO-005-1, there is no significant risk to the reliability of the Bulk-
Power System as a result of a violation of Requirement R1 of IRO-006-4.
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\36\ Exhibit A (Reliability Standard Proposed for Approval) of
NERC's December 21, 2007 filing, however, contains the violation
risk factor of ``medium'' for these requirements, but NERC indicates
elsewhere that it is ``lower.'' NERC December 21, 2007 Filing at 12-
13.
\37\ Id. at 13.
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43. Proposed Requirement R3 establishes that a reliability
coordinator with a TLR obligation from an interconnection-wide
procedure follow the curtailments as directed by the interconnection-
wide procedure. The requirement includes that a reliability coordinator
desiring to use a local procedure as a substitute for curtailments as
directed by the interconnection-wide procedure shall obtain prior
approval of the local procedure from the ERO. NERC states that a
violation risk factor of ``lower'' for Requirement R3 is appropriate
because it is intended that an entity could choose alternate actions
for relief other than curtailments specified by this requirement to
ensure reliability.
44. Proposed Requirement R4 mandates that each reliability
coordinator comply with interconnection-wide procedures, once they are
implemented, to curtail transactions that cross interconnection
boundaries.
45. Proposed Requirement R5 directs balancing authorities and
reliability coordinators to comply with applicable interchange-related
Reliability Standards during the implementation of TLR procedures. NERC
proposes ``medium'' violation risk factors for Requirement R4 and
Requirement R5 explaining that, while failure to comply with these
requirements could lead the system to an unbalanced scenario, such
failure would not pose a ``high'' risk to the system.
46. Finally, NERC explains that four violation severity levels have
been assigned to Requirement R1 of IRO-006-4 based on the number of
violations of interconnection-wide procedure requirements, and these
levels are intended to base violation severity on the degree of
deviation from the requirements by the violator. NERC states that there
is a single violation severity level for each of the remaining
requirements (i.e., R2, R3, R4, and R5), because an entity simply
either ``passes'' or ``fails'' each of these requirements.
c. Commission Proposal
47. The Commission proposes to approve Reliability Standard IRO-
006-4 as just, reasonable, not unduly discriminatory or preferential,
and in the public interest. In addition, the Commission proposes to
direct the ERO to modify certain violation risk factors that correspond
to the Requirements of the Reliability Standard.
i. Requirements
48. NERC's proposal implements the Commission's directives (1) to
include a clear warning that the TLR procedure is an inappropriate and
ineffective tool to mitigate actual IROL violations; and (2) to
identify in a requirement the available alternatives to mitigate an
IROL violation. Specifically, Requirement R1.1 of IRO-006-4 states,
``The TLR procedure alone is an inappropriate and ineffective tool to
mitigate an IROL violation due to the time required to implement the
procedure. Other acceptable and more effective procedures to mitigate
actual IROL violations include: reconfiguration, redispatch, or load
shedding.'' The Commission proposes to approve this standard based on
the interpretation that using a TLR procedure alone to mitigate an IROL
violation is a violation of the Reliability Standard.
49. Further, the proposed division between NERC and NAESB business
practices seems to be reasonable and appears to pose no harm to
reliability. The Commission has long supported the coordination of
business practices and Reliability Standards. As early as May 2002, the
Commission urged the industry expeditiously to establish the procedures
for ensuring coordination between NAESB and NERC.\38\ The Commission
asks for comments on whether any compromise in the reliability of the
Bulk-Power System may result from the removal and transfer to NAESB of
the business-related issues formerly contained in Reliability Standard
IRO-006.
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\38\ Electricity Market Design and Structure, 99 FERC ] 61,171,
at P 22 (2002); see also Standards for Business Practices and
Communication Protocols for Public Utilities, Order No. 676, FERC
Stats. & Regs. ] 31,216, at P 6 (2006).
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ii. Violation Risk Factors
50. Violation risk factors delineate the relative risk to the Bulk-
Power System associated with the violation of each Requirement and are
used by NERC and the Regional Entities to determine financial penalties
for violating a Reliability Standard. NERC assigns a lower, medium, or
high violation risk factor for each mandatory Reliability Standard
Requirement.\39\ The Commission also established guidelines for
evaluating the validity of each Violation Risk Factor assignment.\40\
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\39\ The definitions of ``high,'' ``medium,'' and ``lower'' are
provided in North American Electric Reliability Corp., 119 FERC ]
61,145, at P 9 (Violation Risk Factor Order), order on reh'g, 120
FERC ] 61,145 (2007) (Violation Risk Factor Rehearing).
\40\ The guidelines are: (1) Consistency with the conclusions of
the Blackout Report; (2) consistency within a Reliability Standard;
(3) consistency among Reliability Standards; (4) consistency with
NERC's definition of the violation risk factor level; and (5)
treatment of requirements that co-mingle more than one obligation.
The Commission also explained that this list was not necessarily
all-inclusive and that it retains the flexibility to consider
additional guidelines in the future. A detailed explanation is
provided in Violation Risk Factor Rehearing, 120 FERC ] 61,145 at P
8-13.
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[[Page 22863]]
51. The Commission is concerned regarding the violation risk
factors submitted with IRO-006-4. While the approved violation risk
factors for IRO-006-0 Requirement R2 through Requirement R6 are all
``high,'' \41\ NERC proposes to revise violation risk factors for
similarly-worded Requirements R1 through R5 of IRO-006-4 to ``lower''
or ``medium.'' Sub-requirements R1.1 through R1.3 are explanatory text;
therefore, we propose that a violation risk factor need not be assigned
to them. For consistency with the Commission's five guidelines
discussed above, the Commission proposes to direct the ERO to modify
the violation risk factors assigned to Requirements R1 through R4 to
``high.'' We discuss our concerns below.
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\41\ The violation risk factors for these requirements were
submitted by NERC on February 23, 2007, and they were approved in
the Violation Risk Factor Order.
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52. The Commission disagrees with the ERO that Requirement R1 is
administrative in nature in describing how a reliability coordinator
may choose a procedure to provide transmission loading relief.
Requirement R1, as well as Requirement R2 through R4, goes beyond
merely providing procedural choices for transmission loading relief, as
the ERO asserts. Requirements R1 through R4 require that a reliability
coordinator choose and follow the appropriate procedure to provide
relief. If the reliability coordinator chooses an unapproved and
ineffective procedure for relief or fails to choose a procedure
entirely, potential or actual IROLs will not be mitigated as intended
by the reliability coordinator. Failure to implement the proper TLR
procedure likely would lead to IROL violations, which could lead to
cascading outages. The implementation of the TLR procedure shares a
similar reliability goal as other Reliability Standard requirements
that keep the transmission system within IROLs, thus presenting a
similar reliability risk and violation risk factor, if violated.
53. With respect to IRO-006-4, Requirement R1, the ERO states that,
provided the reliability coordinator is adhering to the requirements in
IRO-005-1, there is no significant risk to the reliability of the Bulk-
Power System as a result of a violation of Requirement R1 of IRO-006-4.
We disagree. The violation risk factor of a requirement represents the
risk a violation of that requirement presents to the reliability of the
Bulk-Power System. Violation risk factors should not be assigned
differently for requirements in separate Reliability Standards based on
compliance with another standard. Two requirements either achieve
separate reliability goals and, therefore, violation of them represents
independent risks, or two requirements share the same reliability goal.
As stated in Guideline 3 of the Violation Risk Factor Order,\42\ the
Commission expects that the assignment of violation risk factors
corresponding to requirements that address similar reliability goals in
different Reliability Standards would be treated comparably.
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\42\ 119 FERC ] 61,145 at P 25.
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54. Furthermore, a ``high'' violation risk factor assignment for
Requirements R1 through R4 is consistent with findings of the Final
Blackout Report. The report highlights that, generally, ``TLRs are
intended as a tool to prevent the system from being operated in an
unreliable state and are not applicable in real-time emergency
situations.'' \43\ As a result, Recommendation No. 31 in the Final
Blackout Report was developed to clarify that the TLR procedure should
not be used in situations involving an actual violation of an operating
security limit.
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\43\ Final Blackout Report at 62.
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55. A medium or lower violation risk factor has been approved for
the Reliability Standards in the Interchange Scheduling and
Coordination (INT) family of Reliability Standards. Requirement R5 of
IRO-006-4 complements the INT group of Reliability Standards and, thus,
appears to be appropriately assigned a medium violation risk factor.
56. The added ``Measures'' and other revisions embedded in proposed
Reliability Standard IRO-006-4 do not appear to substantively change
the earlier, Commission-approved version (i.e., IRO-006-3).
57. In summary, proposed Reliability Standard IRO-006-4 appears to
be just, reasonable, not unduly discriminatory or preferential, and in
the public interest. Accordingly, the Commission proposes to approve
Reliability Standard IRO-006-4 as mandatory and enforceable. In
addition, the Commission proposes to direct the ERO to modify the
violation risk factors, as described above.\44\
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\44\ Although ``time horizons,'' which relate to the immediacy
of the risk posed by a violation of a requirement, are included in
this Reliability Standard, we do not propose to rule on the time
horizons in this rulemaking. On March 3, 2008, in Docket No. RR08-4-
000, NERC submitted proposed violation severity levels corresponding
to the Requirements of 83 Commission-approved Reliability Standards.
The Commission will address the violation severity levels regarding
IRO-006-4 in that proceeding.
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C. NERC's December 26, 2007 Filing: Modification to Five ``Interchange
and Scheduling'' Reliability Standards
58. NERC submitted for Commission approval proposed modifications
to five Reliability Standards from the INT group of Reliability
Standards.
1. INT-001-3--Interchange Information and INT-004-2--Dynamic
Interchange Transaction Modifications
a. Background
59. The Interchange Scheduling and Coordination or ``INT'' group of
Reliability Standards address interchange transactions, which occur
when electricity is transmitted from a seller to a buyer across the
power grid. Reliability Standard INT-001 applies to purchasing-selling
entities and balancing authorities. The stated purpose of this
Reliability Standard is to ``ensure that Interchange Information is
submitted to the NERC-identified reliability analysis service.''
Reliability Standard INT-004 is intended to ``ensure Dynamic Transfers
are adequately tagged to be able to determine their reliability
impacts.''
60. In Order No. 693, the Commission approved the currently
applicable version of these Reliability Standards, INT-001-2 and INT-
004-1.\45\ Further, when NERC initially submitted these two Reliability
Standards for Commission approval, NERC also asked the Commission to
approve a ``regional difference'' that would exempt WECC from
requirements related to tagging dynamic schedules and inadvertent
payback provisions of INT-001-2 and INT-004-1. The Commission, in Order
No. 693, stated that it did not have sufficient information to address
the ERO's proposed regional difference and directed the ERO to submit a
filing either withdrawing the regional difference or providing
additional information needed for the Commission to make a
determination on the matter.\46\ The effect of NERC's December 26, 2007
filing is to withdraw the regional difference with respect to WECC.
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\45\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 821, 843.
In addition, the Commission directed that the ERO develop
modifications to INT-001-2 and INT-004-1 that address the
Commission's concerns.
\46\ Id. P 825.
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[[Page 22864]]
b. NERC's Proposed Modifications
61. In May 2007, WECC requested that NERC rescind the regional
difference, referred to as e-tagging waivers,\47\ for Reliability
Standards INT-001-2 and INT-004-1. According to NERC, WECC has
developed business practices for dynamic schedules and has taken the
steps needed to comply with the e-tagging of inadvertent payback
interchange schedules. Thus, WECC determined that it no longer needs
the e-tagging waivers.
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\47\ An E-tag represents a transaction on the North American
bulk electricity market scheduled to flow within, between, or across
electric utility company territories electronically. This is done so
that transmission system operators can ascertain all of the
transactions impacting their local system and take any corrective
actions to alleviate situations that could put the power grid at
risk of damage or collapse.
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62. NERC processed WECC's request through NERC's Reliability
Standard Development Procedure, using its urgent action process.\48\
NERC states that, by rescinding the e-tagging waivers, NERC maintains
uniformity and makes no structural changes to the requirements in the
current Commission-approved version of the Reliability Standards.
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\48\ NERC December 26, 2007 Filing at 5-6.
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c. Commission Proposal
63. NERC states that simply rescinding these waivers will not
result in structural changes to the requirements in the current
Commission-approved version of the Reliability Standards and will
maintain uniformity. Further, we note that WECC agrees that it no
longer needs to retain the waivers.\49\ Accordingly, the Commission
proposes to approve INT-001-3 and INT-004-2.
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\49\ Id.
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2. INT-005-2--Interchange Authority Distributes Arranged Interchange
a. INT-006-2--Response to Interchange Authority, and INT-008-2--
Interchange Authority Distributes Status
i. Background
64. In Order No. 693, the Commission approved the entire group of
INT Reliability Standards.\50\
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\50\ In addition, the Commission directed the ERO to develop
modifications to INT-006-1. The Commission-directed modifications
are not included in the immediate filing; rather, the ERO will
develop such modifications pursuant to its Reliability Standards
Development Plan 2008-2010.
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65. Reliability Standard INT-005-1 applies to the interchange
authority. The stated purpose of proposed Reliability Standard INT-005-
1 is to ``ensure that the implementation of Interchange between Source
and Sink Balancing Authorities is distributed by an Interchange
Authority such that Interchange information is available for
reliability assessments.''
66. Reliability Standard INT-006-1 applies to balancing authorities
and transmission service providers. The stated purpose of the
Reliability Standard is to ``ensure that each Arranged Interchange is
checked for reliability before it is implemented.''
67. Reliability Standard INT-008-1 applies to the interchange
authority. The stated purpose of the Reliability Standard is to
``ensure that the implementation of Interchange between Source and Sink
Balancing Authorities is coordinated by an Interchange Authority.''
This means that it is the interchange authorities' responsibility to
oversee and coordinate the interchange from one balancing authority to
another.
ii. NERC's Proposed Modifications
68. In its December 26, 2007 filing, NERC addresses a specific
reliability need identified by WECC in its urgent action request.
69. Requirement R1.4 of INT-007-1 requires that each balancing
authority and transmission service provider provide confirmation to the
interchange authority that it has approved the transactions for
implementation. NERC states that for WECC the timeframe allotted for
this assessment is five minutes in the original version of the
Commission-approved Reliability Standards.
70. NERC explains that the proposed Reliability Standards for INT-
005-2, INT-006-2, and INT-008-2 would increase the timeframe for
applicable WECC entities to perform the reliability assessment from
five to ten minutes for next hour interchange tags submitted in the
first thirty minutes of the hour before. According to NERC, this
modification is needed because the majority of next-hour tags in WECC
are submitted between xx:00 and xx:30. NERC explains that the existing
five minute assessment window makes it nearly impossible for balancing
authorities and transmission service providers to review each tag
before the five minute assessment time expires. NERC maintains that,
when the time expires, the tags are denied and must be resubmitte
