[Federal Register: April 28, 2008 (Volume 73, Number 82)]
[Proposed Rules]
[Page 22856-22867]
[DOCID:fr28ap08-21]

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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.

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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: http://www.ferc.gov. Documents created
electronically using word processing software should be filed in native
applications or print-to-PDF format and not in a scanned format.
     Mail/Hand Delivery: Commenters unable to file comments
electronically must mail or hand deliver 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:

                            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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    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, http://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

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.)

    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 http://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

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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    \35\ Order No. 672, FERC Stats. & Regs. ] 31,204 at P 326.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \42\ 119 FERC ] 61,145 at P 25.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \43\ Final Blackout Report at 62.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \48\ NERC December 26, 2007 Filing at 5-6.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \49\ Id.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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\
---------------------------------------------------------------------------

    \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 http://www.wecc.biz.
---------------------------------------------------------------------------

    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 Requirements of Four Reliability Standards.
    Action: Proposed Collection.
    OMB Control No.: 1902-0244.
    Respondents: Businesses or other for-profit 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:<PHONE_NUMBER>, e-mail<EMAIL_ADDRESS>    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<PHONE_NUMBER>, fax:<PHONE_NUMBER>, e-
mail<EMAIL_ADDRESS>
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 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.
---------------------------------------------------------------------------

    \57\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \58\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \59\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

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 http://
www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format.

Commenters filing electronically do not need to make a paper filing.
    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.

VII. Document Availability

    88. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.
    89. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    90. User assistance is available for eLibrary and the FERC's
website during normal business hours from FERC Online Support at (202)
502-6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
List of Subjects in 18 CFR Part 40

    Electric power, Electric utilities, Reporting and recordkeeping
requirements.

    By direction of the Commission.
    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 Notice of Proposed Rulemaking (NOPR)
proposing to approve, among other matters, modified Reliability
Standard IRO-006-4 pertaining to transmission loading relief (TLR)
procedures that can be used to prevent or manage potential or actual
transmission line limit violations when the transmission system is
congested. An earlier version of this Reliability Standard, IRO-006-3,
was approved in Order No. 693 subject to modification.\60\ This
Reliability Standard establishes a detailed TLR process for use in the
Eastern Interconnection to alleviate loadings on the system by
curtailing or changing transmission transactions based on their
priorities and the severity of the transmission congestion. However,
the Commission directed the ERO \61\ 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,
and (2) identify in a requirement the available alternatives to
mitigate an IROL violation other than use of the TLR procedure.\62\
---------------------------------------------------------------------------

    \60\ 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 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.
---------------------------------------------------------------------------

    Reliability Standard IRO-006-4 contains the required warning that
the TLR procedure alone is an inappropriate and ineffective tool to
mitigate an IROL violation due to the time required to implement the
procedure. It furthers states that other acceptable and more effective
procedures to mitigate actual IROL violations include reconfiguration,
redispatch, or load shedding. Load 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:
---------------------------------------------------------------------------

    \63\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 335.

    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

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\
---------------------------------------------------------------------------

    \64\ Id at P 331-33.

    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


[Federal Register Volume 77, Number 79 (Tuesday, April 24, 2012)]
[Notices]
[Pages 24484-24485]
[FR Doc No: 2012-9779]

-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RM98-1-000]

Records Governing Off-the-Record Communications; Public Notice

    This constitutes notice, in accordance with 18 CFR 385.2201(b), of
the receipt of prohibited and exempt off-the-record communications.
    Order No. 607 (64 FR 51222, September 22, 1999) requires Commission
decisional employees, who make or receive a prohibited or exempt off-
the-record communication relevant to the merits of a contested
proceeding, to deliver to the Secretary of the Commission, a copy of
the communication, if written, or a summary of the substance of any
oral communication.
    Prohibited communications are included in a public, non-decisional
file associated with, but not a part of, the decisional record of the
proceeding. Unless the Commission determines that the prohibited
communication and any responses thereto should become a part of the
decisional record, the prohibited off-the-record communication will not
be considered by the Commission in reaching its decision. Parties to a
proceeding may seek the opportunity to respond to any facts or
contentions made in a prohibited off-the-record communication, and may
request that the Commission place the prohibited communication and
responses thereto in the decisional record. The Commission will grant
such a request only when it determines that fairness so requires. Any
person identified below as having made a prohibited off-the-record
communication shall serve the document on all parties listed on the
official service list for the applicable proceeding in accordance with
Rule 2010, 18 CFR 385.2010.
    Exempt off-the-record communications are included in the decisional
record of the proceeding, unless the communication was with a
cooperating agency as described by 40

CFR 1501.6, made under 18 CFR 385.2201(e)(1)(v).
    The following is a list of off-the-record communications recently
received by the Secretary of the Commission. The communications listed
are grouped by docket numbers in ascending order. These filings are
available for review at the Commission in the Public Reference Room or
may be viewed on the Commission's Web site at http://www.ferc.gov using
the eLibrary link. Enter the docket number, excluding the last three
digits, in the docket number field to access the document. For
assistance, please contact FERC, Online Support at
<EMAIL_ADDRESS>or toll free at<PHONE_NUMBER>, or for TTY,
contact<PHONE_NUMBER>.

------------------------------------------------------------------------
                                     Communication       Presenter or
            Docket No.                   date             requester
------------------------------------------------------------------------
Prohibited
    1. IS12-160-000/IS12-165-000.            3-7-12  Commission
                                                      Staff.\1\
    2. CP11-515-000..............            3-9-12  John Odland.\2\
    3. CP12-72-000...............           3-15-12  Michelle D. Sweet.
    4. CP11-515-000..............           3-16-12  John Odland.\3\
    5. CP11-515-000..............           3-22-12  Janice O'Keefe.\4\
    6. P-11858-000...............           3-26-12  Timothy Maw, CMCA.
Exempt:
    1. CP11-161-000..............          11-24-11  Commission
                                                      Staff.\5\
    2. CP11-161-000..............            3-2-11  Commission
                                                      Staff.\6\
    3. CP11-14-000...............           3-13-12  Commission
                                                      Staff.\7\
    4. CP12-19-000/CP12-20-000...           3-14-12  Commission
                                                      Staff.\8\
    5. CP07-52-000...............           3-15-12  Commission
                                                      Staff.\9\
    6. P-459-000.................           3-20-12  Hon. Vicky
                                                      Hartzler.
    7. CP12-11-000...............           3-20-12  Commission
                                                      Staff.\10\
    8. P-459-000.................           3-21-12  Hon. Roy Blunt
    9. CP12-11-000...............           3-26-12  Commission
                                                      Staff.\11\
    10. CP12-18-000..............           3-27-12  L. Girth, US Dept.
                                                      Interior.
    11. CP11-128-000.............           3-27-12  Hon. Kristen E.
                                                      Gillibrand.
    12. P-13417-000..............            4-5-12  Hon. Ron Johnson.
    13. ER11-4081-000/AD12-1-000.            4-9-12  Minnesota PUC.\12\
    14. ER12-1177-000............            4-9-12  Todd A.
                                                      Snitchler.\13\
    15. CP11-128-000.............            4-9-12  Hon. Brian Higgins
                                                      & Hon. Kathleen C.
                                                      Hochul.
------------------------------------------------------------------------
\1\ Email record.
\2\ Email record.
\3\ Email record.
\4\ Letter sent to each of the Commissioners.
\5\ Email record, covering the period of 11/24/11 to 2/22/12.
\6\ Meeting with Commission Staff.
\7\ Telephone record.
\8\ Email record.
\9\ Telephone record.
\10\ Telephone record.
\11\ Telephone record.
\12\ Letter signed by all Commissioners of the Minnesota Public
  Utilities Commission.
\13\ Letter signed by the Chairman of the Ohio Public Utilities
  Commission.

    Dated: April 17, 2012.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2012-9779 Filed 4-23-12; 8:45 am]
BILLING CODE 6717-01-P