Document ID: FERC-2008-0605-0001
Agency: ferc
Document Type: Proposed Rule
Title: Modification of Interchange and Transmission Loading Relief Reliability Standards; and Electric Reliability Organization Interpretation of Specific Requirements of Four Reliability Standards
Posted Date: 2008-04-28T04:00Z

[Federal Register: April 28, 2008 (Volume 73, Number 82)]
[Proposed Rules]               
[Page 22856-22867]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[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:

[[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, 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

[[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 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

[[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\
---------------------------------------------------------------------------

    \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

[[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.
---------------------------------------------------------------------------

    \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.

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

[[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.
---------------------------------------------------------------------------

    \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.

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

[[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.
---------------------------------------------------------------------------

    \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

[[Page 22865]]

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: (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 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.
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    \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).
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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.
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    \59\ 5 U.S.C. 601-12.
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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.

[[Page 22866]]

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 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

List of Subjects in 18 CFR Part 40

    Electric power, Electric utilities, Reporting and recordkeeping 
requirements.

    By direction of the Commission.
    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\
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    \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.
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    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:
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    \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

[[Page 22867]]

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\
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    \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