Document ID: FERC-2008-0605-0003
Agency: ferc
Document Type: 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: 2008-07-28T04:00Z

[Federal Register: July 28, 2008 (Volume 73, Number 145)]
[Rules and Regulations]               
[Page 43613-43621]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr28jy08-3]                         

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM08-7-000; Order No. 713]

 
Modification of Interchange and Transmission Loading Relief 
Reliability Standards; and Electric Reliability Organization 
Interpretation of Specific Requirements of Four Reliability Standards

Issued July 21, 2008.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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SUMMARY: Pursuant to section 215 of the Federal Power Act, the Federal 
Energy Regulatory Commission (Commission) approves five of six modified 
Reliability Standards submitted to the Commission for approval by the 
North American

[[Page 43614]]

Electric Reliability Corporation (NERC). The Commission directs NERC to 
submit a filing that provides an explanation regarding one aspect of 
the sixth modified Reliability Standard submitted by NERC. The 
Commission also approves NERC's proposed interpretations of five 
specific requirements of Commission-approved Reliability Standards.

DATES: Effective Date: This rule will become effective August 27, 2008.

FOR FURTHER INFORMATION CONTACT:

Patrick Harwood (Technical Information), Office of Electric 
Reliability, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-6125, patrick.harwood@ferc.gov,
Christopher Daignault (Legal Information), Office of the General 
Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8286, christopher.daignault@ferc.gov.

SUPPLEMENTARY INFORMATION:

Final Rule

                            Table of Contents

                                                              Paragraph
                                                                 Nos.

I. Background..............................................            2
    A. EPAct 2005 and Mandatory Reliability Standards......            2
    B. NERC Filings........................................            6
    C. Notice of Proposed Rulemaking.......................           11
II. Discussion.............................................           13
    A. NERC's December 19, 2007 Filing: Interpretations of            13
     Reliability Standards.................................
        1. BAL-001-0--Real Power Balancing Control                    14
         Performance and BAL-003-0--Frequency Response and
         Bias..............................................
            a. Proposed Interpretation.....................           16
            b. Comments....................................           19
            c. Commission Determination....................           20
        2. Requirement R17 of BAL-005-0--Automatic                    23
         Generation Control................................
            a. Proposed Interpretation.....................           23
            b. Comments....................................           26
                i. Whether interpretation could decrease              26
                 accuracy of frequency and time error
                 measurements..............................
                ii. What conditions would preclude                    28
                 requirement to calibrate devices..........
                iii. Whether accuracy of devices is assured           30
                 by other requirements.....................
            c. Commission Determination....................           32
        3. Requirements R1 and R2 of VAR-002-1 Generator              35
         Operation for Maintaining Network Voltage
         Schedules.........................................
            a. Proposed Interpretations....................           35
            b. Comments....................................           39
            c. Commission Determination....................           40
    B. NERC's December 21, 2007 Filing: Modification of TLR           41
     Procedure.............................................
        1. Background......................................           42
        2. ERO TLR Filing, Reliability Standard IRO-006-4..           43
        3. NOPR............................................           44
        4. Comments........................................           45
        5. Commission Determination........................           46
    C. NERC's December 26, 2007 Filing: Modification to               51
     Five ``Interchange and Scheduling'' Reliability
     Standards.............................................
        1. INT-001-3--Interchange Information and INT-004-            52
         2--Dynamic Interchange Transaction Modifications..
            a. Comments....................................           56
            b. Commission Determination....................           57
        2. INT-005-2--Interchange Authority Distributes               58
         Arranged Interchange, INT-006-2--Response to
         Interchange Authority, and INT-008-2--Interchange
         Authority Distributes Status......................
            a. Comments....................................           66
            b. Commission Determination....................           67
III. Information Collection Statement......................           68
IV. Environmental Analysis.................................           71
V. Regulatory Flexibility Act..............................           72
VI. Document Availability..................................           73
VII. Effective Date and Congressional Notification.........           76

    Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. 
Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

    1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the 
Commission approves five of six modified Reliability Standards 
submitted to the Commission for review by the North American Electric 
Reliability Corporation (NERC). The five Reliability Standards pertain 
to interchange scheduling and coordination. The Commission directs NERC 
to submit a filing that provides an explanation regarding one aspect of 
the sixth modified Reliability Standard submitted by NERC, which 
pertains to transmission loading relief (TLR) procedures. The Final 
Rule also approves interpretations of five specific requirements of 
Commission-approved Reliability Standards.

I. Background

A. EPAct 2005 and Mandatory Reliability Standards

    2. Section 215 of the FPA requires a Commission-certified Electric 
Reliability Organization (ERO) to propose Reliability Standards for the 
Commission's review. Once approved by the Commission, the Reliability 
Standards may be enforced by the ERO, subject to Commission oversight, 
or by the Commission independently.\2\
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    \1\ 16 U.S.C. 824o (2006).
    \2\ See FPA 215(e)(3), 16 U.S.C. 824o(e)(3) (2006).
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    3. Pursuant to section 215 of the FPA, the Commission established a 
process to select and certify an ERO \3\ and,

[[Page 43615]]

subsequently, certified NERC as the ERO.\4\ 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.\5\ 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.
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    \3\ 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).
    \4\ 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 (DC Cir. Dec. 29, 2006).
    \5\ 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).
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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).\6\ 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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    \6\ 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.\7\ 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.\8\
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    \7\ NERC Rules of Procedure, Appendix 3A (Reliability Standards 
Development Procedure), at 26-27.
    \8\ We note that the NERC board of trustees approved the 
interpretations of Reliability Standards submitted by NERC for 
approval in this proceeding. However, Appendix 3A of NERC's Rules of 
Procedure is silent on NERC board of trustees approval of 
interpretations before they are filed with the regulatory authority. 
The Commission is concerned that NERC's Rules of Procedure do not 
properly reflect this approval step.
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B. NERC Filings

    6. As explained in the Notice of Proposed Rulemaking (NOPR),\9\ 
this rulemaking proceeding consolidates and addresses three NERC 
filings.
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    \9\ Modification of Interchange and Transmission Loading Relief 
Reliability Standards; and Electric Reliability Organization 
Interpretation of Specific Requirements of Four Reliability 
Standards, Notice of Proposed Rulemaking, 73 FR 22,856 (Apr. 28, 
2008), FERC Stats. & Regs. ] 32,632 (2008) (NOPR).
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    7. On December 19, 2007, NERC submitted for Commission approval 
five 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\ On April 15, 2008, NERC 
submitted a petition to withdraw the earlier request for approval of 
NERC's interpretation of BAL-003-0, Requirement R17, and instead to 
approve a second interpretation of Requirement R17 submitted by NERC in 
the April 15 filing.
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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. 
According to NERC, 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, the modified Reliability Standard includes changes 
directed by the Commission in Order No. 693 related to the 
appropriateness of using the TLR procedure to mitigate violations of 
interconnection reliability operating limits (IROL).\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'' (INT) 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 stated 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 Reliability Standards and interpretations addressed in 
this Final Rule are 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 proposed to interpret or 
modify in this proceeding was approved by the Commission in Order No. 
693.

C. Notice of Proposed Rulemaking

    11. On April 21, 2008, the Commission issued a NOPR that proposed 
to approve the six modified Reliability Standards submitted to the 
Commission for approval by NERC and to approve NERC's proposed 
interpretations of five specific requirements of Commission-approved 
Reliability Standards. On May 16, 2008, the Commission supplemented the 
NOPR,\14\ proposing to approve NERC's modified interpretation of 
Reliability Standard BAL-005-0, Requirement R17.
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    \14\ Modification of Interchange and Transmission Loading Relief 
Reliability Standards; and Electric Reliability Organization 
Interpretation of Specific Requirements of Four Reliability 
Standards, Supplemental Notice of Proposed Rulemaking, 73 FR 30,326 
(May 27, 2008), FERC Stats. & Regs. ] 32,635 (2008) (Supplemental 
NOPR).
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    12. In response to the NOPR, comments were filed by the following 
eight interested persons: Alcoa Inc. (Alcoa); Independent Electricity 
System Operator of Ontario (IESO); ISO/RTO Council; International 
Transmission Company, Michigan Electric Transmission Company, LLC and 
Midwest LLC (collectively, ITC); Lafayette Utilities and the Louisiana 
Energy and Power Authority (Lafayette

[[Page 43616]]

and LEPA); NERC; NRG Companies; \15\ and Southern Company Services, 
Inc. (Southern).
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    \15\ NRG Companies includes Louisiana Generating LLC, Bayou Cove 
Peaking Power, LLC, Big Cajun I Peaking Power, LLC, NRG Sterlington 
Power, LLC, and NRG Power Marketing, LLC.
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II. Discussion

A. NERC's December 19, 2007 Filing: Interpretations of Reliability 
Standards

    13. As mentioned above, NERC submitted for Commission approval 
interpretations of five specific requirements in four Commission-
approved Reliability Standards.
1. BAL-001-0--Real Power Balancing Control Performance and BAL-003-0--
Frequency Response and Bias
    14. 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.\16\ It uses two 
averages, covering the one-minute and ten-minute area control error 
(ACE) performance (CPS1 and CPS2, respectively), as measures for 
determining compliance with its four Requirements. Requirement R1 of 
BAL-001-0 obligates each balancing authority, on a rolling twelve-month 
basis, to maintain its clock-minute averages of ACE, modified by its 
frequency bias and the interconnection frequency, within a specific 
limit based on historic performance.\17\
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    \16\ See Reliability Standard BAL-001-0. Each Reliability 
Standard developed by the ERO includes a ``Purpose'' statement.
    \17\ Frequency bias is an approximation, expressed in megawatts 
per 0.1 Hertz, of the frequency response of a balancing authority 
area which estimates the net change in power from the generators 
that is expected to occur with a change in interconnection frequency 
from the scheduled frequency (which is normally 60 Hertz).
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    15. The purpose of Reliability Standard BAL-003-0 is to ensure that 
a balancing authority's frequency bias setting is accurately calculated 
to match its actual frequency response. Frequency bias may be 
calculated in a number of ways provided that the frequency bias is as 
close as practical to the frequency response. Requirement R3 of BAL-
003-0 requires each balancing authority to operate its automatic 
generation control on ``tie line frequency bias,'' unless such 
operation is adverse to system interconnection reliability.\18\
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    \18\ 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. North American Electric 
Reliability Corporation, 121 FERC ] 61,179, at P 19 n.14 (2007). 
``Tie line frequency bias'' is defined in the NERC Glossary of Terms 
Used in Reliability Standards as ``[a] mode of Automatic Generation 
Control that allows the Balancing Authority to 1.) maintain its 
Interchange Schedule and 2.) respond to Interconnection frequency 
error.''
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a. Proposed Interpretation
    16. In its December 19, 2007 filing, NERC explained that WECC 
requested the ERO to provide a formal interpretation whether the use of 
WECC's existing automatic time error correction factor that is applied 
to the net interchange portion of the ACE equation violates Requirement 
R1 of BAL-001-0 or Requirement R3 of BAL-003-0.
    17. In response, the ERO interpreted BAL-001-0 Requirement R1 as 
follows:
     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.
    The ERO interpreted BAL-003-0 Requirement R3 as follows:
     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, [and] time control (in single 
[balancing authority] interconnections).\19\
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    \19\ 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,\20\ there is no violation of BAL-003-0 Requirement 3:
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    \20\ ``CPS1'' refers to Requirement R1 of BAL-001-0.

ACE = (NIA-NIS)-10B (FA-
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FS)-IME

(NERC December 19, 2007 Filing, Ex. A-3.)

    18. In the NOPR, the Commission proposed to approve the ERO's 
formal interpretations of Requirement R1 of BAL-001-0 and Requirement 
R3 of BAL-003-0.
b. Comments
    19. NERC and IESO support the Commission's proposal to approve 
these interpretations.
c. Commission Determination
    20. The Commission approves the ERO's formal interpretations of 
Requirement R1 of BAL-001-0 and Requirement R3 of BAL-003-0. The ERO's 
interpretation of BAL-001-0, Requirement R1, is reasonable in that it 
requires all balancing authorities in WECC to calculate CPS1 and CPS2 
as defined in the Requirements. Thus, the interpretation upholds the 
reliability goal to minimize the frequency deviation of the 
interconnection by constantly balancing supply and demand.
    21. The ERO's interpretation of BAL-003-0, Requirement R3 is 
appropriate because it maintains the goal of Requirement R3 by 
obligating a balancing authority to operate automatic generation 
control on tie-line frequency bias as its underlying control mode, 
unless to do so is adverse to system or interconnection reliability. 
Further, the interpretation fosters the purpose of Requirement R3, as 
it allows that a balancing authority may go beyond Requirement R3 and 
``layer other control objectives on top of their basic control modes, 
such as automatic inadvertent payback, [control performance standard] 
optimization, [and] time control (in single [balancing authority] 
interconnections),'' \21\ although such layering is not required by the 
Reliability Standard.
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    \21\ NERC interpretation of BAL-003-0, Requirement R3.
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    22. For the reasons stated above, the Commission finds that the 
ERO's interpretations of Requirement R1 of BAL-001-0 and Requirement R3 
of BAL-003-0 are just, reasonable, not unduly discriminatory or 
preferential, and in the public interest. Accordingly, the Commission 
approves the ERO's interpretations.
2. Requirement R17 of BAL-005-0--Automatic Generation Control
a. Proposed Interpretation
    23. Requirement R17 of Reliability Standard BAL-005-0 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

[[Page 43617]]

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.
    24. On April 15, 2008, NERC submitted an interpretation of 
Requirement R17 regarding the type and location of the equipment to 
which Requirement R17 applies.\22\ The interpretation provides that 
BAL-005-0, Requirement R17
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    \22\ As mentioned earlier, in April 2008, NERC submitted a 
petition seeking to withdraw an earlier interpretation of 
Requirement R17 and substituting a new interpretation for Commission 
approval.

applies only to the time error and frequency devices that provide, 
or in the case of back-up equipment may provide, input into the 
reporting or compliance ACE equation or provide real-time time error 
or frequency information to the system operator. Frequency inputs 
from other sources that are for reference only are excluded. The 
time error and frequency measurement devices may not necessarily be 
located in the system operations control room or owned by the 
Balancing Authority; however the Balancing Authority has the 
responsibility for the accuracy of the frequency and time error 
devices * * *.
    New or replacement equipment that provides the same functions 
noted above requires the same calibrations. Some devices used for 
time error and frequency measurement cannot be calibrated as such. 
In this case, these devices should be cross-checked against other 
properly calibrated equipment and replaced if the devices do not 
meet the required level of accuracy.

    25. In a supplemental NOPR issued May 16, 2008, the Commission 
proposed to approve NERC's interpretation of BAL-005-0, Requirement 
R17. In addition, the Commission noted that tie-line megawatt metering 
data is an important aspect of ensuring the accurate calculation of 
ACE, and the interpretation limits the specific accuracy requirements 
of Requirement R17 to frequency and time error measurement devices. The 
Commission asked for comment on (1) whether the interpretation could 
decrease the accuracy of frequency and time error measurements by not 
requiring calibration of tie-line megawatt metering devices; (2) what 
conditions would preclude the requirement to calibrate these devices; 
and (3) whether the accuracy of these devices is assured by other 
requirements within BAL-005-0 in the absence of calibration.
b. Comments
i. Whether Interpretation Could Decrease Accuracy of Frequency and Time 
Error Measurements
    26. Southern, ITC, ISO/RTO Council, and NERC claim that the 
interpretation could not decrease the accuracy of frequency and time 
error measurements by not requiring calibration of tie-line megawatt 
metering devices because tie-line metering data is not an input to 
either time error or frequency measurements and has no impact on the 
accuracy of these devices. NERC further suggests that the Commission 
may have intended to ask whether the interpretation adversely affects 
the accuracy of the balancing authority ACE calculation. NERC provides 
that it does not, because calibration of tie-line metering historically 
was included in the guide section of NERC Operating Policy 1 and was 
not intended to be translated into a requirement. NERC asserts that 
calibration of tie-line metering remains a sound practice and there are 
safeguards, checks, and balances to ensure inadvertent flows in the 
interconnection equal zero, thus ensuring that errors in ACE are 
bounded to protect the interconnections.
    27. As a general comment on the proposed interpretation of 
Requirement R17, Southern suggests that the metering specifications 
table in Requirement R17 may be creating some confusion because the 
NERC committee that developed this Reliability Standard intended to 
include the frequency metering specifications from this table but 
inadvertently included other metering specifications that are not 
required to fulfill Requirement R17. Southern claims that Requirement 
R17 is intended to only address time error and frequency devices, and 
this table was added in error and should have been limited to 
specifications for those devices.
ii. What Conditions Would Preclude Requirement To Calibrate Devices
    28. NERC, ISO/RTO Council, and Southern claim that there are no 
conditions which would preclude the requirement to calibrate tie-line 
megawatt metering devices. NERC suggests that, if the question relates 
to a possible new requirement to calibrate all tie-line metering 
equipment on a given schedule, a new standards authorization request 
should be submitted through the Reliability Standards Development 
Process. NERC believes that the industry may not want to divert 
resources away from other important tasks unless a case can be made 
that calibration of these devices presents a risk to reliability. 
Similarly, ITC comments that, if the Commission believes it is 
necessary to annually calibrate the tie-line megawatt metering devices, 
such a requirement belongs in BAL-005-0 and not in Requirement R17. 
ISO/RTO Council claims such a requirement is unnecessary because it is 
redundant, not needed for reliability, and poses the possibility of 
financial sanctions for no good reason.
    29. ITC states that tie-line meters would be precluded from 
calibration requirements if they are digital devices that the equipment 
vendor has indicated do not require calibration. They claim that there 
are no field calibration procedures which can be performed by end-users 
for such devices. According to ITC, Requirement R17 of BAL-005-0 should 
recognize that there are modern digital devices that do not require 
calibration as analog devices do.
iii. Whether Accuracy of Devices Is Assured by Other Requirements
    30. NERC, ITC, ISO/RTO Council, and Southern state that tie-line 
metering accuracy is addressed by Requirement R13 of BAL-005-0, which 
requires each balancing authority to perform hourly error checks using 
tie-line megawatt-hour meters with common time synchronization to 
determine the accuracy of its control equipment and make adjustments 
accordingly. ITC claims that Requirement R13 of BAL-005-0 provides a 
more timely identification of errors than a requirement for annual 
calibration.
    31. NERC comments that tie-line metering accuracy is not assured by 
any other requirement. According to NERC, requirements relating to 
Reliability Standards BAL-005-0 and BAL-006-1, along with the 
associated NERC processes, provide several layers of overlapping 
protection to address tie-line accuracy. NERC further claims that BAL-
005-0 requires balancing authorities to operate in conformance with 
common metering equipment in comparison to that of their neighbors, so 
there is no net balancing authority error in the interconnection as a 
whole. In addition, NERC claims that many balancing authorities have 
secondary or backup metering on critical tie lines and have access to 
the NERC Resource Adequacy application, which can provide alerts to the 
balancing authority of tie-line metering errors.
c. Commission Determination
    32. The Commission approves the ERO's formal interpretation of 
Requirement R17 of BAL-005-0 as set forth in the ERO's April 2008 
filing. Based on the comments, we find that

[[Page 43618]]

this interpretation will not decrease the accuracy of frequency and 
time error measurements by not requiring calibration of tie-line 
megawatt metering devices. In addition, we are persuaded by the 
commenters that the need to calibrate tie-line megawatt metering 
devices is addressed by other requirements such as Requirement R13 that 
require hourly checks to ensure continuous accuracy. The Commission 
notes that the applicable requirement for the accuracy of calibration 
of tie-line megawatt metering devices is identified in Requirement R17. 
While Southern has stated that the metering specifications table in 
Requirement R17 was added in error, an interpretation cannot change the 
substance of a Reliability Standard. Notwithstanding the question of 
relevancy of particular components of the metering specifications 
table, the accuracy requirements of this table remain part of 
Reliability Standard BAL-005-0 as reference for mandatory reliability 
practices. The Commission encourages further clarification of tie-line 
metering device calibration requirements through the ERO standards 
development process.
    33. ITC comments that digital devices are precluded from the 
calibration requirement. We note that the interpretation provides that 
``[s]ome devices used for time error and frequency measurement cannot 
be calibrated as such. In this case, these devices should be cross-
checked against other properly calibrated equipment and replaced if the 
devices do not meet the required level of accuracy.'' Thus, while ITC's 
comment is accurate, the ERO's interpretation acknowledges the concern 
and provides a response, i.e., modern digital devices that cannot be 
calibrated must be cross-checked against other equipment and replaced 
if they do not meet the required level of accuracy.
    34. The ERO's interpretation of BAL-005-0, Requirement R17 provides 
that ``frequency inputs from other sources that are for reference only 
are excluded.'' The Commission notes that this Reliability Standard 
establishes requirements concerning the inputs to the ACE equation to 
correctly operate automatic generation control. Frequency inputs used 
for other purposes are not covered by this Reliability Standard. 
Therefore, we understand the ERO's interpretation to exclude frequency 
devices that do not provide input into the reporting or compliance with 
the ACE equation or provide real-time time error or frequency 
information to the system operator. Any devices that provide reference 
input from which a balancing authority calibrates other time error and 
frequency devices, however, do provide real-time time error and 
frequency information to the system operator and therefore must be 
calibrated under this requirement.
3. Requirements R1 and R2 of VAR-002-1 Generator Operation for 
Maintaining Network Voltage Schedules
a. Proposed Interpretations
    35. 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. Requirement R1 
ofVAR-002-1 provides:

    The Generator Operator shall operate each generator connected to 
the interconnected transmission system in the automatic voltage 
control mode (automatic voltage regulator in service and controlling 
voltage) unless the Generator Operator has notified the Transmission 
Operator.

    Requirement R2 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.

    36. The ERO received a request to provide a formal interpretation 
of Requirements R1 and R2. The request first asked whether automatic 
voltage regulator operation in the constant power factor or constant 
Mvar modes complies with Requirement R1. Second, the request asked the 
ERO whether Requirement R2 gives the transmission operator the option 
of directing the generation owner to operate the automatic voltage 
regulator in the constant power factor or constant Mvar modes rather 
than the constant voltage mode.
    37. NERC's formal interpretation provides that a generator operator 
that is operating its automatic voltage regulator in the constant power 
factor or constant Mvar modes does not comply with Requirement R1.\23\ 
The interpretation rests on the assumptions 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 gives the transmission operator the option of directing 
the generation operator to operate the automatic voltage regulator in 
the constant power factor or constant Mvar modes rather than the 
constant voltage mode.
---------------------------------------------------------------------------

    \23\ NERC's interpretation of VAR-002-1, Requirement R1 is 
quoted in full in the NOPR, FERC Stats. & Regs. ] 32,632 at P 32, 
n.27.
---------------------------------------------------------------------------

    38. In the NOPR, the Commission proposed to approve the ERO's 
interpretation of Requirement R1 and Requirement R2 of VAR-002-1.
b. Comments
    39. NERC and IESO support the Commission's proposal to approve the 
interpretation.
c. Commission Determination
    40. The Commission concludes that the interpretation is just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest. Therefore, the Commission approves the ERO's 
interpretation of Requirements R1 and R2 of VAR-002-1.

B. NERC's December 21, 2007 Filing: Modification of TLR Procedure

    41. NERC submitted for Commission approval proposed Reliability 
Standard IRO-006-4, which modifies the Commission-approved Reliability 
Standard, IRO-006-3.
1. Background
    42. In Order No. 693, the Commission approved an earlier 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 established a detailed TLR 
procedure 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. The 
Reliability Standard referenced other procedures for WECC and Electric 
Reliability Council of Texas (ERCOT).\24\
---------------------------------------------------------------------------

    \24\ The equivalent interconnection-wide TLR procedures for use 
in WECC and ERCOT are known as ``WSCC Unscheduled Flow Mitigation 
Plan'' and section 7 of the ``ERCOT Protocols,'' respectively.
---------------------------------------------------------------------------

2. ERO TLR Filing, Reliability Standard IRO-006-4
    43. In its December 2007 filing, NERC submitted for Commission 
approval a modified TLR procedure, Reliability Standard IRO-006-4, 
which contains five requirements. Requirement R1 obligates a 
reliability coordinator experiencing a potential or actual system 
operating limit (SOL) or IROL

[[Page 43619]]

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 ERCOT.
3. NOPR
    44. In the NOPR, the Commission proposed to approve IRO-006-4 as 
just, reasonable, not unduly discriminatory or preferential, and in the 
public interest.\25\ The Commission also proposed to approve the 
Reliability Standard based on the interpretation that using a TLR 
procedure to mitigate an IROL violation is a violation of the 
Reliability Standard. The Commission asked 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-006-3. In addition, the 
Commission proposed to direct the ERO to modify the violation risk 
factors assigned to Requirements R1 through R4 by raising them to 
``high.''
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    \25\ NOPR, FERC Stats. & Regs. ] 32,632 at P 48.
---------------------------------------------------------------------------

4. Comments
    45. The Commission received comments on the NOPR proposal. Because 
the Final Rule does not approve or remand the proposed Reliability 
Standard and, rather, directs the ERO to submit a filing that provides 
an explanation regarding specific language of one requirement of IRO-
006-4, the Commission will address the comments in a future issuance in 
this proceeding.
5. Commission Determination
    46. Because the Commission has concern regarding the understanding 
of certain language of Requirements R1 and R1.1 of IRO-006-4, the 
Commission is not approving or remanding the proposed Reliability 
Standard at this time. Rather, the Commission directs that the ERO, 
within 15 days of the effective date of this Final Rule, submit a 
filing that provides an explanation regarding specific language of 
Requirements R1 and R1.1 of IRO-006-4. The Commission will then issue a 
notice allowing public comment on the ERO's filing, and will act on the 
proposed Reliability Standard in a future issuance in this proceeding.
    47. In the Final Blackout Report, an international team of experts 
studying the causes of the August 2003 blackout in North America 
recommended that NERC ``[c]larify that the transmission loading relief 
(TLR) process should not be used in situations involving an actual 
violation of an Operation Security Limit.'' \26\ Based on the Final 
Blackout Report recommendation, the Commission, in Order No. 693, 
directed NERC to develop a modification to the TLR procedure (IRO-006-
3) that ``(1) includes a clear warning that the TLR procedure is an 
inappropriate and ineffective tool to mitigate actual IROL violations 
and (2) identifies in a Requirement the available alternatives to 
mitigate an IROL violation other than use of the TLR procedure.'' \27\
---------------------------------------------------------------------------

    \26\ See 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) (Recommendation 31).
    \27\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 577, 
964.
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    48. In response to this directive, NERC proposed in Requirement 
R1.1 of IRO-006-4 that ``[t]he TLR procedure [for the Eastern 
Interconnection] alone is an inappropriate and ineffective tool to 
mitigate an IROL violation due to the time required to implement the 
procedure.'' (Emphasis added.) The Commission is concerned whether this 
language is adequate to satisfy the concern of the Final Blackout 
Report and Order No. 693. Specifically, we note that the use of the 
term ``alone'' seems to imply that a TLR procedure could be used in 
response to an actual violation of an IROL whereas the Final Blackout 
Report recommendation would prevent the use of the TLR procedure in 
such situations. Moreover, Requirement R1 of IRO-006-4 further appears 
to contradict the Final Blackout Report recommendation by allowing a 
reliability coordinator to implement transmission loading relief 
procedures to mitigate not only potential SOL or IROL violations but 
also actual SOL or IROL violations.\28\ The Commission is concerned 
that Recommendation 31 of the Final Blackout Report and the directive 
in Order No. 693, both of which state the TLR procedures should not be 
used in situations involving an actual violation of an IROL, may not be 
clearly addressed in the proposed Reliability Standard.
---------------------------------------------------------------------------

    \28\ Requirement R1 provides that ``[a] reliability Coordinator 
experiencing a potential or actual SOL or IROL violation within its 
Reliability Coordinator Area shall, with its authority and at its 
discretion, select one or more procedures to provide transmission 
loading relief. This procedure can be a ``local'' * * * transmission 
loading relief procedure or one of the following Interconnection-
wide procedures.* * *'' Sub-requirement R1.1 provides that ``[t]he 
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.''
---------------------------------------------------------------------------

    49. The Commission notes that an entity is not prevented from using 
the TLR procedure to avoid a potential IROL violation before a 
violation occurs. If, while a TLR procedure is in progress, an IROL 
violation occurs, it is not necessary for the entity to terminate the 
TLR procedure. However, the Commission believes that it is 
inappropriate and ineffective to rely on the TLR procedure, even in 
conjunction with another tool, to address an actual IROL violation.
    50. Therefore, the Commission does not approve or remand IRO-006-4. 
Rather, the Commission directs the ERO to submit a filing, within 15 
days of the effective date of this Final Rule, that provides an 
explanation regarding Requirements R1 and R1.1 of IRO-006-4. 
Specifically, in light of the above discussion, the Commission directs 
the ERO to provide an explanation regarding the phrase ``[t]he TLR 
procedure alone is an inappropriate and ineffective tool to mitigate an 
IROL violation * * *'' Further, the ERO should explain whether 
Requirements R1 and R1.1 only allow the TLR procedure to be continued 
when already deployed prior to an actual IROL violation or, 
alternatively, whether Requirements R1 and R1.1 allow use of the TLR 
procedure as a tool to address actual violations after they occur. If 
the latter, the ERO is directed to explain why this application is not 
contrary to both Blackout Report Recommendation 31 and the Commission's 
determination in Order No. 693. The ERO's filing should include an 
explanation of those actions that are acceptable, and those that are 
unacceptable, pursuant to Requirement R1 and R1.1.

C. NERC's December 26, 2007 Filing: Modification to Five ``Interchange 
and Scheduling'' Reliability Standards

    51. 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
    52. 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 
Bulk-Power System. Reliability Standard INT-001 applies to purchasing-
selling entities and balancing authorities. The stated purpose of the 
Reliability Standard is to ``ensure that Interchange Information is 
submitted to the NERC-identified reliability analysis service.'' 
Reliability

[[Page 43620]]

Standard INT-004 is intended to ``ensure Dynamic Transfers are 
adequately tagged to be able to determine their reliability impacts.''
    53. In Order No. 693, the Commission approved earlier versions of 
these Reliability Standards, INT-001-2 and INT-004-1.\29\ Further, when 
NERC initially (in April 2006) 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.\30\ The effect of NERC's December 26, 2007 
filing is to withdraw the regional difference with respect to WECC.
---------------------------------------------------------------------------

    \29\ 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.
    \30\ Id. P 825.
---------------------------------------------------------------------------

    54. In its December 26, 2007 filing, NERC stated 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.
    55. In the NOPR, the Commission proposed to approve INT-001-3 and 
INT-004-2.
a. Comments
    56. NERC and the IESO support the Commission's proposal to approve 
these Reliability Standards.
b. Commission Determination
    57. Pursuant to section 215(d) of the FPA, the Commission approves 
Reliability Standards INT-001-3 and INT-004-2 as mandatory and 
enforceable.
2. INT-005-2--Interchange Authority Distributes Arranged Interchange, 
INT-006-2--Response to Interchange Authority, and INT-008-2--
Interchange Authority Distributes Status
    58. 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.''
    59. 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.''
    60. 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 an interchange authority's responsibility to 
oversee and coordinate the interchange from one balancing authority to 
another.
    61. In its December 26, 2007 filing, NERC addressed a reliability 
need identified by WECC in its urgent action request. Specifically, 
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 stated that for WECC the timeframe allotted for 
this assessment is five minutes in the original version of the 
Commission-approved Reliability Standards.
    62. Reliability Standards for INT-005-2, INT-006-2, and INT-008-2 
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 and xx:30. 
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. According to 
NERC, when the time expires, the tags are denied and must be 
resubmitted.
    63. In its December 26, 2007 filing, NERC stated 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 stated 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.
    64. NERC noted 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.
    65. In the NOPR, the Commission proposed to approve INT-005-2, INT-
006-2, and INT-008-2.
a. Comments
    66. NERC and IESO support the Commission's proposal to approve 
these Reliability Standards.
b. Commission Determination
    67. Pursuant to section 215(d) of the FPA, the Commission approves 
Reliability Standards INT-005-2, INT-006-2, and INT-008-2 as mandatory 
and enforceable.\31\
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    \31\ 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

    68. The Office of Management and Budget (OMB) regulations require 
that OMB approve certain reporting and recordkeeping (collections of 
information) imposed by an agency.\32\ The information contained here 
is also subject to review under section 3507(d) of the Paperwork 
Reduction Act of 1995.\33\ As stated above, the Commission previously 
approved, in Order No. 693, each of the Reliability Standards that are 
the subject of the current rulemaking. In the NOPR, the Commission 
explained that the modifications to the Reliability Standards are minor 
and the interpretations relate to existing Reliability Standards; 
therefore, they do not add to or increase entities' reporting burden. 
Thus, in the NOPR, the Commission stated that the modified Reliability 
Standards and interpretations of Reliability Standards do not 
materially affect the burden estimates relating to the earlier version 
of the Reliability Standards presented in Order No. 693.\34\
---------------------------------------------------------------------------

    \32\ 5 CFR 1320.11.
    \33\ 44 U.S.C. 3507(d).
    \34\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1905-
07. The NOPR, FERC Stats. & Regs. ] 32,632 at P 76-78, provided a 
detailed explanation why each modification and interpretation has a 
negligible, if any, effect on the reporting burden.
---------------------------------------------------------------------------

    69. In response to the NOPR, the Commission received no comments 
concerning its estimate for the burden and costs and therefore uses the 
same estimate here.

[[Page 43621]]

    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 Final Rule approves five 
modified Reliability Standards that pertain to interchange scheduling 
and coordination. It directs NERC to make a filing with the Commission 
regarding one modified Reliability Standard that pertains to 
transmission loading relief procedures. In addition, the Final Rule 
approves interpretations of five specific requirements of Commission-
approved Reliability Standards. The Final Rule finds the Reliability 
Standards and interpretations just, reasonable, not unduly 
discriminatory or preferential, and in the public interest.
    70. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, Attn: 
Michael Miller, Office of the Executive Director, 888 First Street, 
NE., Washington, DC 20426, Tel: (202) 502-8415, Fax: (202) 273-0873, E-
mail: michael.miller@ferc.gov, or by contacting: Office of Information 
and Regulatory Affairs, Attn: Desk Officer for the Federal Energy 
Regulatory Commission (Re: OMB Control No. 1902-0244), Washington, DC 
20503, Tel: (202) 395-4650, Fax: (202) 395-7285, E-mail: oira_
submission@omb.eop.gov.

IV. Environmental Analysis

    71. 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.\35\ 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.\36\ The actions proposed 
herein fall within this categorical exclusion in the Commission's 
regulations.
---------------------------------------------------------------------------

    \35\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \36\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act

    72. The Regulatory Flexibility Act of 1980 (RFA) \37\ 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 Final Rule because 
the minor modifications and interpretations discussed herein will not 
have a significant economic impact on a substantial number of small 
entities.
---------------------------------------------------------------------------

    \37\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

VI. Document Availability

    73. 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.
    74. 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.
    75. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC Online Support at (202) 
502-6652 (toll free at 1-866-208-3676) or e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

VII. Effective Date and Congressional Notification

    76. These regulations are effective August 27, 2008. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 40

    Electric power, Electric utilities, Reporting and recordkeeping 
requirements.

    By the Commission.
 Nathaniel J. Davis, Sr.,
 Deputy Secretary.
 [FR Doc. E8-17196 Filed 7-25-08; 8:45 am]

BILLING CODE 6717-01-P