[Federal Register Volume 72, Number 64 (Wednesday, April 4, 2007)]
[Rules and Regulations]
[Pages 16416-16602]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-5284]



[[Page 16415]]

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Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 40



Mandatory Reliability Standards for the Bulk-Power System; Final Rule

  Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules 
and Regulations  

[[Page 16416]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM06-16-000; Order No. 693]


Mandatory Reliability Standards for the Bulk-Power System

Issued March 16, 2007.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: Pursuant to section 215 of the Federal Power Act (FPA), the 
Commission approves 83 of 107 proposed Reliability Standards, six of 
the eight proposed regional differences, and the Glossary of Terms Used 
in Reliability Standards developed by the North American Electric 
Reliability Corporation (NERC), which the Commission has certified as 
the Electric Reliability Organization (ERO) responsible for developing 
and enforcing mandatory Reliability Standards. Those Reliability 
Standards meet the requirements of section 215 of the FPA and Part 39 
of the Commission's regulations. However, although we believe it is in 
the public interest to make these Reliability Standards mandatory and 
enforceable, we also find that much work remains to be done. 
Specifically, we believe that many of these Reliability Standards 
require significant improvement to address, among other things, the 
recommendations of the Blackout Report. Therefore, pursuant to section 
215(d)(5), we require the ERO to submit significant improvements to 56 
of the 83 Reliability Standards that are being approved as mandatory 
and enforceable. The remaining 24 Reliability Standards will remain 
pending at the Commission until further information is provided.
    The Final Rule adds a new part to the Commission's regulations, 
which states that this part applies to all users, owners and operators 
of the Bulk-Power System within the United States (other than Alaska or 
Hawaii) and requires that each Reliability Standard identify the subset 
of users, owners and operators to which that particular Reliability 
Standard applies. The new regulations also require that each 
Reliability Standard that is approved by the Commission will be 
maintained on the ERO's Internet Web site for public inspection.

EFFECTIVE DATE: This rule will become effective June 4, 2007.

FOR FURTHER INFORMATION CONTACT: Jonathan First (Legal Information), 
Office of the General Counsel, Federal Energy Regulatory Commission, 
888 First Street, NE., Washington, DC 20426, (202) 502-8529.
    Paul Silverman (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8683.
    Robert Snow (Technical Information), Office of Energy Markets and 
Reliability, Division of Reliability, Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
6716.
    Kumar Agarwal (Technical Information), Office of Energy Markets and 
Reliability, Division of Policy Analysis and Rulemaking, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
(202) 502-8923.

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

                            Table of Contents
 
                                                               Paragraph
 
I. Introduction.............................................           1
    A. Background...........................................           3
        1. EPAct 2005 and Order No. 672.....................           3
        2. NERC Petition for Approval of Reliability                  12
         Standards..........................................
        3. Staff Preliminary Assessment and Commission NOPR.          15
        4. Notice of Proposed Rulemaking....................          17
II. Discussion..............................................          21
    A. Overview.............................................          21
        1. The Commission's Underlying Approach to Review             21
         and Disposition of the Proposed Standards..........
        2. Mandates of Section 215 of the FPA...............          23
        3. Balancing the Need for Practicality with the               29
         Mandates of Section 215 and Order No. 672..........
    B. Discussion of the Commission's New Regulations.......          34
        1. Applicability....................................          34
        2. Mandatory Reliability Standards..................          40
        3. Availability of Reliability Standards............          44
    C. Applicability Issues.................................          50
        1. Bulk-Power System v. Bulk Electric System........          50
        2. Applicability to Small Entities..................          80
        3. Definition of User of the Bulk-Power System......         110
        4. Use of the NERC Functional Model.................         117
        5. Regional Reliability Organizations...............         146
    D. Mandatory Reliability Standards......................         161
        1. Legal Standard for Approval of Reliability                161
         Standards..........................................
        2. Commission Options When Acting on a Reliability           169
         Standard...........................................
        3. Prioritizing Modifications to Reliability                 193
         Standards..........................................
        4. Trial Period.....................................         208
        5. International Coordination.......................         226
    E. Common Issues Pertaining to Reliability Standards....         234
        1. Blackout Report Recommendation on Liability               234
         Limitations........................................
        2. Measures and Levels of Non-Compliance............         238
        3. Ambiguities and Potential Multiple                        264
         Interpretations....................................
        4. Technical Adequacy...............................         282
        5. Fill-in-the-Blank Standards......................         287
    F. Discussion of Each Individual Reliability Standard...         304
        1. BAL: Resource and Demand Balancing...............         305
        2. CIP: Critical Infrastructure Protection..........         446

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        3. COM: Communications..............................         473
        4. EOP: Emergency Preparedness and Operations.......         542
        5. FAC: Facilities Design, Connections, Maintenance,         678
         and Transfer Capabilities..........................
        6. INT: Interchange Scheduling and Coordination.....         796
        7. IRO: Interconnection Reliability Operations and           889
         Coordination.......................................
        8. MOD: Modeling, Data, and Analysis................        1007
        9. PER: Personnel Performance, Training and                 1325
         Qualifications.....................................
        10. PRC: Protection and Control.....................        1419
        11. TOP: Transmission Operations....................        1568
        12. TPL: Transmission Planning......................        1684
        13. VAR: Voltage and Reactive Control...............        1847
        14. Glossary of Terms Used in Reliability Standards.        1887
III. Information Collection Statement.......................        1900
IV. Environmental Analysis..................................        1909
V. Regulatory Flexibility Act...............................        1910
VI. Document Availability...................................        1947
VII. Effective Date and Congressional Notification..........        1950
Appendix A: Disposition of Reliability Standards, Glossary
 and Regional Differences
Appendix B: Commenters on the Notice of Proposed Rulemaking
Appendix C: Abbreviations in this Document
 

I. Introduction

    1. Pursuant to section 215 of the Federal Power Act (FPA), the 
Commission approves 83 of 107 proposed Reliability Standards, six of 
the eight proposed regional differences, and the Glossary of Terms Used 
in Reliability Standards (glossary) developed by the North American 
Electric Reliability Corporation (NERC), which the Commission has 
certified as the Electric Reliability Organization (ERO) responsible 
for developing and enforcing mandatory Reliability Standards. Those 
Reliability Standards meet the requirements of section 215 of the FPA 
and Part 39 of the Commission's regulations. However, although we 
believe it is in the public interest to make these Reliability 
Standards mandatory and enforceable, we also find that much work 
remains to be done. Specifically, we believe that many of these 
Reliability Standards require significant improvement to address, among 
other things, the recommendations of the Blackout Report.\1\ Therefore, 
pursuant to section 215(d)(5), we require the ERO to submit significant 
improvements to 56 of the 83 Reliability Standards that are being 
approved as mandatory and enforceable. The remaining 24 Reliability 
Standards will remain pending at the Commission until further 
information is provided.
    2. The Final Rule adds a new part to the Commission's regulations, 
which states that this part applies to all users, owners and operators 
of the Bulk-Power System within the United States (other than Alaska or 
Hawaii) and requires that each Reliability Standard identify the subset 
of users, owners and operators to which that particular Reliability 
Standard applies. The new regulations also require that each 
Reliability Standard that is approved by the Commission will be 
maintained on the ERO's Internet Web site for public inspection.
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    \1\ U.S.-Canada Power System Outage Task Force, Final Report on 
the August 14 Blackout in the United States and Canada: Causes and 
Recommendations (April 2004) (Blackout Report). The Blackout Report 
is available on the Internet at http://www.ferc.gov/cust-protect/moi/blackout.asp.
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A. Background

1. EPAct 2005 and Order No. 672
    3. On August 8, 2005, the Electricity Modernization Act of 2005, 
which is Title XII, Subtitle A, of the Energy Policy Act of 2005 (EPAct 
2005), was enacted into law.\2\ EPAct 2005 adds a new section 215 to 
the FPA, which requires a Commission-certified 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 the Commission 
can independently enforce Reliability Standards.\3\
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    \2\ Energy Policy Act of 2005, Pub. L. No 109-58, Title XII, 
Subtitle A, 119 Stat. 594, 941 (2005), to be codified at 16 U.S.C. 
824o.
    \3\ 16 U.S.C. 824o(e)(3).
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    4. On February 3, 2006, the Commission issued Order No. 672, 
implementing section 215 of the FPA.\4\ Pursuant to Order No. 672, the 
Commission certified one organization, NERC, as the ERO.\5\ The ERO is 
required to develop Reliability Standards, which are subject to 
Commission review and approval.\6\ The Reliability Standards will apply 
to users, owners and operators of the Bulk-Power System, as set forth 
in each Reliability Standard.
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    \4\ Rules Concerning Certification of the Electric Reliability 
Organization; Procedures for the Establishment, Approval and 
Enforcement of Electric Reliability Standards, Order No. 672, 71 FR 
8662 (February 17, 2006), FERC Stats. & Regs. ] 31,204 (2006), order 
on reh'g, Order No. 672-A, 71 FR 19814 (April 18, 2006), 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), order on compliance, 118 FERC ] 
61,030 (2007) (January 2007 Compliance Order).
    \6\ Section 215(a)(3) of the FPA defines the term Reliability 
Standard to mean ``a requirement, approved by the Commission under 
this section, to provide for reliable operation of the Bulk-Power 
System. This term includes requirements for the operation of 
existing Bulk-Power System facilities, including cybersecurity 
protection, and the design of planned additions or modifications to 
such facilities to the extent necessary to provide for the reliable 
operation of the Bulk-Power System, but the term does not include 
any requirement to enlarge such facilities or to construct new 
transmission capacity or generation capacity.'' 16 U.S.C. 
824o(a)(3).
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    5. Section 215(d)(2) of the FPA and the Commission's regulations 
provide that the Commission may approve a proposed Reliability Standard 
if it determines that the proposal is just, reasonable, not unduly 
discriminatory or preferential, and in the public interest. The 
Commission specified in Order No. 672 certain general factors it would 
consider when assessing whether a particular Reliability Standard is 
just and reasonable.\7\ According to this guidance, a Reliability 
Standard must provide for the Reliable Operation of Bulk-Power System 
facilities and may impose a requirement on any user, owner or operator 
of such facilities. It must be designed to achieve a specified

[[Page 16418]]

reliability goal and must contain a technically sound means to achieve 
this goal. The Reliability Standard should be clear and unambiguous 
regarding what is required and who is required to comply. The possible 
consequences for violating a Reliability Standard should be clear and 
understandable to those who must comply. There should be clear criteria 
for whether an entity is in compliance with a Reliability Standard. 
While a Reliability Standard does not necessarily need to reflect the 
optimal method for achieving its reliability goal, a Reliability 
Standard should achieve its reliability goal effectively and 
efficiently. A Reliability Standard must do more than simply reflect 
stakeholder agreement or consensus around the ``lowest common 
denominator.'' It is important that the Reliability Standards developed 
through any consensus process be sufficient to adequately protect Bulk-
Power System reliability.\8\
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    \7\ Order No. 672 at P 262, 321-37.
    \8\ Id. at P 329.
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    6. A Reliability Standard may take into account the size of the 
entity that must comply and the costs of implementation. A Reliability 
Standard should be a single standard that applies across the North 
American Bulk-Power System to the maximum extent this is achievable 
taking into account physical differences in grid characteristics and 
regional Reliability Standards that result in more stringent practices. 
It can also account for regional variations in the organizational and 
corporate structures of transmission owners and operators, variations 
in generation fuel type and ownership patterns, and regional variations 
in market design if these affect the proposed Reliability Standard. 
Finally, a Reliability Standard should have no undue negative effect on 
competition.\9\
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    \9\ Id. at P 332.
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    7. Order No. 672 directs the ERO to explain how the factors the 
Commission identified are satisfied and how the ERO balances any 
conflicting factors when seeking approval of a proposed Reliability 
Standard.\10\
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    \10\ Id. at P 337.
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    8. Pursuant to section 215(d)(2) of the FPA and Sec.  39.5(c) of 
the Commission's regulations, the Commission will give due weight to 
the technical expertise of the ERO with respect to the content of a 
Reliability Standard or to a Regional Entity organized on an 
Interconnection-wide basis with respect to a proposed Reliability 
Standard or a proposed modification to a Reliability Standard to be 
applicable within that Interconnection. However, the Commission will 
not defer to the ERO or to such a Regional Entity with respect to the 
effect of a proposed Reliability Standard or proposed modification to a 
Reliability Standard on competition.\11\
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    \11\ 18 CFR 39.5(c)(1), (3).
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    9. The Commission's regulations require the ERO to file with the 
Commission each new or modified Reliability Standard that it proposes 
to be made effective under section 215 of the FPA. The filing must 
include a concise statement of the basis and purpose of the proposed 
Reliability Standard, a summary of the Reliability Standard development 
proceedings conducted by either the ERO or Regional Entity, together 
with a summary of the ERO's Reliability Standard review proceedings, 
and a demonstration that the proposed Reliability Standard is just, 
reasonable, not unduly discriminatory or preferential and in the public 
interest.\12\
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    \12\ 18 CFR 39.5(a).
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    10. Where a Reliability Standard requires significant improvement, 
but is otherwise enforceable, the Commission approves the Reliability 
Standard. In addition, as a distinct action under the statute, the 
Commission directs the ERO to modify such a Reliability Standard, 
pursuant to section 215(d)(5) of the FPA, to address the identified 
issues or concerns. This approach will allow the proposed Reliability 
Standard to be enforceable while the ERO develops any required 
modifications.
    11. The Commission will remand to the ERO for further consideration 
a proposed new or modified Reliability Standard that the Commission 
disapproves in whole or in part.\13\ When remanding a Reliability 
Standard to the ERO, the Commission may order a deadline by which the 
ERO must submit a proposed or modified Reliability Standard.
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    \13\ 18 CFR 39.5(e).
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2. NERC Petition for Approval of Reliability Standards
    12. On April 4, 2006, as modified on August 28, 2006, NERC 
submitted to the Commission a petition seeking approval of the 107 
proposed Reliability Standards that are the subject of this Final 
Rule.\14\ According to NERC, the 107 proposed Reliability Standards 
collectively define overall acceptable performance with regard to 
operation, planning and design of the North American Bulk-Power System. 
Seven of these Reliability Standards specifically incorporate one or 
more ``regional differences'' (which can include an exemption from a 
Reliability Standard) for a particular region or subregion, resulting 
in eight regional differences. NERC stated that it simultaneously filed 
the proposed Reliability Standards with governmental authorities in 
Canada. The Commission addresses these proposed Reliability Standards 
in this rulemaking proceeding.\15\
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    \14\ The filed proposed Reliability Standards are not attached 
to the Final Rule but are available on the Commission's eLibrary 
document retrieval system in Docket No. RM06-16-000 and are 
available on the ERO's Web site, http://www.nerc.com/filez/nerc_filings_ferc.html.
    \15\ Eight proposed Reliability Standards submitted in the 
August 29, 2006 filing that relate to cyber security, Reliability 
Standards CIP-002 through CIP-009, will be addressed in a separate 
rulemaking proceeding in Docket No. RM06-22-000.
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    13. On November 15, 2006, NERC filed 20 revised proposed 
Reliability Standards and three new proposed Reliability Standards for 
Commission approval. The 20 revised Reliability Standards primarily 
provided additional Measures and Levels of Non-Compliance, but did not 
add or revise any existing Requirements to these Reliability Standards. 
NERC requested that the 20 revised proposed Reliability Standards be 
included as part of the Final Rule issued by the Commission in this 
docket. The proposed new Reliability Standards, FAC-010-1, FAC-011-1, 
and FAC-014-1, will be addressed in a separate rulemaking proceeding in 
Docket No. RM07-3-000.
    14. On December 1, 2006, NERC submitted in Docket No. RM06-16-000 
an informational filing entitled ``NERC's Reliability Standards 
Development Plan: 2007--2009'' (Work Plan). NERC stated it was 
submitting the Work Plan to inform the Commission of NERC's program to 
improve the Reliability Standards that currently are the subject of the 
Commission's rulemaking proceeding.
3. Staff Preliminary Assessment and Commission NOPR
    15. On May 11, 2006, Commission staff issued a ``Staff Preliminary 
Assessment of the North American Electric Reliability Council's 
Proposed Mandatory Reliability Standards'' (Staff Preliminary 
Assessment). The Staff Preliminary Assessment identifies staff's 
observations and concerns regarding NERC's then-current voluntary 
Reliability Standards. The Staff Preliminary Assessment describes 
issues common to a number of proposed Reliability Standards. It reviews 
and identifies issues regarding each individual Reliability Standard 
but did not make specific recommendations regarding the appropriate 
Commission action on a particular proposal.
    16. Comments on the Staff Preliminary Assessment were due by June 
26, 2006. Approximately 50 entities filed comments in response to

[[Page 16419]]

the Staff Preliminary Assessment. In addition, on July 6, 2006, the 
Commission held a technical conference to discuss NERC's proposed 
Reliability Standards, the Staff Preliminary Assessment, the comments 
and other related issues.
4. Notice of Proposed Rulemaking
    17. The Commission issued the NOPR on October 20, 2006, and 
required that comments be filed within 60 days after publication in the 
Federal Register, or January 2, 2007.\16\ The Commission granted the 
request of several commenters to extend the comment date to January 3, 
2007. Several late-filed comments were filed. The Commission will 
accept these late-filed comments. A list of commenters appears in 
Appendix A.
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    \16\ Mandatory Reliability Standards for the Bulk Power System, 
Notice of Proposed Rulemaking, 71 FR 64,770 (Nov. 3, 2006), FERC 
Stats. & Regs., Vol IV, Proposed Regulations, ] 32,608 (2006).
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    18. On November 27, 2006, the Commission issued a notice on the 20 
revised Reliability Standards filed by NERC on November 15, 2006. In 
the notice, the Commission explained that, because of their close 
relationship with Reliability Standards dealt with in the October 20, 
2006 NOPR, the Commission would address these 20 revised Reliability 
Standards in this proceeding.\17\ The notice provided an opportunity to 
comment on the revised Reliability Standards, with a comment due date 
of January 3, 2007.
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    \17\ The modified 20 Reliability Standards are: CIP-001-1; COM-
001-1; COM-002-2; EOP-002-2; EOP-003-1; EOP-004-1; EOP-006-1; INT-
001-2; INT-003-2; IRO-001-1; IRO-002-1; IRO-003-2; IRO-005-2; PER-
004-1; PRC-001-1; TOP-001-1; TOP-002-2; TOP-004-1; TOP-006-1; and 
TOP-008-1.
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    19. The Commission issued a notice on NERC's Work Plan on December 
8, 2006. While the Commission sought public comment on NERC's filing 
because it was informative on the prioritization of modifying 
Reliability Standards raised in the NOPR, the notice emphasized that 
the Work Plan was filed for informational purposes and NERC stated that 
it is not requesting Commission action on the Work Plan.
    20. On February 6, 2007, NERC submitted a request for leave to file 
supplemental information, and included a revised version of the NERC 
Statement of Compliance Registry Criteria (Revision 3). NERC noted that 
it had submitted with its NOPR comments an earlier version of the same 
document.\18\
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    \18\ See NERC comments, Attachment B.
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II. Discussion

A. Overview

1. The Commission's Underlying Approach To Review and Disposition of 
the Proposed Standards
    21. In this Final Rule, the Commission takes the important step of 
approving the first set of mandatory and enforceable Reliability 
Standards within the United States in accordance with the provisions of 
new section 215 of the FPA. The Commission's action herein marks the 
official departure from reliance on the electric utility industry's 
voluntary compliance with Reliability Standards adopted by NERC and the 
regional reliability councils and the transition to the mandatory, 
enforceable Reliability Standards under the Commission's ultimate 
oversight through the ERO and, eventually, the Regional Entities, as 
directed by Congress. As we discuss more fully below, in deciding 
whether to approve, approve and direct modifications, or remand each of 
the proposed Reliability Standards in this Final Rule, our overall 
approach has been one of carefully balancing the need for practicality 
during the time of transition with the imperatives of section 215 of 
the FPA and Order No. 672, and other considerations.
    22. In addition, our action today is informed by the August 14, 
2003 blackout which affected significant portions of the Midwest and 
Northeast United States and Ontario, Canada and impacted an estimated 
50 million people and 61,800 megawatts of electric load. As noted in 
the NOPR, a joint United States-Canada task force found that the 
blackout was caused by several entities violating NERC's then-effective 
policies and Reliability Standards.\19\ Those violations directly 
contributed to the loss of a significant amount of electric load. The 
joint task force identified both the need for legislation to make 
Reliability Standards mandatory and enforceable with penalties for 
noncompliance, as well as particular Reliability Standards that needed 
corrections to make them more effective in preventing blackouts. 
Indeed, the August 2003 blackout and the recommendations of the joint 
task force helped foster enactment of EPAct 2005 and new section 215 of 
the FPA.
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    \19\ NOPR at P 14.
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2. Mandates of Section 215 of the FPA
    23. The imperatives of section 215 of the FPA address not only the 
protection of the reliability of the Bulk-Power System but also the 
reliability roles of the Commission, the ERO, the Regional Entities, 
and the owners, users and operators of the Bulk-Power System.\20\ 
First, section 215 specifies that the ERO is to develop and enforce a 
comprehensive set of Reliability Standards subject to Commission 
review. Section 215 explains that a Reliability Standard is a 
requirement approved by the Commission that is intended to provide for 
the Reliable Operation of the Bulk-Power System. Such requirement may 
pertain to the operation of existing Bulk-Power System facilities, 
including cybersecurity protection, or it may pertain to the design of 
planned additions or modifications to such facilities to the extent 
necessary to provide for reliable operation of the Bulk-Power 
System.\21\
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    \20\ Generally speaking, the nation's Bulk-Power System has been 
described as consisting of ``generating units, transmission lines 
and substations, and system controls.'' Maintaining Reliability in a 
Competitive U.S. Electricity Industry, Final Report of the Task 
Force on Electric System Reliability, Secretary of Energy Advisory 
Board, U.S. Department of Energy (September 1998) at 2, 6-7. The 
transmission component of the Bulk-Power System is understood to 
provide for the movement of power in bulk to points of distribution 
for allocation to retail electricity customers. Essentially, 
transmission lines and other parts of the transmission system, 
including control facilities, serve to transmit electricity in bulk 
from generation sources to concentrated areas of retail customers, 
while the distribution system moves the electricity to where these 
retail customers consume it at a home or business.
    \21\ 16 U.S.C. 824o(a)(3).
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    24. Second, the reliability mandate of section 215 of the FPA 
addresses not only the comprehensive maintenance of the reliable 
operation of each of the elements of the Bulk-Power System, it also 
contemplates the prevention of incidents, acts and events that would 
interfere with the reliable operation of the Bulk-Power System. 
Further, section 215 seeks to prevent an instability, an uncontrolled 
separation or a cascading failure, whether resulting from either a 
sudden disturbance, including a cybersecurity incident, or an 
unanticipated failure of the system elements. In order to avoid these 
outcomes, the various elements and components of the Bulk-Power System 
are to be operated within equipment and electric system thermal, 
voltage and stability limits.\22\
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    \22\ ``The term `reliable operation' means operating the 
elements of the Bulk-Power System within equipment and electric 
system thermal, voltage, and stability limits so that instability, 
uncontrolled separation, or cascading failures of such system will 
not occur as a result of a sudden disturbance, including a 
cybersecurity incident, or unanticipated failure of system 
elements.'' 16 U.S.C. 824o(a)(4).
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    25. Third, section 215 of the FPA explains that the Bulk-Power 
System broadly encompasses both the facilities

[[Page 16420]]

and control systems necessary for operating an interconnected electric 
energy transmission network (or any portion thereof) as well as the 
electric energy from generation facilities needed to maintain 
transmission system reliability.\23\ Further, section 215 explains that 
the interconnected transmission network within an Interconnection is a 
geographic area in which the operation of Bulk-Power System components 
is synchronized such that the failure of one such component, or more 
than one such component, may adversely affect the ability of the 
operators of other components within the system to maintain reliable 
operation of the facilities within their control.\24\ A Cybersecurity 
Incident is explained to be a malicious act that disrupts or attempts 
to disrupt the operation of programmable electronic devices and 
communication networks including hardware, software or data that are 
essential to the reliable operation of the Bulk-Power System.\25\
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    \23\ 16 U.S.C. 824o(a)(1).
    \24\ 16 U.S.C. 824o(a)(5).
    \25\ 16 U.S.C. 824o(a)(8).
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    26. Next, as to the reliability roles of the Commission and others, 
section 215 of the FPA explains that the ERO must file each of its 
Reliability Standards and any modification thereto with the 
Commission.\26\ The Commission will consider a number of factors before 
taking any action with respect thereto. We may approve the Reliability 
Standard or its modification only if we determine that it is just, 
reasonable, and not unduly discriminatory or preferential and in the 
public interest to do so. Also, in doing so, we are instructed to give 
due weight to the technical expertise of the ERO concerning the content 
of a proposed standard or a modification thereto. We must also give due 
weight to an Interconnection-wide Regional Entity with respect to a 
proposed Reliability Standard to be applicable within that 
Interconnection, except for matters concerning the effect on 
competition.\27\
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    \26\ ``The Electric Reliability Organization shall file each 
Reliability Standard or modification to a Reliability Standard that 
it proposes to be made effective under this section with the 
Commission.'' 16 U.S.C. 824o(d)(1).
    \27\ ``The Commission may approve, by rule or order, a proposed 
Reliability Standard or modification to a Reliability Standard if it 
determines that the standard is just, reasonable, not unduly 
discriminatory or preferential, and in the public interest. The 
Commission shall give due weight to the technical expertise of the 
Electric Reliability Organization with respect to the content of a 
proposed standard or modification to a Reliability Standard and to 
the technical expertise of a regional entity organized on an 
Interconnection-wide basis with respect to a Reliability Standard to 
be applicable within that Interconnection, but shall not defer with 
respect to the effect of a standard on competition. A proposed 
standard or modification shall take effect upon approval by the 
Commission.'' 16 U.S.C. 824o(d)(2).
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    27. Similarly, in considering whether to forward a proposed 
Reliability Standard to the Commission for approval, the ERO must 
rebuttably presume that a proposal from a Regional Entity organized on 
an Interconnection-wide basis for a Reliability Standard or 
modification to a Reliability Standard to be applicable on an 
Interconnection-wide basis is just, reasonable, and not unduly 
discriminatory or preferential, and in the public interest.\28\ The 
Commission may also give deference to the advice of a Regional Advisory 
Body organized on an Interconnection-wide basis in regard to whether a 
proposed Reliability Standard is just, reasonable and not unduly 
discriminatory or preferential and in the public interest, as it may 
apply within the region.\29\
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    \28\ 16 U.S.C. 824o(d)(3).
    \29\ 16 U.S.C. 824o(j).
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    28. Finally, the Commission is further instructed to remand to the 
ERO for further consideration any standard or modification that it does 
not approve in whole or part.\30\ We may also direct the ERO to submit 
a proposed Reliability Standard or modification that addresses a 
specific problem if we consider this course of action to be 
appropriate.\31\ Further, if we find that a conflict exists between a 
Reliability Standard and any function, rule, order, tariff, rate 
schedule, or agreement accepted, approved, or ordered by the Commission 
applicable to a transmission organization,\32\ and if we determine that 
the Reliability Standard needs to be changed as a result of such a 
conflict, we must order the ERO to develop and file with the Commission 
a modified Reliability Standard for this purpose.\33\
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    \30\ 16 U.S.C. 824o(d)(4).
    \31\ 16 U.S.C. 824o(d)(5).
    \32\ Under section 215, a transmission organization is a RTO, 
ISO, independent transmission provider or other Transmission 
Organization finally approved by the Commission for the operation of 
transmission facilities. 16 U.S.C. 824o(a)(6).
    \33\ 16 U.S.C. 824o(d)(6).
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3. Balancing the Need for Practicality With the Mandates of Section 215 
and Order No. 672
    29. In enacting section 215, Congress chose to expand the 
Commission's jurisdiction beyond our historical role as primarily an 
economic regulator of the public utility industry under Part II of the 
FPA. Many entities not previously touched by our economic regulatory 
oversight are within our reliability purview and these entities will 
have to familiarize themselves not only with the new reliability 
obligations under section 215 of the FPA and the Reliability Standards 
that we are approving in this Final Rule, but also any proposed 
Reliability Standards or improvements that may implicate them that are 
under development by the ERO and the Regional Entities.\34\ We have 
taken these and other considerations into account and have tried to 
reach an appropriate balance among them.
---------------------------------------------------------------------------

    \34\ Section 215(b) of the FPA provides that, for purposes of 
approving Reliability Standards and enforcing compliance with such 
standards, the Commission shall have jurisdiction over those 
entitles that had previously been excluded under section 201(f) of 
the FPA. Section 201(f) excludes the United States, a state or any 
political subdivision of a state, an electric cooperative that 
receives financing under the Rural Electrification Act of 1936, 7 
U.S.C. 901 et seq., or that sells less than 4,000,000 megawatt hours 
of electricity per year, or any agency, authority, or 
instrumentality of any one or more of the foregoing, or any 
corporation which is wholly owned, directly or indirectly, by any 
one or more of the foregoing, or any officer, agent, or employee of 
any of the foregoing acting as such in the course of his official 
duty, unless such provision makes specific reference thereto. 16 
U.S.C. 824(f).
---------------------------------------------------------------------------

    30. First, we have decided, as proposed in our NOPR, to approve 
most of the Reliability Standards that the ERO submitted in this 
proceeding, even though concerns with respect to many of the 
Reliability Standards have been voiced. As most of these Reliability 
Standards are already being adhered to on a voluntary basis, we are 
concerned that to remand them and leave no standard in place in the 
interim would not help to ensure reliability when such standards could 
be improved over time. In these cases, however, the concerns 
highlighted below merit the serious attention of the ERO and we are 
directing the ERO to consider what needs to be done and how to do so, 
often by way of descriptive directives.\35\
---------------------------------------------------------------------------

    \35\ In Order No. 672, we decided, in response to some 
commenters' suggestions that a Reliability Standard should address 
the ``what'' and not the ``how'' of reliability and that the actual 
implementation should be left to entities such as control area 
operators and system planners, that in some limited situations, 
there may be good reason to do so but, for the most part, in other 
situations the ``how'' may be inextricably linked to the Reliability 
Standard and may need to be specified by the ERO to ensure the 
enforcement of the standard. Since leaving out implementation 
features could sacrifice necessary uniformity, create uncertainty 
for the entity that has to follow the standard, make enforcement 
difficult, or increase the complexity of the Commission's oversight 
and review process, we left it to the ERO to reach the appropriate 
balance between reliability principles and implementation features. 
Order No. 672 at P 260. We also decided that the Commission's 
authority to order the ERO to address a particular reliability topic 
is not in conflict with other provisions of Order No. 672 that 
assigned the responsibility for developing a proposed Reliability 
Standard to the ERO. Order No. 672 at P 416.
---------------------------------------------------------------------------

    31. We emphasize that we are not, at this time, mandating a 
particular

[[Page 16421]]

outcome by way of these directives, but we do expect the ERO to respond 
with an equivalent alternative and adequate support that fully explains 
how the alternative produces a result that is as effective as or more 
effective that the Commission's example or directive.
    32. We have sought to provide enough specificity to focus the 
efforts of the ERO and others adequately. We are also sensitive to the 
concern of the Canadian Federal Provincial Territorial Working Group 
(FPT) about the status of an existing standard that is already being 
followed on a voluntary basis. The FPT suggests, for example, that 
instead of remanding an existing Reliability Standard, the Commission 
should conditionally approve the standard pending its modification.\36\ 
We believe the action we take today is similar in many respects to this 
approach.
---------------------------------------------------------------------------

    \36\ FPT letter to Chairman Kelliher (submitted on July 10, 
2006) (placed in the record of this proceeding).
---------------------------------------------------------------------------

    33. We have also adopted a number of other measures to mitigate 
many of the difficulties associated with the electric utility 
industry's preparation for and transition to mandatory Reliability 
Standards. For instance, we are directing the ERO and Regional Entities 
to focus their enforcement resources during an initial period on the 
most serious Reliability Standard violations. Moreover, because 
commenters have raised valid concerns as discussed below, our Final 
Rule relies on the existing NERC definition of bulk electric system and 
its compliance registration process to provide as much certainty as 
possible regarding the applicability and responsibility of specific 
entities under the approved standards. This approach should also 
assuage the concerns of many smaller entities.

B. Discussion of the Commission's New Regulations

1. Applicability
    34. In the NOPR, the Commission proposed to add Sec.  40.1(a) to 
the regulations. The Commission proposed that Sec.  40.1(a) would 
provide that this Part applies to all users, owners and operators of 
the Bulk-Power System within the United States (other than Alaska and 
Hawaii) including, but not limited to, the entities described in 
section 201(f) of the FPA. This statement is consistent with section 
215(b) of the FPA and Sec.  39.2 of the Commission's regulations.
    35. The Commission further proposed to add Sec.  40.1(b), which 
would require each Reliability Standard made effective under this Part 
to identify the subset of users, owners and operators to whom that 
particular Reliability Standard applies.
a. Comments
    36. NERC agrees with the Commission's proposal to add the text of 
Sec.  40.1(b) to its regulations to require that each Reliability 
Standard identify the subset of users, owners and operators to which 
that particular Reliability Standard applies and believes this 
requirement is currently established in NERC's Rules of Procedure.
    37. TANC supports proposed Sec.  40.1. It states that requiring 
each Reliability Standard to identify the subset of users, owners and 
operators to whom it applies, thereby limiting the scope of the broad 
phrase ``users, owners and operators,'' is a critical step to removing 
ambiguities from the Reliability Standards. According to TANC, the 
proposed text of Sec.  40.1 would eliminate ambiguities with regard to 
the entity responsible for complying with each Reliability Standard. In 
this way, Regional Entities and other interested parties will be 
allowed to weigh in during the Reliability Standards development 
process on the breadth of each standard and may urge NERC to accept any 
necessary regional variations that are necessary to maintain adequate 
reliability within the region.
    38. APPA believes that the Commission's proposal to add Sec.  40.1 
and 40.2 to its regulations is generally appropriate and acceptable, 
but the regulatory language should be amended to make clear the exact 
universe of users, owners and operators of the Bulk-Power System to 
which the mandatory Reliability Standards apply. It recommends that the 
regulations provide that determinations as to applicability of 
standards to particular entities shall be resolved by reference to the 
NERC compliance registry.
b. Commission Determination
    39. The Commission adopts the NOPR's proposal to add Sec.  40.1 to 
the Commission's regulations. The Commission disagrees with APPA's 
suggestion to define here the exact universe of users, owners and 
operators of the Bulk-Power System to which the mandatory Reliability 
Standards apply. Rather, consistent with NERC's existing approach, we 
believe that it is appropriate that each Reliability Standard clearly 
identify the subset of users, owners and operators to which it applies 
and the Commission determines applicability on that basis. As we 
discuss later, we approve NERC's current compliance registry to provide 
certainty and stability in identifying which entities must comply with 
particular Reliability Standards.
2. Mandatory Reliability Standards
    40. The Commission proposed to add Sec.  40.2(a) to the 
Commission's regulations. The proposed regulation text would require 
that each applicable user, owner and operator of the Bulk-Power System 
comply with Commission-approved Reliability Standards developed by the 
ERO, and would provide that the Commission-approved Reliability 
Standards can be obtained from the Commission's Public Reference Room 
at 888 First Street, NE., Room 2A, Washington, DC 20426.
    41. The Commission further proposed to add Sec.  40.2(b) to its 
regulations, providing that a modification to a Reliability Standard 
proposed to become effective pursuant to Sec.  39.5 shall not be 
effective until approved by the Commission.
a. Comments
    42. NERC concurs with the Commission's proposal to require NERC to 
provide to the Commission a copy of all approved Reliability Standards 
for posting in its Public Reference Room. NERC agrees with the 
Commission that neither the text nor the title of an approved 
Reliability Standard should be codified in the Commission's 
regulations.
b. Commission Determination
    43. For the reasons discussed in the NOPR, the Commission generally 
adopts the NOPR's proposal to add Sec.  40.2 to the Commission's 
regulations.\37\ However, after consideration, the Commission has 
determined that it is not necessary to have the approved Reliability 
Standards on file in the Commission's public reference room and on the 
NERC Web site. Therefore, we will require that all Commission-approved 
Reliability Standards be available on the ERO's Web site, with an 
effective date, and revise Sec.  40.2(b) to remove the following 
language: ``Which can be obtained from the Commission's Public 
Reference Room at 888 First Street, NE., Room 2A, Washington, DC, 
20426.'' Further, to be consistent with Part 39 of our regulations, we 
remove the reference to NERC and replace it with ``Electric Reliability 
Organization.''
---------------------------------------------------------------------------

    \37\ NOPR at P 37.
---------------------------------------------------------------------------

3. Availability of Reliability Standards
    44. The Commission proposed to add Sec.  40.3 to the regulation 
text, which requires that the ERO maintain in electronic format that is 
accessible from the Internet the complete set of effective

[[Page 16422]]

Reliability Standards that have been developed by the ERO and approved 
by the Commission. The Commission stated that it believes that ready 
access to an electronic version of the effective Reliability Standards 
will enhance transparency and help avoid confusion as to which 
Reliability Standards are mandatory and enforceable. We noted that NERC 
currently maintains the existing, voluntary Reliability Standards on 
the NERC Web site.
    45. While the NOPR discusses each Reliability Standard and 
identifies the Commission's proposed disposition for each Reliability 
Standard, we did not propose to codify either the text or the title of 
an approved Reliability Standard in the Commission's regulations. 
Rather, we proposed that each user, owner or operator of the Bulk-Power 
System must comply with applicable Commission-approved Reliability 
Standards that are available in the Commission's Public Reference Room 
and on the Internet at the ERO's Web site. We stated that this approach 
is consistent with the statutory options of approving a proposed 
Reliability Standard or modification to a Reliability Standard ``by 
rule or order.'' \38\
---------------------------------------------------------------------------

    \38\ See 16 U.S.C. 824o(d)(2).
---------------------------------------------------------------------------

a. Comments
    46. NERC states that it can successfully implement the Commission's 
proposal to require NERC to maintain in electronic format that is 
accessible from the Internet the complete set of Reliability Standards 
that have been developed by the ERO and approved by the Commission. 
NERC currently maintains a public Web site displaying the existing, 
voluntary Reliability Standards for access by users, owners and 
operators of the Bulk-Power System. Once the proposed Reliability 
Standards are approved by the Commission, NERC will modify its Web site 
to distinguish which Reliability Standards have been approved by the 
Commission for enforcement in the United States.
    47. EEI states that the approval of Reliability Standards should be 
through a rulemaking rather than an order, except in very rare 
circumstances, because of the open nature of the rulemaking process. 
Where the Commission decides to proceed by order, EEI states that the 
Commission should give notice and an opportunity to comment on any 
proposed Reliability Standards.
b. Commission Determination
    48. For the reasons discussed in the NOPR, the Commission adopts 
the NOPR's proposal to add Sec.  40.3 to the Commission's regulations; 
however the Commission has further clarified the proposed regulatory 
text.\39\ We clarify that the ERO must post on its Web site the 
currently effective Reliability Standards as approved and enforceable 
by the Commission. Further, we require the effective date of the 
Reliability Standards must be included in the posting.
---------------------------------------------------------------------------

    \39\ NOPR at P 39-41.
---------------------------------------------------------------------------

    49. In response to EEI, the Commission anticipates that it will 
address most, if not all, new Reliability Standards proposed by NERC 
through a rulemaking process. However, we retain the flexibility to 
address matters by order where appropriate, consistent with the statute 
and our regulations.\40\ In Order No. 672, the Commission stated that 
it would provide notice and opportunity for public comment except in 
extraordinary circumstances and, on rehearing, clarified that any 
decision by the Commission not to provide notice and comment when 
reviewing a proposed Reliability Standard will be made in accordance 
with the criteria established in section 553 of the Administrative 
Procedure Act.\41\
---------------------------------------------------------------------------

    \40\ See 16 U.S.C. 824o(d)(2) (``the Commission may approve, by 
rule or order, a proposed Reliability Standard or modification * * 
*''); 18 CFR 39.5(c).
    \41\ See Order No. 672 at P 308; Order No 672-A at P 26.
---------------------------------------------------------------------------

C. Applicability Issues

1. Bulk-Power System v. Bulk Electric System
    50. The NOPR observed that, for purposes of section 215, ``Bulk-
Power System'' means:

    (A) facilities and control systems necessary for operating an 
interconnected electric energy transmission network (or any portion 
thereof) and (B) electric energy from generating facilities needed 
to maintain transmission system reliability. The term does not 
include facilities used in the local distribution of electric 
energy.

    51. The NERC glossary, in contrast, states that Reliability 
Standards apply to the ``bulk electric system,'' which is defined by 
its regions in terms of a voltage threshold and configuration, as 
follows:

    As defined by the Regional Reliability Organization, the 
electrical generation resources, transmission lines, 
interconnections with neighboring systems, and associated equipment, 
generally operated at voltages of 100 kV or higher. Radial 
transmission facilities serving only load with one transmission 
source are generally not included in this definition.\42\
---------------------------------------------------------------------------

    \42\ NERC Glossary at 2. All citations to the Glossary in this 
Final Rule refer to the November 1, 2006 version filed on November 
15, 2006.

    52. In the NOPR, the Commission proposed that, for the initial 
approval of proposed Reliability Standards, the continued use of NERC's 
definition of bulk electric system as set forth in the NERC glossary is 
appropriate.\43\ However, the Commission interpreted the term ``bulk 
electric system'' to apply to: (1) All of the >= 100 kV transmission 
systems and any underlying transmission system (< 100 kV) that could 
limit or supplement the operation of the higher voltage transmission 
systems and (2) transmission to all significant local distribution 
systems (but not the distribution system itself), transmission to load 
centers and transmission connecting generation that supplies electric 
energy to the system. The Commission proposed that, if a question arose 
concerning which underlying transmission system limits or supplements 
the operation of the higher voltage transmission system, the ERO would 
determine the matter on a case-by-case basis.
---------------------------------------------------------------------------

    \43\ NOPR at P 66-70. The Commission explained in the NOPR that 
regional definitions had not been submitted and it would not 
determine the appropriateness of any regional definition in the 
current rulemaking proceeding. Id. at n. 56.
---------------------------------------------------------------------------

    53. The Commission solicited comment on its interpretation and 
whether the Regional Entities should, in the future, play a role in 
either defining the facilities that are subject to a Reliability 
Standard or be allowed to determine an exception on a case-by-case 
basis.
    54. Further, the NOPR explained that continued reliance on multiple 
regional interpretations of the NERC definition of bulk electric 
system, which omits significant portions of the transmission system 
component of the Bulk-Power System that serve critical load centers, is 
not appropriate. Thus, the NOPR proposed that, in the long run, NERC 
revise the current definition of bulk electric system to ensure that 
all facilities, control systems and electric energy from generation 
resources that impact system reliability are included within the scope 
of applicability of Reliability Standards, and that NERC's revision is 
consistent with the statutory term Bulk-Power System.
a. Comments
    55. Most commenters, including NERC, NARUC, APPA, National Grid, 
EEI and Ontario IESO, believe that the Commission should only impose 
Reliability Standards on those entities that fall under NERC's 
definition of bulk electric system as it existed under the voluntary 
regime. They state that, by extending the definition of bulk electric 
system, the Commission goes beyond

[[Page 16423]]

what is necessary to protect Bulk-Power System reliability, creates 
uncertainty and will divert resources from monitoring compliance of 
those entities that could have a material impact on Bulk-Power System 
reliability.
    56. Entergy, however, agrees with the Commission that NERC's 
definition of bulk electric system is not adequate and agrees with the 
Commission's proposed interpretation. ISO-NE does not oppose the NOPR's 
approach on how to interpret the term ``Bulk-Power System,'' but it 
states that this broader scope justifies a delay in the date civil 
penalties take effect, to January 1, 2008, to provide the industry 
sufficient time to review the Commission's Final Rule and to adjust to 
the expanded reach of the Reliability Standards.
    57. NERC, APPA and NRECA maintain that there was no intentional 
distinction made by Congress between ``Bulk-Power System'' (as defined 
in section 215) and the ``bulk electric system'' (as defined by the 
NERC glossary). NERC asserts that recent discussions with stakeholders 
confirm NERC's belief that there was no distinction intended. Moreover, 
NERC is not aware of any documentation that suggests a distinction was 
intended. NRECA argues that legislative intent and prior usage do not 
support the Commission's approach to defining the Bulk-Power System. 
NRECA concedes that no conference committee report accompanied EPAct 
2005, but it notes that the Congressional Research Service specifies in 
its manual on statutory interpretation that ``[W]here Congress borrows 
terms of art in which are accumulated the legal tradition and meaning 
of centuries of practice, it presumably knows and adopts the cluster of 
ideas that were attached to each borrowed word in the body of learning 
from which it was taken.'' \44\
---------------------------------------------------------------------------

    \44\ NRECA, citing Morissette v. United States, 342 U.S. 246, 
263 (1952).
---------------------------------------------------------------------------

    58. TAPS states that the Commission cannot lawfully ``interpret'' 
the bulk electric system definition contrary to its terms. According to 
TAPS, the Commission cannot include facilities below 100 kV ``that 
could limit or supplement the operation of the higher voltage 
transmission systems,'' in the bulk electric system, even if they are 
``necessary for operating'' the bulk system, because these facilities 
are not included in NERC's definition of bulk electric system.
    59. NERC states that the Commission's proposal that NERC's ``bulk 
electric system'' should apply to all of the equal to or greater than 
100 kV transmission systems and any underlying transmission system 
(less than 100 kV) that could limit or supplement the operation of the 
higher voltage transmission systems is a significant expansion over 
what the industry has historically regarded as the bulk electric 
system, both in terms of the facilities covered and the entities 
involved. While NERC agrees with the Commission that Congress intended 
to give the Commission broad jurisdiction over the reliability of the 
Bulk-Power System, it does not believe this is the right time for the 
Commission to define the full extent of its jurisdiction or that the 
approach proposed in the NOPR is the right way to do so. In addition, 
NERC does not believe it is legally necessary for the Commission to 
extend its jurisdiction to the limits in a single step.
    60. NERC states that the Commission should make clear in this Final 
Rule that its jurisdiction is at least as broad as the historic NERC 
definition of ``bulk electric system'' and that the Commission will use 
that definition for the near term. NERC asserts that the Commission 
should also make clear that it is not deciding in this docket the full 
scope of its jurisdiction and is reserving its right to consider a 
broader definition. Instead, NERC states that the Commission should 
focus on approving an initial set of Reliability Standards for the core 
set of users, owners and operators that have the most significant 
impact on the reliability of the Bulk-Power System. NERC maintains that 
this core set has been defined through its use of the terms ``bulk 
electric system'' and ``responsible entities'' provided in the NERC 
Glossary, the ``Applicability'' section of each Reliability Standard 
and substantive requirements of the standards themselves, and NERC's 
registration of specific entities that are responsible for compliance 
with the Reliability Standards.
    61. NRECA argues that the definition of ``Bulk-Power System'' 
contained in section 215(a)(1) reflects Congressional intent to codify 
the established materiality component because Congress limited the 
definition of Bulk-Power System to facilities and control systems 
necessary for operating an interconnected electric energy transmission 
network and electric energy from generation facilities needed to 
maintain transmission system reliability. NRECA argues that these 
limiting terms mean that not all transmission facilities are included. 
In NRECA's view, the definition of the Bulk-Power System within the 
meaning of section 215 cannot extend to radial facilities to 
``significant local distribution systems,'' ``load centers,'' or local 
transmission facilities unless otherwise ``necessary for'' (i.e., 
material to) the reliable operation of the interconnected grid. 
Further, NRECA states that the definition of ``Reliable Operation'' in 
section 215(a) focuses on the reliable operation of the Bulk-Power 
System and not the protection of local load per se.
    62. Certain commenters assert that expanding the scope of the 
Commission's jurisdiction and the scope of the Reliability Standards in 
this proceeding would be an unanticipated expansion of the reach of the 
existing Reliability Standards implemented with insufficient due 
process and may cause jurisdictional concerns.\45\ They state that the 
Reliability Standards under consideration were developed and approved 
through NERC's Reliability Standards development process with the 
intention that they would apply based on the industry's historical 
conception of the bulk electric system and that the outcome might have 
been different using the Commission's proposed definition. NERC 
therefore argues that it would be inappropriate to assume that the 
requirements of the existing Reliability Standards would be relevant to 
an expanded set of entities or an expanded scope of facilities under a 
broader definition of the Bulk-Power System. NERC also asserts that 
there is no reasonable justification for subjecting ``thousands of 
small entities'' to the costs of compliance with the Reliability 
Standards when there is no reasonable justification to do so in terms 
of incremental benefit to the reliability of the Bulk-Power System.
---------------------------------------------------------------------------

    \45\ See, e.g., NERC, TAPS and NRECA.
---------------------------------------------------------------------------

    63. NRECA, APPA and others argue that the Commission's 
interpretation would undermine, rather than promote, reliability. 
According to these commenters, the Commission's interpretation would 
require new definitions, such as one for ``load center,'' and otherwise 
creates confusion. For example, Small Entities Forum states that it is 
concerned with the inclusion of ``transmission connecting generation 
that supplies electric energy to the system'' because that could 
include any transmission connected to any generation of any size.
    64. APPA objects to the Commission's statement that ``[t]he 
transmission system component of the Bulk-Power System is understood to 
provide for the movement of power in bulk to points of distribution for 
allocation to retail electricity customers.'' APPA states that it does 
not believe there is an industry ``understanding'' that the bulk 
electric system or the Bulk-Power System

[[Page 16424]]

necessarily encompass all transmission facilities that connect major 
generation stations to distribution systems or that there is a bright 
line between transmission and distribution facilities. APPA interprets 
these terms as describing the backbone facilities that integrate 
regional transmission networks.
    65. NERC's approach to moving forward with the enforcement of 
mandatory Reliability Standards is to register the specific entities 
that NERC will hold accountable for compliance with the Reliability 
Standards. The registration will identify all entities that are 
material to the reliability of the Bulk-Power System. NERC maintains 
its most important role is to mitigate noncompliant behavior regardless 
of an entity's registration. Further, NERC asserts that all that it and 
the Commission give up by using the registration approach is, at most, 
``one penalty, one time'' for an entity. That is, if there is an entity 
that is not registered and NERC later discovers that the entity can 
have a material impact on the reliability of the Bulk-Power System, 
NERC has the ability to add the entity, and possibly other entities of 
a similar class, to the registration list and to direct corrective 
action by that entity on a going forward basis.\46\ Thereafter, of 
course, the entity would be subject to sanctions. APPA, TANC, AMP-Ohio 
and NPCC support this approach. While SoCal Edison believes that there 
can be no single definition of Bulk-Power System, it states that NERC's 
registry is a good starting point to developing general criteria for 
what facilities should be subject to the Reliability Standards.
---------------------------------------------------------------------------

    \46\ See Rules of Procedure, Sec.  500.
---------------------------------------------------------------------------

    66. AMP-Ohio supports NERC's proposal to include any additional 
entities or facilities that it believes could have a detrimental effect 
on the reliability of the bulk electric system on a case-by-case basis 
over time. Further, Ontario IESO suggests that if the Commission 
believes that NERC's definition of bulk electric system excludes 
facilities that should be subject to Reliability Standards for reasons 
other than preventing cascading outages, the Commission could submit a 
detailed request through the ERO Reliability Standards development 
process.
    67. NERC and EEI believe that, in the long run, NERC should be 
directed to develop, through its Reliability Standards development 
process, a single process to identify the specific elements of the 
Bulk-Power System that must comply with Reliability Standards under 
section 215. According to NERC, the Commission, the states, and all 
other stakeholders would benefit tremendously from a deliberate 
dialogue on these matters. NERC asks that the Commission not directly 
define the outer limits of its jurisdiction under section 215, but 
requests that the Commission direct NERC to undertake certain 
activities to reconcile the definitions of bulk electric system and 
Bulk-Power System and report the results back to the Commission.
    68. Similarly, TAPS, APPA, Duke and MidAmerican state that, if 
there is a problem with NERC's current definition of the bulk electric 
system, the Commission should require NERC to revisit it using the ANSI 
process to give ``due weight'' to NERC's technical expertise. AMP-Ohio, 
TANC, Georgia Operators and Entergy state that Regional Entities should 
play a primary role in defining the facilities that are subject to a 
Reliability Standard because the Regional Entities will have more 
detailed system knowledge in their regions than NERC or the Commission.
    69. The Connecticut Attorney General, the Connecticut DPUC and the 
New England Conference of Public Utilities Commissioners maintain that 
NERC's definition of the ``bulk electric system'' exceeds the 
Commission's jurisdiction by including generation that is not needed to 
maintain transmission system reliability and therefore intrudes into 
state jurisdiction over generation resource adequacy matters and is 
unlawful. According to Connecticut DPUC, section 215(a)(1) of the FPA 
excludes from federal regulation (1) facilities that are used in local 
distribution, (2) facilities and control systems that are not necessary 
for operating an interconnected electric energy transmission network or 
part of a network and (3) electric energy from generating facilities 
not needed to maintain transmission system reliability. Connecticut 
DPUC maintains that, in contrast, NERC's definition replaces the FPA 
definition with criteria based on voltage thresholds for transmission 
facilities and electric energy from generating facilities. According to 
Connecticut DPUC, NERC's definition does not comply with section 
215(a)(1) because it includes facilities and equipment that are neither 
``necessary'' for operation of the transmission network nor ``needed'' 
to maintain transmission system reliability. The Connecticut Attorney 
General and Connecticut DPUC, therefore, urge the Commission to reject 
this definition.
    70. Further, in Connecticut DPUC's view, because the Commission 
cannot adopt NERC's definition of bulk electric system, it cannot 
expand the boundaries of its jurisdiction farther than the bulk 
electric system. It maintains that Congress did not give the Commission 
jurisdiction to mandate and enforce all Reliability Standards, 
especially those related to the long-term adequacy of generation 
resources; therefore, the Commission may not delegate to an ERO 
authority that it does not have. APPA also states that the Commission 
expanded the definition of the bulk electric system so that it may 
affect facilities subject to state reliability jurisdiction, such as 
low-voltage transmission systems that affect only the local areas 
served by those facilities, which do not cause cascading outages, 
without explaining why it is necessary to federalize reliability 
responsibility for outages on these facilities.
    71. NARUC and New York Commission maintain that the Commission's 
proposed interpretation of what facilities constitute the Bulk-Power 
System is inconsistent with section 215 of the FPA. They state that the 
ability of a facility to ``limit or supplement'' the transmission 
system does not automatically mean that a facility is necessary for 
operating an interconnected transmission system, as required by the 
FPA, or for maintaining system reliability. According to NARUC, 
Congress only authorized the Commission to approve Reliability 
Standards necessary for operating an interconnected electric energy 
transmission network. Although the NOPR interpretation includes these 
underlying facilities, it also covers others that are not required to 
operate an interconnected transmission network.
    72. Moreover, NARUC and New York Commission state that the NOPR 
proposal to define Bulk-Power System as all facilities operating at or 
above 100 kV exceeds the Commission's jurisdiction. According to NARUC 
and New York Commission, there is generally a layer of ``area'' 
transmission facilities below the ``Bulk-Power System'' and above 
distribution facilities that move energy within a service territory and 
toward load centers. However, NARUC and New York Commission claim that 
only a small subset of these underlying facilities assists in 
maintaining the reliability of the Bulk-Power System.
    73. Several commenters, including New York Commission, NYSRC, 
Massachusetts DTE, NPCC, TANC and Ontario IESO, support a functional, 
impact-based approach to applying Reliability Standards. According to 
NPCC, neither NERC nor section 215 of the FPA provide a rigorous 
approach to

[[Page 16425]]

determining which elements play a role in maintaining reliability of 
the bulk electric system. These commenters generally state that an 
impact-based approach would define those elements necessary for 
Reliable Operation and ensure that compliance and enforcement efforts 
concentrate on those facilities that materially affect the Reliable 
Operation of the interconnected Bulk-Power System, while at the same 
time balancing the costs imposed by mandatory Reliability Standards 
with the reliability improvement realized on the interconnected Bulk-
Power System.
    74. Ontario IESO maintains that reliability impact is a process of 
assessing facilities to determine if, due to recognized contingencies 
and other test criteria, they represent a significant adverse impact 
beyond a local area. This assessment will be the basis of a consistent 
test methodology the ERO must develop to define the facilities included 
within the overall Bulk-Power System to which a Reliability Standard 
would apply. Ontario IESO states that the Commission should direct the 
ERO to take the lead in developing the impact assessment procedure to 
provide a consistent and uniform methodology that can be applied by any 
Regional Entity. Ontario IESO does not support the Commission's 
proposal to limit case-by-case determinations to underlying 
transmission systems operating at less than 100 kV.
b. Commission Determination
    75. The Commission agrees with commenters that, at least initially, 
expanding the scope of facilities subject to the Reliability Standards 
could create uncertainty and might divert resources as the ERO and 
Regional Entities implement the newly created enforcement and 
compliance regime. Further, we agree with commenters that unilaterally 
modifying the definition of the term bulk electric system is not an 
effective means to achieve our goal. For these reasons, the Commission 
is not adopting the proposed interpretation contained in the NOPR. 
Rather, for at least an initial period, the Commission will rely on the 
NERC definition of bulk electric system \47\ and NERC's registration 
process to provide as much certainty as possible regarding the 
applicability to and the responsibility of specific entities to comply 
with the Reliability Standards in the start-up phase of a mandatory 
Reliability Standard regime.\48\
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    \47\ ``As defined by the Regional Reliability Organization, the 
electrical generation resources, transmission lines, 
interconnections with neighboring systems, and associated equipment, 
generally operated at voltages of 100 kV or higher. Radial 
transmission facilities serving only load with one transmission 
source are generally not included in this definition.''
    \48\ See Section II.C.2., Applicability to Small Entities, 
infra.
---------------------------------------------------------------------------

    76. However, we disagree with NERC, APPA and NRECA that there is no 
intentional distinction between Bulk-Power System and bulk electric 
system. NRECA states that ``[W]here Congress borrows terms of art in 
which are accumulated the legal tradition and meaning of centuries of 
practice, it presumably knows and adopts the cluster of ideas that were 
attached to each borrowed word in the body of learning from which it 
was taken.'' \49\ In this instance, however, Congress did not borrow 
the term of art--bulk electric system--but instead chose to create a 
new term, Bulk-Power System, with a definition that is distinct from 
the term of art used by industry. In particular, the statutory term 
does not establish a voltage threshold limit of applicability or 
configuration as does the NERC definition of bulk electric system. 
Instead, section 215 of the FPA broadly defines the Bulk-Power System 
as ``facilities and control systems necessary for operating an 
interconnected electric energy transmission network (or any portion 
thereof) [and] electric energy from generating facilities needed to 
maintain transmission system reliability.'' Therefore, the Commission 
confirms its statements in the NOPR that the Bulk-Power System reaches 
farther than those facilities that are included in NERC's definition of 
the bulk electric system.\50\
---------------------------------------------------------------------------

    \49\ Citing Morissette v. United States, 342 U.S. 246, 263 
(1952).
    \50\ NOPR at P 66. For these same reasons, the Commission 
rejects the position of those commenters that suggest the statutory 
definition of Bulk-Power System is more limited than the NERC 
definition of bulk electric system.
---------------------------------------------------------------------------

    77. Although we are accepting the NERC definition of bulk electric 
system and NERC's registration process for now, the Commission remains 
concerned about the need to address the potential for gaps in coverage 
of facilities. For example, some current regional definitions of bulk 
electric system exclude facilities below 230 kV and transmission lines 
that serve major load centers such as Washington, DC and New York 
City.\51\ The Commission intends to address this matter in a future 
proceeding. As a first step in enabling the Commission to understand 
the reach of the Reliability Standards, we direct the ERO, within 90 
days of this Final Rule, to provide the Commission with an 
informational filing that includes a complete set of regional 
definitions of bulk electric system and any regional documents that 
identify critical facilities to which the Reliability Standards apply 
(i.e., facilities below a 100 kV threshold that have been identified by 
the regions as critical to system reliability).
---------------------------------------------------------------------------

    \51\ See id. at P 64-65 & n.53-54.
---------------------------------------------------------------------------

    78. The Commission believes that the above approach satisfies 
concerns raised by NARUC and New York Commission that the proposal to 
interpret Bulk-Power System exceeds the Commission's jurisdiction. When 
the Commission addresses this matter in a future proceeding, it will 
consider NARUC's and New York Commission's comments regarding the 
``layer of `area' transmission.''
    79. We disagree with commenters claiming that the ERO's definition 
of bulk electric system is broader than the statutory definition of 
Bulk-Power System. Connecticut Attorney General, Connecticut DPUC and 
others argue that the ERO's definition of bulk electric system exceeds 
the Commission's jurisdiction by including generation that is not 
needed to maintain transmission system reliability and, therefore, 
intrudes into state jurisdiction over generation resource adequacy. 
First, none of the Reliability Standards submitted by the ERO set 
requirements for resource adequacy. Moreover, commenters have not 
adequately supported their claim that the ``threshold'' in the NERC 
definition of bulk electric system that includes facilities ``generally 
operated at 100 kV or higher'' is broader than the statutory phrase 
``electric energy from generation facilities needed to maintain 
transmission system reliability.'' As stated explicitly in the NERC 
definition, this is a ``general'' threshold and allows leeway to 
address specific circumstances. On its face, the NERC definition is not 
overbroad; as applied, it must be interpreted and applied consistent 
with the statutory language in section 215. Finally, as stated above, 
we believe that the ERO definition of bulk electric system is narrower 
than the statutory definition of Bulk-Power System.
2. Applicability to Small Entities
    80. The NOPR discussed NERC's plan to, in the future, identify in a 
particular Reliability Standard limitations on applicability based on 
electric facility characteristics.\52\ The Commission agreed that it is 
important to examine the impact a particular entity may have on the 
Bulk-Power System in determining the applicability of a specific 
Reliability Standard. However,

[[Page 16426]]

the Commission stated that a ``blanket waiver'' approach that would 
exempt entities below a threshold level from compliance with all 
Reliability Standards would not be appropriate because there may be 
instances where a small entity's compliance is critical to reliability. 
The Commission also proposed to direct NERC to develop procedures that 
permit a joint action agency or similar organization to accept 
compliance responsibility on behalf of their members.
---------------------------------------------------------------------------

    \52\ Id. P 49-53.
---------------------------------------------------------------------------

    81. In addition, the Commission solicited comment on whether, 
despite the existence of a threshold in a particular standard (e.g., 
generators with a nameplate rating of 20 MW or over), the ERO or a 
Regional Entity should be permitted to include an otherwise exempt 
facility, e.g., a 15 MW generator, on a facility-by-facility basis, if 
it determines that the facility is needed for Bulk-Power System 
reliability and, if so, what, if any, process the ERO or Regional 
Entity should provide when making such a determination.
a. Identifying Applicable Small Entities
i. Comments
    82. While certain commenters, including EEI, FirstEnergy, SERC, 
Xcel and Entergy, agree with the Commission that a blanket waiver to 
exempt small entities from compliance is not appropriate because there 
may be instances where a small entity's compliance is critical to 
reliability, APPA, ELCON, Process Electricity Committee, MEAG and South 
Carolina E&G advocate a blanket waiver.
    83. APPA notes that none of the entities that contributed to the 
August 14, 2003 blackout were ``small entities'' within the meaning of 
the Regulatory Flexibility Act. APPA and MEAG believe that the 
Commission's refusal to provide for a blanket waiver to small entities 
is counterproductive to maintaining reliability, as it will distract 
compliance staff at NERC and the Regional Entities from identifying and 
monitoring those with a material impact on reliability, and gives 
insufficient deference to NERC as the ERO. APPA recommends that the 
methods and procedures used to identify critical facilities that impact 
the bulk electric system, regardless of size, should be the subject of 
a specific set of NERC Reliability Standards. Objective, transparent 
study criteria and assumptions and due process for affected entities 
are essential to implement such standards properly. Regional Entities 
should take advantage of industry expertise in developing and applying 
the methodology for determining critical facilities.
    84. According to MEAG, because the Commission has already 
determined that it is not bound by the NERC compliance registry,\53\ 
the NOPR's approach leaves small systems, which do not appear on the 
compliance registry, confused about whether the Reliability Standards 
apply to them. MEAG asks the Commission to either: (1) Grant a 
temporary, size-based exemption to those small entities that NERC omits 
from its preliminary compliance registry; or (2) direct NERC to develop 
and file with the Commission an appropriate size-based exemption for 
small entities.
---------------------------------------------------------------------------

    \53\ See ERO Rehearing Order at P 108.
---------------------------------------------------------------------------

    85. Several commenters suggest thresholds for applying Reliability 
Standards. MEAG states that an appropriate threshold level for an 
exemption, on either an interim or more permanent basis, should at 
least provide that a LSE or distribution provider should generally be 
omitted from the compliance registry if it meets the following 
criteria: (1) Its peak load is less than 25 MW and it is not directly 
connected to the Bulk-Power System; (2) it is not designated as the 
responsible entity for facilities that are part of a required 
underfrequency load shedding (UFLS) program designed, installed, and 
operated for the protection of the Bulk-Power System; or (3) it is not 
designated as the responsible entity for facilities that are part of a 
required undervoltage load shedding (UVLS) program designed, installed, 
and operated for the protection of the Bulk-Power System. STI Capital 
states that there should be a rebuttable presumption that any 
generation facility below 50 MW does not pose a threat to reliability. 
Moreover, more data intensive standards are beyond the ability of small 
generators.
    86. SERC states that exemptions should be granted through the 
Reliability Standards development process. The ERO and the Regional 
Entities can provide guidance in that process, and stakeholders have an 
opportunity to comment on that guidance.
    87. A number of commenters, including APPA, NRECA, TANC and TAPS, 
ask the Commission to adopt NERC's registry guidelines and make clear 
that issues of applicability will be determined with reference to the 
NERC compliance registry.\54\ TAPS asks the Commission to either 
approve NERC's registry criteria, or send them back to NERC for further 
consideration, with mandatory application of Reliability Standards 
deferred until NERC submits waiver criteria the Commission finds 
acceptable. According to TAPS, these criteria do not constitute a 
blanket waiver because they allow NERC and its Regional Entities to go 
below the general threshold requirements where they determine it is 
necessary.
---------------------------------------------------------------------------

    \54\ NERC has developed a Statement of Compliance Registry 
Criteria that provides guidance on how NERC will identify 
organizations that may be candidates for registration. See NERC 
comments, Attachment B; NERC's February 6, 2007 supplemental filing.
---------------------------------------------------------------------------

    88. California Cogeneration states that, while focusing on entities 
that have a material impact on the Bulk-Power System is a possible 
approach to applying the Reliability Standards, the proposed rule does 
not define how ``material impact'' may be demonstrated. According to 
California Cogeneration, material impact will vary among 
Interconnections and it may vary among individual transmission systems. 
Therefore, California Cogeneration states that the task of defining 
``material impact'' should be remanded by the Commission to NERC for 
resolution through an inclusive stakeholder process. Until that process 
is completed, California Cogeneration maintains that the Reliability 
Standards should not be finally adopted as mandatory and enforceable.
    89. Various Georgia cities, which are all member systems of MEAG, 
state that the Commission should place reasonable limits on the 
applicability of the proposed Reliability Standards.\55\ Each maintains 
that the Final Rule should include a rebuttable presumption that their 
distribution system facilities have no material effect on Bulk-Power 
System reliability unless established otherwise. They suggest that such 
a rebuttable presumption approach would fairly establish the 
``reasonable limits on applicability'' of the Reliability Standards 
based on their respective sizes. Similarly, Small Entities Forum 
supports a rebuttable presumption that any LSE or distribution provider 
with less than 25 MW of load would be excluded unless a Regional Entity 
decides that a reason exists to include it.
---------------------------------------------------------------------------

    \55\ See NOPR at P 1175-76.
---------------------------------------------------------------------------

    90. California Cogeneration states that qualifying facilities (QFs) 
are exempted from section 215 of the FPA. It claims that, after passage 
of EPAct 2005, the Commission modified its regulations to provide that 
QFs are exempt from all sections of the FPA except sections 205, 206, 
220, 221 and 222.\56\ Further, California Cogeneration states that the

[[Page 16427]]

Commission should set limits on whether a Reliability Standard 
applicable to a generator owner or operator also applies to operators 
of cogeneration facilities. According to California Cogeneration, the 
Commission has clearly determined that the impact by a cogenerator on 
the reliability of the system is limited to its net load on the 
system.\57\ Therefore, California Cogeneration maintains that the 
Reliability Standards should reflect this limitation.
---------------------------------------------------------------------------

    \56\ 18 CFR 292.601(c).
    \57\ California Cogenration at 6-7, citing California 
Independent System Operator Corp., 96 FERC ] 63,015, at P 7, 24-25 
(2001).
---------------------------------------------------------------------------

    91. Finally, Small Entities Forum and Entergy state that, despite 
the existence of a threshold in a particular Reliability Standard, the 
ERO or a Regional Entity should be permitted to include an otherwise 
exempt facility, on a facility-by-facility basis, if it determines that 
the facility is needed for Bulk-Power System reliability. South 
Carolina E&G states that exceptions to an exemption threshold should 
sufficiently improve reliability so as to justify the administrative 
costs and other burdens. However, SMA and MidAmerican oppose allowing 
the ERO or its designee to include otherwise exempt facilities by 
making exceptions.
ii. Commission Determination
    92. The Commission believes that, at the outset of this new 
program, it is important to have as much certainty and stability as 
possible regarding which users, owners and operators of the Bulk-Power 
System must comply with mandatory and enforceable Reliability 
Standards. NERC, as the ERO, has developed an approach to accomplish 
this through its compliance registry process. The Commission has 
previously found NERC's compliance registry process to be a reasonable 
means ``to ensure that the proper entities are registered and that each 
knows which Commission-approved Reliability Standard(s) are applicable 
to it.'' \58\
---------------------------------------------------------------------------

    \58\ ERO Certification Order at P 689.
---------------------------------------------------------------------------

    93. NERC has provided with its NOPR comments, and in a subsequent 
supplemental filing, a Statement of Compliance Registry Criteria that 
describes how NERC will identify organizations that may be candidates 
for registration and assign them to the compliance registry. For 
example, NERC plans to register only those distribution providers or 
LSEs that have a peak load of 25 MW or greater and are directly 
connected to the bulk electric system or are designated as a 
responsibility entity as part of a required underfrequency load 
shedding program or a required undervoltage load shedding program. For 
generators, NERC plans to register individual units of 20 MVA or 
greater that are directly connected to the bulk electric system, 
generating plants with an aggregate rating of 75 MVA or greater, any 
blackstart unit material to a restoration plan, or any generator 
``regardless of size, that is material to the reliability of the Bulk-
Power System.''
    94. The compliance registry identifies specific categories of 
users, owners and operators that correlate to the types of entities 
responsible for performing specific functions described in the NERC 
Functional Model.\59\ These same functional types are also used by the 
ERO to identify the entities responsible for compliance with a 
particular Reliability Standard in the Applicability section of a given 
standard. Thus, each registered entity will be registered under one or 
more appropriate functional categories, and that registration by 
function will determine with which Reliability Standards--and 
Requirements of those Reliability Standards--the entity must comply. In 
other words, a user, owner or operator of the Bulk-Power System would 
be required to comply with each Reliability Standard that is applicable 
to any one of the functional types for which it is registered.
---------------------------------------------------------------------------

    \59\ The Statement of Compliance Registry Criteria, as well as 
the Functional Model, identify, inter alia, the following functions: 
Balancing authority, distribution provider, generator operator, 
generator owner, load serving entity, planning authority, 
purchasing-selling entity, transmission owner, transmission operator 
and transmission service provider. An entity may be registered under 
one or more of these functions.
---------------------------------------------------------------------------

    95. We believe that NERC has set reasonable criteria for 
registration and, thus, we approve the ERO's compliance registry 
process as an appropriate approach to allow the ERO, Regional Entities 
and, ultimately, the entities responsible for compliance with mandatory 
Reliability Standards to know which entities are responsible for 
initial implementation of and compliance with the new Reliability 
Standards. Further, based on supplemental comments of APPA, TAPS and 
NRECA, it appears that there is support among many of the smaller 
entities for the NERC compliance registry process.\60\ Thus, at this 
juncture, the Commission will rely on the NERC registration process to 
identify the set of entities that are responsible for compliance with 
particular Reliability Standards.
---------------------------------------------------------------------------

    \60\ See Supplemental Comments of TAPS (February 13, 2007), APPA 
(February 14, 2007), and NRECA (February 15, 2007).
---------------------------------------------------------------------------

    96. In sum, the ERO will identify those entities that must comply 
with Reliability Standards in three steps: (1) The ERO will identify 
and register those entities that fall under its definition of bulk 
electric system; (2) each registered entity will register in one or 
more appropriate functional categories and (3) each registered entity 
will comply with those Reliability Standards applicable to the 
functional categories in which it is registered.
    97. In response to MEAG's concern that the Commission previously 
determined that it was not bound by the NERC compliance registry 
process and that there thus was uncertainty, the Commission is 
modifying the approach proposed in the NOPR and, as noted above, will 
use the NERC compliance registry to determine those users, owners and 
operators of the Bulk-Power System that must comply with the 
Reliability Standards. Each individual Reliability Standard will then 
identify the set of users, owners and operators of the Bulk-Power 
System that must comply with that standard. While the Commission may 
take prospective action against an entity that was not previously 
identified as a user, owner or operator through the NERC registration 
process once it has been added to the registry, the Commission will not 
assess penalties against an entity that has not previously been put on 
notice, through the NERC registration process, that it must comply with 
particular Reliability Standards. Under this process, if there is an 
entity that is not registered and NERC later discovers that the entity 
should have been subject to the Reliability Standards, NERC has the 
ability to add the entity, and possibly other entities of a similar 
class, to the registration list and to direct corrective action by that 
entity on a going-forward basis.\61\ The Commission believes that this 
should prevent an entity from being subject to a penalty for violating 
a Reliability Standard without prior notice that it must comply with 
that Reliability Standard.
---------------------------------------------------------------------------

    \61\ See NERC Rules of Procedure, Sec.  500.
---------------------------------------------------------------------------

    98. As stated in the NOPR, NERC has indicated that in the future it 
may add to a Reliability Standard limitations on applicability based on 
electric facility characteristics such as generator nameplate 
ratings.\62\ While the NOPR explored this approach as a means of 
addressing concerns over applicability to smaller entities, the 
Commission believes that, until the ERO submits a Reliability Standard 
with such a

[[Page 16428]]

limitation to the Commission, the NERC compliance registry process is 
the preferred method of determining the applicability of Reliability 
Standards on an entity-by-entity basis.
---------------------------------------------------------------------------

    \62\ NOPR at P 49.
---------------------------------------------------------------------------

    99. A number of municipalities and generation owners ask that the 
Commission review their particular circumstances and provide an 
individual waiver from compliance with the mandatory Reliability 
Standards. In light of our above discussion, the Commission declines to 
determine whether any individual municipality, generation owner or 
other entity is subject to a specific Reliability Standard. Rather, 
NERC and the Regional Entities should determine such applicability in 
the first instance through the registration process.
    100. We agree with California Cogeneration that the Commission's 
regulations currently exempt most QFs from specific provisions of the 
FPA including section 215.\63\ The Commission is concerned, however, 
whether it is appropriate to grant QFs a complete exemption from 
compliance with Reliability Standards that apply to other generator 
owners and operators. It is not clear to the Commission that for 
reliability purposes there is a meaningful distinction between QF and 
non-QF generators. While such an issue is beyond the scope of the 
current rulemaking, we note that, concurrent with the issuance of this 
Final Rule, the Commission is issuing a notice of proposed rulemaking 
that proposes to amend the Commission's regulation that exempts most 
QFs from section 215 of the FPA.
---------------------------------------------------------------------------

    \63\ 18 CFR 292.601(c).
---------------------------------------------------------------------------

    101. Finally, the Commission agrees that, despite the existence of 
a voltage or demand threshold for a particular Reliability Standard, 
the ERO or Regional Entity should be permitted to include an otherwise 
exempt facility on a facility-by-facility basis if it determines that 
the facility is needed for Bulk-Power System reliability.\64\ However, 
we note that an entity that disagrees with NERC's determination to 
place it in the compliance registry may submit a challenge in writing 
to NERC and, if still not satisfied, may lodge an appeal with the 
Commission.\65\ Therefore, a small entity may appeal to the Commission 
if it believes it should not be required to comply with the Reliability 
Standards.
---------------------------------------------------------------------------

    \64\ Demand resources deemed critical by the ERO to Bulk-Power 
System reliability should be included in the registry.
    \65\ See ERO Certification Order at P679.
---------------------------------------------------------------------------

b. Ability To Accept Compliance on Behalf of Members
i. Comments
    102. APPA, NERC, ELCON, APPA, TAPS and Small Entities Forum support 
the Commission's proposal to allow a joint action agency, generation 
and transmission (G&T) cooperative, or other entities to accept 
responsibility for compliance with Reliability Standards on behalf of 
their members and also may divide the responsibilities for compliance 
with its members. APPA states that this should also be extended to 
RTOs, vertically integrated utilities, and other wholesale power 
suppliers that perform substantial reliability functions on behalf of 
their full requirements wholesale customers, including public power 
distribution systems and other entities that currently fulfill 
reliability functions for customers. APPA, TAPS and Small Entities 
Forum state that the procedure should allow for this responsibility to 
be assigned on a standard-by-standard basis.
    103. In response to the Commission's proposal to direct NERC to 
develop procedures that permit a joint action agency or similar 
organization to accept compliance responsibility on behalf of its 
members, NERC proposes the following procedure, and has updated its 
entity registration criteria to reflect these changes.\66\ NERC states 
that each ``central'' organization should be able to register as being 
responsible for compliance for itself and collectively on behalf of its 
members. Each member within a central organization may separately 
register to be accountable for a particular reliability function 
defined by the standards. Under NERC's proposal, if the central 
organization and a member organization cannot agree that one 
organization or the other is responsible, or if the parties agree that 
the responsibilities for a particular reliability function should be 
split, then NERC would register both entities concurrently. NERC and 
the Regional Entities will then have the authority to find either 
organization or both accountable for a violation of a Reliability 
Standard, based on the facts of the case and circumstances surrounding 
the violation.
---------------------------------------------------------------------------

    \66\ See NERC comments at 53-55; NERC supplemental filing, 
Statement of Compliance Registry Criteria (Revision 3) at 9.
---------------------------------------------------------------------------

    104. AMP-Ohio states that the Commission should clarify that a 
joint action agency should not be required to assume compliance 
responsibility for its members for all reliability-related functions. 
It asks that the Commission allow flexibility in how joint action 
agencies and their members allocate responsibility. TAPS states that 
joint action agencies should be allowed to achieve compliance with a 
standard at the joint action agency level rather than to simply stand 
in the shoes of their individual members. TAPS states that this is 
necessary to ensure comparable treatment for small entities in relation 
to large utilities. Where a joint action agency accepts compliance 
responsibility and a standard is susceptible to joint action agency-
level assessment of compliance, the Commission should ask NERC to adopt 
such assessment to avoid an adverse impact on competition.
    105. MEAG finds the Commission's proposal with regard to joint 
action agencies problematic. MEAG asserts that the proxy approach is 
not a universal approach to small municipal systems. For example, this 
option would be fundamentally inconsistent with MEAG's role as a G&T 
cooperative serving its member systems because MEAG has no authority to 
plan, physically operate, modify, maintain or test the local 
distribution system facilities of the member systems. Second, MEAG 
states that if it were to assume the role of the proxy compliance agent 
for the member systems and incur a fine for the failure of a few to 
comply with the requirements of the Reliability Standards, then the 
imposition of fines would lead to a rate increase to all systems, an 
improper and unjustifiable cost shifts among the member systems. Third, 
if MEAG were to err in its role as a proxy compliance agent for the 
member systems, MEAG could be sued and there is nothing that presently 
limits its liability or provides indemnification to MEAG in that 
circumstance. Moreover, MEAG states that the compliance-by-proxy option 
will not mitigate the economic impact on many small distribution-only 
entities because many are not members of joint action agencies.
    106. Several commenters, including EEI, PJM and FirstEnergy do not 
oppose the Commission's proposal to allow organizations to accept 
compliance responsibility on behalf of members so long as compliance 
responsibility is clear and responsible entities are held accountable. 
FirstEnergy and PJM state that some Reliability Standards appear to 
have duplicate accountability in different organizational entities, 
which could create confusion and complicate operational authority and 
thus undermine the transmission operator chain of command required to 
respond quickly and decisively to system operational events. Further, 
FirstEnergy

[[Page 16429]]

states that some Reliability Standards obligate an entity to perform 
reliability functions when that entity may not be able to perform its 
reliability function due to other legal constraints. FirstEnergy states 
that one effective approach to resolving this problem would be to 
establish a ``priority'' of control between entities. FirstEnergy adds 
that entities that are subject to legal control by ISOs and RTOs should 
be afforded a ``safe harbor'' under the Reliability Standards if, 
during an emergency, they perform as directed by the ISO or RTO, 
whether under the ISO/RTO's OATT or under the ISO/RTO's authority as 
reliability coordinator.
ii. Commission Determination
    107. The Commission directs the ERO to file procedures which permit 
(but do not require) an organization, such as a joint action agency, 
G&T cooperative or similar organization to accept compliance 
responsibility on behalf of its members. The Commission believes that 
NERC's proposed procedures described above are reasonable, and directs 
the ERO to submit a filing within 60 days.\67\ In allowing a joint 
action agency, G&T cooperative or similar organization to accept 
compliance responsibility on behalf of its members, our intent is not 
to change existing contracts, agreements or other understandings as to 
who is responsible for a particular function under a Reliability 
Standard. Further, we clarify that there should not be overlaps in 
responsibility nor should there be any gaps.
---------------------------------------------------------------------------

    \67\ Section 39.10(b) of the Commission's regulations, 18 CFR 
39.10(b), provides that the Commission, upon its own motion or upon 
complaint, may propose a change to an ERO or Regional Entity Rule.
---------------------------------------------------------------------------

    108. In response to concerns raised by AMP-Ohio and MEAG, the 
Commission clarifies that an organization is not required to assume 
compliance responsibility for its members for any reliability-related 
functions and all Reliability Standards. Moreover, under NERC's 
proposal, a member within a central organization may separately 
register to be accountable for a particular reliability function so the 
responsibility for reliability functions can be split. The Commission 
believes that this will provide flexibility and will not require an 
entity to assume responsibility where it is not possible to do so. We 
also believe that NERC's proposal adequately addresses TAPS' concern 
that a joint action agency should be allowed to achieve compliance at 
the joint action agency level. Specifically, the Statement of 
Compliance Registry Criteria provides that a central organization can 
register for all functions that it performs itself and, in addition, 
may register on behalf of one or more of its members for functions for 
which the member would otherwise be required to register.\68\
---------------------------------------------------------------------------

    \68\ See NERC Supplemental Filing, Statement of Compliance 
Registry Criteria (Revision 3), at 8-9.
---------------------------------------------------------------------------

    109. NERC, in developing its procedures relating to joint action 
agencies and similar organizations, should consider the concerns of 
EEI, PJM and FirstEnergy regarding the need for ensuring clear lines of 
responsibility. While we agree with FirstEnergy in the abstract that an 
entity implementing the legal directives of an ISO or RTO should not be 
penalized for following an ISO or RTO directive during an emergency, we 
will not mandate a safe harbor provision for such circumstances. 
Rather, these and other matters should be considered by the ERO or a 
Regional Entity when deciding the appropriate enforcement action in 
response to an event where a violation of a Reliability Standard may 
have occurred.
3. Definition of User of the Bulk-Power System
    110. In the NOPR, the Commission did not propose a generic 
definition of the term ``User of the Bulk-Power System.'' Rather, the 
Commission stated that it would determine applicability on a standard-
by-standard basis.\69\ The NOPR explained that Sec.  40.1(b) of the 
proposed regulations would require the ERO to identify in each proposed 
Reliability Standard the specific subset of users, owners and operators 
of the Bulk-Power System to which the proposed Reliability Standard 
would apply, which is NERC's current practice. The NOPR also stated 
that entities concerned that a particular proposed Reliability Standard 
would apply more broadly than the statute allows may raise their 
concerns in the context of the specific Reliability Standard.
---------------------------------------------------------------------------

    \69\ NOPR at P 43.
---------------------------------------------------------------------------

a. Comments
    111. APPA disagrees with a standard-by-standard approach to 
defining the term ``user of the Bulk-Power System'' because it would go 
beyond those facilities that are required to maintain the reliability 
of the high-voltage, bulk transmission system and intrude into state 
and local matters and trespass on state jurisdiction. According to 
APPA, the Reliability Standards themselves state their applicability in 
terms of the Functional Model, which does not include size limitations 
in the various functional categories included in it. Without some type 
of outer limit on the ``user of the Bulk-Power System'' definition, all 
such entities regardless of size or their impact on the Bulk-Power 
System, must review every proposed Reliability Standard and protest 
every time they have a ``concern in the context of the specific 
Reliability Standard.'' They must also retain permanent staff or 
consultants to evaluate new or revised standards. Rather, APPA, as does 
TANC, urges the Commission to support NERC's registry criteria to make 
the definition of ``users of the Bulk-Power System'' co-extensive with 
the users on NERC's compliance registry.
    112. SMA is concerned that not specifically defining who is a 
``user of the Bulk-Power System'' will not provide timely notice to 
entities that are not the parties historically responsible for 
implementing NERC's prior reliability standards. SMA states that NERC 
must identify the subset of users that must comply with any given 
Reliability Standard at a sufficiently early stage for all such 
affected parties to have an opportunity to raise objections to the 
sweep or content of the Reliability Standard while approval of that 
Reliability Standard is under consideration. SMA also argues that 
NERC's Rules of Procedure must require actual notice to an entity 
before it is placed on the compliance registry.
    113. Southwest TDUs urges the Commission to clarify that ``users'' 
are entities that have more involvement with it than merely receiving 
power from it. Since these Reliability Standards will become mandatory 
and violation of any of them can be accompanied by economically 
significant penalties, Southwest TDUs urges the Commission to make 
every effort to be specific about what constitutes a ``user.''
    114. California Cogeneration states that the Commission has not 
provided any detail as to how a ``user'' will be identified. The NOPR 
and the NERC Reliability Standards it proposes to adopt rely on the 
broad entities identified in the NERC Functional Model. According to 
California Cogeneration, using only the NERC Functional Model provides 
no detail and no differentiation in the applicability of each 
Reliability Standard. While a single definition of ``user'' may not be 
appropriate, California Cogeneration maintains that using only the 
fixed designations within the NERC Functional Model does not provide 
sufficient specificity. The terms ``Generator Owner'' and ``Generation 
Operator'' also must be qualified so that they only apply to generation 
operations that utilize the grid and exclude

[[Page 16430]]

generation output dedicated to on-site consumption.
b. Commission Determination
    115. The Commission's determination above to rely on the ERO's 
compliance registry process to identify users, owners and operators of 
the Bulk-Power System that must comply with new mandatory and 
enforceable Reliability Standards should resolve the concerns expressed 
by APPA, SMA and others regarding the need to identify and provide 
timely notice to those users of the Bulk-Power System that are expected 
to comply with specific Reliability Standards.
    116. While we recognize the desire of some commenters for a 
concise, generic definition of ``user of the Bulk-Power System,'' we 
are concerned that any attempt to define the term at this time will 
either be overly broad so as not to provide any helpful guidance or 
overly narrow so as to exclude entities that should be covered. The 
Commission believes that it has employed a reasonable approach by 
endorsing NERC's compliance registry process and requiring that each 
Reliability Standard identify the subset of users, owners and operators 
to whom that particular Reliability Standard applies.
4. Use of the NERC Functional Model
    117. NERC has developed a ``Functional Model'' that defines the set 
of functions that must be performed to ensure the reliability of the 
Bulk-Power System. The Functional Model identifies 14 functions and the 
name of a corresponding entity responsible for fulfilling each 
function.
    118. In the NOPR, the Commission proposed to use the NERC 
Functional Model to identify the applicable entities to which each 
Reliability Standard applies.\70\ The Commission explained that 
focusing on the functions an entity performs to identify what entities 
are users, owners and operators of the Bulk-Power System, and thus what 
entities are subject to the Reliability Standards, provides a useful 
level of detail and appears to be more practical than simply 
identifying an applicable entity as a user, owner or operator. In 
addition, the NOPR recognized concerns that the Functional Model may 
contain ambiguities and proposed to require NERC to specifically 
address these concerns.
---------------------------------------------------------------------------

    \70\ NOPR at P 46-48.
---------------------------------------------------------------------------

    119. The Commission proposed that, because the Functional Model is 
linked to applicability of the Reliability Standards, the ERO should 
submit for Commission approval any future modifications to the 
Functional Model that may affect the applicability of the Reliability 
Standards.
a. Filing the Functional Model With the Commission
i. Comments
    120. NERC states that, while it believes that the Functional Model 
should be filed for informational purposes only, it will submit any 
changes to the Functional Model to the Commission for approval as 
requested. While NERC states that the Functional Model will not 
function as a legally binding document like a Reliability Standard, the 
Commission's approval of this reference document and of any changes to 
the Functional Model will support the development of high quality, 
enforceable and technically sufficient standards.
    121. Several commenters, including NERC, EEI, APPA, MidAmerican, 
National Grid and MRO state that the Functional Model is not part of 
the Reliability Standards and should be filed with the Commission for 
informational purposes only. They generally state that the Functional 
Model is not a definitive guide to the ``users, owners and operators'' 
of the Bulk-Power System and should not be used to establish 
obligations under section 215, which should be established within each 
individual Commission-approved Reliability Standard.
    122. Northeast Utilities is concerned with the Commission's 
proposal to use the NERC Functional Model to identify applicable 
entities. It believes that the Functional Model can be useful in 
drafting standards, but it is not a substitute for having clear 
definitions of the entities responsible for compliance with the 
requirements for each Reliability Standard within a region. The 
entities responsible for meeting the standard may vary depending on how 
the Bulk-Power System is operated. FirstEnergy states that the 
Functional Model may not clearly or correctly identify the entities to 
which a Reliability Standard applies and maintains that the Functional 
Model should be applied only where all of the affected stakeholders 
agree on the final classifications of each Registered Entity's roles 
and responsibilities.
    123. In contrast, TANC and ISO-NE state that the Commission should 
require that any future modification to the Functional Model that could 
affect the categories of entities that must comply with a particular 
Reliability Standard be approved by the Commission because the 
Functional Model is so closely interrelated with the applicability of 
each Reliability Standard.
    124. APPA, TAPS and ReliabilityFirst maintain that any modification 
to the NERC Functional Model should be reviewed and approved through 
the Reliability Standards development process. According to 
ReliabilityFirst, any change to the Functional Model is essentially an 
amendment to the Reliability Standard made outside the ERO process. 
TANC asserts that a Reliability Standard will only be complete if the 
definitions of the Functional Model are developed through the 
Reliability Standards development process just like any Reliability 
Standard. APPA would allow NERC to issue interpretations of the 
Functional Model, but these interpretations should then be confirmed 
through NERC procedures.
    125. TAPS cautions that, because the Functional Model includes no 
express size limitations, NERC and the Commission can rely on the 
Functional Model to define applicability of standards only if such 
limits are imposed by NERC's compliance registry criteria and its bulk 
electric system definition. The Small Entities Forum is concerned 
because smaller entities have historically performed only a subset of 
functions. For example, it states that some joint action agencies 
invest in transmission facilities that are operated by others, but that 
these joint action agencies, under the Functional Model, would have to 
verify that these facilities, operated by others, are being operated 
and maintained according to applicable Reliability Standards.
    126. Several commenters argue that the Functional Model contains a 
number of ambiguities. MISO argues that the definition of the term 
planning coordinator is circular and may lead to one subset of the 
transmission system having multiple Planning Coordinators. MISO 
recommends that the Commission direct NERC to survey the industry to 
identify the planning roles that actually exist in the industry and 
clarify the role of the wide-area Planning Coordinator. MISO and 
Wisconsin Electric note that the proposed Reliability Standards do not 
specify who fulfills the Interchange Authority or Planning Authority 
roles, and there is no common industry understanding of those roles. 
Finally, California Cogeneration states that the definition of LSE is 
too inclusive and should be modified to exclude entities providing 
service only to loads on-site or pursuant to private contract.

[[Page 16431]]

ii. Commission Determination
    127. The Commission accepts the characterization offered by 
numerous commenters that the Functional Model is an evolving guidance 
document that is not intended to convey firm rights and 
responsibilities. Further, we agree that the applicability section of a 
particular Reliability Standard should be the ultimate determinant of 
applicability of each Reliability Standard. In light of this, we will 
not require the ERO to submit revisions of the Functional Model for 
Commission approval. While some commenters suggest that revisions be 
filed for informational purposes, we see little value in mandating such 
a filing.\71\
---------------------------------------------------------------------------

    \71\ We note that NERC has available on its Web site, http://
www/nerc.com, the current version of the Functional Model. We expect 
NERC to continue to do so in the future.
---------------------------------------------------------------------------

    128. With regard to the comments of TAPS, APPA, TANC and others on 
whether revisions to the Functional Model should be made through the 
ERO's Reliability Standards development process, we do not believe that 
it is necessary under the statute, since applicability will be 
determined at this time by the specifications of the Reliability 
Standards and the compliance registry process. Thus, we leave to the 
discretion of the ERO the appropriate means of allowing stakeholder 
input when revising the Functional Model. To the extent that changes in 
the Functional Model require revised specification in the Reliability 
Standards, the latter will be addressed in the Reliability Standards 
development process.
    129. While TAPS and Small Entities Forum raise concerns regarding 
the absence of size limitations in the Functional Model and potential 
negative impacts on small entities, we believe that these concerns are 
addressed above in our decision regarding use of the NERC compliance 
registry process. MISO, Wisconsin Electric and others comment on the 
need to clarify certain ambiguities in the Functional Model. Given that 
the Functional Model is an evolving guidance document, the ERO can 
address such concerns as it updates and revises the Functional Model.
b. Responsibility for Functions Within the Functional Model
    130. In the NOPR, the Commission explained that, in the context of 
an ISO or RTO or any organization that pools resources, decision-making 
and implementation are performed by separate groups.\72\ The ISO or RTO 
typically makes decisions for the transmission operator and, to a 
lesser extent, the generation operator, while actual implementation is 
performed by either local transmission control centers or independent 
generation control centers. The NOPR proposed that ``all control 
centers and organizations that are necessary for the actual 
implementation of the decisions or are needed for operation and 
maintenance made by the ISO or RTO or the pooled resource organizations 
are part of the transmission or generation operator function in the 
Functional Model.'' \73\
---------------------------------------------------------------------------

    \72\ NOPR at P 236.
    \73\ Id. at P 237. Although discussed in the context of the 
communication (COM) Reliability Standards, the NOPR suggested that 
the proposal would apply to other Reliability Standards. Because of 
the nature of the comments on the issue and its relationship to the 
Functional Model, we discuss the matter here.
---------------------------------------------------------------------------

i. Comments
    131. A number of commenters raise concerns or seek clarification 
regarding the relationship between the Functional Model and existing 
agreements that set forth the responsibility of various entities, 
particularly in the context of ISO and RTO operations. MISO requests 
the Commission to clarify that nothing in the Functional Model requires 
one entity to be responsible for all of the tasks within a function, 
regardless of who actually performs the task. In those ISOs and RTOs 
where balancing authorities have retained and have never delegated to 
the RTO certain tasks that fall within the balancing authority 
function, NERC's Functional Model should only require one responsible 
entity per task rather than one responsible entity for all of the tasks 
within that function. MISO submits that the NERC Functional Model 
should not play a prescriptive role by assigning responsibility for a 
given task where such an assignment would be inconsistent with a 
Commission-approved regional transmission agreement, RTO tariff, or 
reliability plan filed with NERC, all of which specify the entity 
performing each task.
    132. PJM states that, while the Commission proposed to assign 
responsibility for reliable operations to multiple entities within an 
ISO or RTO to address its concern that decision making and 
implementation are performed by separate organizations, it does not 
believe that increasing the number of organizations responsible for a 
given function for the same facilities within the bulk electric system 
has been shown to be an effective or appropriate solution to the 
concerns cited. PJM states that NERC employs processes that 
successfully manage the delegation of operational tasks while 
maintaining single entity accountability for the reliable performance 
of those operational tasks.
    133. ATC states that Regional Entities should be given the 
flexibility to allow some ``tasks'' within a ``function'' to be 
performed by one entity, with the remaining tasks to be performed by 
another entity. According to ATC, this would provide entities--
particularly smaller ones--with the flexibility to transfer their 
responsibility for a reliability task or function to another registered 
entity that can perform the work more effectively. Further, ATC 
maintains, Regional Entities should ensure that entities be given 
accountability only for systems, facilities and functions over which 
they actually have control.
    134. NPCC states that requirements applicable to local control 
centers should be distinct from requirements applicable to transmission 
and generation operators under the NERC Functional Model. NPCC submits 
that there is a difference between being assigned to do a task and 
being responsible for the completion of that task. An organization that 
registers with NERC as performing a function is considered a 
responsible entity and must ensure that all tasks are performed. While 
an organization may delegate a task to another organization, it may not 
delegate its responsibility for ensuring that the task is accomplished.
    135. According to Ontario IESO, the Commission's proposal is 
inconsistent with the NERC Functional Model, which envisions one 
responsible entity for each reliability function. In contrast, the 
Commission's proposal would split the same function between different 
organizations such as an ISO and a local control center. PJM claims 
that, under the Functional Model, single entity registration is a 
foundational cornerstone for ensuring clear responsibility and 
accountability for compliance with Reliability Standards.
    136. Ontario IESO asserts that the Commission's proposal is also 
problematic because in the event of a violation it will be difficult to 
determine who violated the Reliability Standard--the entity making the 
decision or the entity implementing the decision. Ontario IESO argues 
that, although the NERC Functional Model is not foolproof, it avoids 
complications by distinguishing between responsibility and performance. 
The ISO is the responsible entity and it delegates some of its tasks to 
local control centers, but retains the overall responsibility.
    137. According to Ontario IESO, NERC has recognized that, although

[[Page 16432]]

organizations such as local control centers play an important role in 
reliability, they are not responsible entities. Therefore, NERC has 
made such organizations subject to compliance audits and placed other 
requirements on them. In addition, NERC intends that the regional 
reliability plans will document the relationships between the local 
control centers and the entity that delegates its responsibility to 
such centers. The current framework has a mechanism for accommodating 
reliability considerations for organizations such as local control 
centers. In this regard, NERC's ongoing formal certification of 
reliability coordinator, balancing authority and transmission provider 
will be useful in determining any delegation of tasks to local control 
centers that must take place for a clear demarcation of 
responsibilities. Ontario IESO advises that, since NERC has not 
finished this task, the Commission should defer its decision in this 
regard.
    138. ISO/RTO Council states that the Commission should not use the 
term ``local control center'' because it will cause confusion. The NERC 
Functional Model does not define the term and it means different things 
in different regions. For example, in MISO, which consists of 25 
balancing areas, ``local control center'' is an equivalent term for 
balancing area although this was probably not the Commission's intent 
in the NOPR. Therefore, ISO/RTO Council argues that the Reliability 
Standards should be limited to defining the tasks in the context of 
users, owners and operators of the Bulk-Power System; any delegation of 
responsibilities to a local control center or any other organization 
should take place in the context of ISO/RTO governing documents, 
operating agreements, tariffs and other arrangements with transmission 
owners and related stakeholders. This approach, according to ISO/RTO 
Council will address the Commission's concerns with respect to local 
control centers without preempting possible regional solutions.
    139. FirstEnergy believes that, while independent authority to 
operate the transmission system should be self-evident, in RTO 
environments with local control centers, the tasks performed by each 
entity do not encompass the entirety of tasks performed by the 
transmission operator under the Functional Model. It suggests that NERC 
should revise the Functional Model to create certification and 
registration requirements for local control authorities within RTOs 
that perform real-time operations of the transmission system. 
FirstEnergy states that a revised NERC Functional Model should 
recognize local control centers that take some direction from RTOs yet 
maintain authority to act independently to carry-out functional tasks 
that require real-time operation of the system. According to 
FirstEnergy, the required registration and certification of such 
entities would clearly indicate the need for operational personnel in 
these control rooms to be NERC-certified. It concludes that at a 
minimum, a NERC certification for the tasks performed by such local 
control center individuals would be an enhancement over the current 
situation.
    140. ISO-NE argues that the Commission should not mandate that the 
tasks performed by local control centers be included in the definition 
of transmission operator because to do so would be to suggest that a 
local control center has independent autonomy in operating the Bulk 
Power System which would conflict with the ``one set of hands on the 
wheel'' philosophy. It explains that local control center personnel in 
New England implement tasks delegated to them by ISO-NE for operation 
of designated transmission facilities. Therefore, ISO-NE submits, the 
scope of the Reliability Standard need not be expanded.
ii. Commission Determination
    141. In response to the many concerns of commenters, the Commission 
clarifies that it did not intend to change existing contracts, impose 
new organizational structures or otherwise affect existing agreements 
that set forth the responsibilities of various entities. Rather, its 
intent was to allow enough granularity in the definitions so that the 
appropriate user, owner or operator of the Bulk-Power System would be 
identified for each Reliability Standard. We agree also with MISO's 
statement that nothing in the Functional Model requires one entity to 
be responsible for all of the tasks within a function, regardless of 
who actually performs the task.
    142. The Commission's concern is that, particularly in the ISO, RTO 
and pooled resource context, there should be neither unintended 
redundancy nor gaps for responsibilities within a function. In 
particular, the Commission is concerned that such ``gaps'' could occur 
in the context of several Reliability Standards addressing matters 
related to activities other than directing or implementing real-time 
operations.\74\ For example, the involvement of a transmission operator 
at an ISO or RTO with respect to the requirements related to 
telecommunications facilities (COM-001-1) from the local control room 
and blackstart restoration plans (EOP-005-0) may be minimal. Because 
the operators at local control centers actually perform all or most of 
the tasks contemplated under various Reliability Standards, we are 
concerned that there may be unintended gaps in such responsibilities if 
the existing contracts between the ISO or RTO and owners of the 
facilities do not address such responsibilities.
---------------------------------------------------------------------------

    \74\ See, e.g., CIP-001--Sabotage Reporting; COM-001--
Telecommunications; EOP-003--Load Shedding Plans; EOP-004--
Disturbance Reporting; EOP-005--System Restoration Plans; EOP-008--
Plans for Loss of Control Center Functionality; PRC-001--System 
Protection Coordination; PRC-007--Assessing Consistency with Entity 
Underfrequency Load Shedding Programs with Regional Reliability 
Organizations UFLS Program Requirements; PRC-009--Analysis and 
Documentation of Underfrequency Load Shedding Performance Following 
an Underfrequency Event; PRC-010--Technical Assessment of the Design 
and Effectiveness of Undervoltage Load Shedding Program; PRC-022--
UFLS Program Performance; and TOP-006--Monitoring System Conditions.
---------------------------------------------------------------------------

    143. In response to MISO, we did not intend to be prescriptive in 
assigning tasks to specific entities. The intent was to allow 
flexibility in identifying the actual user, owner or operator of the 
Bulk-Power System that would be responsible for complying with the 
Requirements in the Reliability Standards. One approach could be that 
the RTO, ISO or other pooled resource registers as the transmission 
operator pursuant to the NERC compliance registry process and, while 
retaining ultimate responsibility, assigns specific tasks to be 
performed by what are sometimes known as local control centers or other 
relevant organizations. Alternatively, the local control center 
operators could register together with the RTO, ISO or pooled resources 
as transmission operators clearly delineating their specific 
responsibilities with regard to the Requirements of particular 
Reliability Standards. Such joint registration must assure that there 
is no overlap between the decisionmaking and implementation functions, 
i.e., that there are not two sets of hands on the wheel. Again, our 
intent is to ensure that there is neither redundancy nor gap in 
responsibility for compliance with the Requirements of a Reliability 
Standard, while allowing entities flexibility to determine how best to 
accomplish this goal.
    144. Consistent with our above explanation, we agree with NPCC that 
there is a difference between being assigned to perform a task and 
being responsible for completing the task. The organization that 
registers with NERC to perform a function will be the

[[Page 16433]]

responsible entity and, while it may delegate the performance of that 
task to another, it may not delegate its responsibility for ensuring 
the task is completed.
    145. Accordingly, the Commission directs that the ERO, in 
registering RTOs, ISOs and pooled resource organizations (or, indeed in 
registering any entity), assure that there is clarity in the assigning 
responsibility and that there are no gaps or unnecessary redundancies 
with regard to the entity or entities responsible for compliance with 
the Requirements of each relevant Reliability Standard. Accordingly, 
although the Commission is not requiring NERC to amend the Functional 
Model, we believe our concerns can be addressed by having the ERO, 
through its compliance registry process, ensure that each user, owner 
and operator of the Bulk-Power System is registered for each 
Requirement in the Reliability Standards that relate to transmission 
owners to assure there are no gaps in coverage of the type discussed 
here.
5. Regional Reliability Organizations
    146. The NOPR stated that 28 proposed Reliability Standards would 
apply, in whole or in part, to a regional reliability organization.\75\ 
Further, many of the proposed Reliability Standards that have 
compliance measures refer to the regional reliability organization as a 
compliance monitor. The Commission stated in the NOPR that it was not 
persuaded that a regional reliability organization's compliance with a 
Reliability Standard can be enforced as proposed by NERC because it 
does not appear that a regional reliability organization is a user, 
owner or operator of the Bulk-Power System.
---------------------------------------------------------------------------

    \75\ NOPR at P 54.
---------------------------------------------------------------------------

    147. The Commission proposed to approve and direct modification of 
five Reliability Standards that apply partially to regional reliability 
organizations. For the other Reliability Standards that apply to 
regional reliability organizations, the Commission proposed, as an 
interim measure, to direct the ERO to use its authority pursuant to 
Sec.  39.2(d) of our regulations to require users, owners and operators 
to provide to the regional reliability organizations information 
related to data gathering, data maintenance, reliability assessments 
and other process-type functions. The NOPR explained that this approach 
is necessary to ensure that there will be no gap during the transition 
from the current voluntary system to a mandatory system in which 
Reliability Standards are enforced by the ERO and Regional Entities. 
The NOPR proposed that, in the long run, Regional Entities should be 
made responsible, through delegation from the ERO, for the functions 
currently performed by the regional reliability organizations. To 
implement this, the Commission proposed the modification of delegation 
agreements to require the Regional Entities to assume responsibility 
for noncompliance. In addition, the Commission proposed that the 
Reliability Standards should be modified to apply to the users, owners 
and operators of the Bulk-Power System that are responsible for 
providing information. The Commission proposed to require that any 
Reliability Standard that references a regional reliability 
organization as a compliance monitor be modified to refer to the ERO as 
the compliance monitor.
    148. The Commission stated that, while it is important that the 
existing regional reliability organizations continue to fulfill their 
current roles during the transition to a regime where Reliability 
Standards are mandatory and enforceable, the Commission does not 
understand why, once the transition is complete, a regional reliability 
organization should play a role separate from a Regional Entity whose 
function and responsibility is explicitly recognized by section 215 of 
the FPA. The Commission sought comment on whether there is any need to 
maintain separate roles for regional reliability organizations with 
regard to establishing and enforcing Reliability Standards under 
section 215.
a. Comments
    149. NERC believes it can remove references to regional reliability 
organizations and Regional Entities from the Reliability Standards, 
with the exception of retaining the Regional Entities as the compliance 
enforcement authorities. However, NERC and California PUC request that 
the Commission reconsider its proposal to direct that the ERO be listed 
as the compliance monitor in each Reliability Standard. California PUC 
states that naming NERC as the compliance monitor deprives the Regional 
Entities of their enforcement role under section 215. NERC believes it 
will be clearer, and consistent with the delegation agreements, to 
designate the Regional Entity as the compliance monitor in almost all 
Reliability Standards. According to NERC, this would also be helpful to 
distinguish those few Reliability Standards that are monitored directly 
by NERC.
    150. ReliabilityFirst, TANC and SoCal Edison agree with the 
Commission that regional reliability organizations and Regional 
Entities cannot be users, owners or operators of the Bulk-Power System 
and should not be subject to compliance with Reliability Standards. 
TANC states that Reliability Standards that reference a regional 
reliability organization need to be revised to reference a user, owner 
or operator of the Bulk-Power System in order to comply with the 
statute.
    151. EEI agrees with the Commission's proposal to direct the ERO to 
require users, owners and operators to provide the information related 
to data gathering, data maintenance, reliability assessments and other 
process-type functions that previously have applied to regional 
reliability organizations. EEI also agrees that, in the long run, it is 
appropriate to make the Regional Entities responsible through 
delegation from the ERO for various functions now performed by regional 
reliability organizations. In doing so, and during the transition in 
particular, EEI maintains that it is important that functions now 
performed by the regional councils, such as planning, be continued.
    152. A number of commenters discuss the possible ongoing role for a 
regional reliability organization. For example, Ontario IESO, NPCC and 
National Grid state that the Commission should recognize that the 
regional reliability organizations will continue to play a role in 
areas including developing regional reliability plans and adequacy 
requirements that are outside the jurisdiction of the ERO. NPCC states 
that enforcement of adequacy requirements should continue to reside 
with the regional reliability organization. National Grid states that 
the role of regional reliability organizations can be preserved in a 
variety of ways, including requiring obligations currently imposed upon 
regional reliability organizations to be included in the regional 
delegation agreements.
    153. NPCC further maintains that regional reliability organizations 
should continue to function as regional sites for technical expertise 
for enhanced reliability requirements through adopting regionally-
specific criteria. According to NPCC, eliminating the ability for 
regions to develop and propose new criteria that enhance system 
reliability would edge the system closer towards the lowest common 
denominator rather than striving towards operational excellence. 
Further, Ontario IESO and NPCC state that regional reliability 
organizations

[[Page 16434]]

should be allowed to perform certain functions for their members, such 
as system operator workshops, forums for coordination of operations and 
planning and operational readiness conference calls.
    154. Massachusetts DTE comments that a regional reliability 
organization should be allowed to propose a Reliability Standard that 
may exceed or enhance the proposed mandatory Reliability Standards to 
ensure regional reliability. It further states that any regional 
reliability criteria proposed by a regional reliability organization 
should be vetted through a regional stakeholder process and then 
specifically adopted by the appropriate state regulatory authorities.
    155. Although MRO does not oppose regional reliability 
organizations, with regard to establishing and enforcing mandatory 
Reliability Standards, MRO, Constellation and Xcel state that there is 
no need to maintain a separate role for regional reliability 
organizations. Because Regional Entities may perform non-reliability 
functions, Constellation states that maintaining regional reliability 
organizations will result in unnecessary cost. While Constellation has 
no objection to the Regional Entities performing non-statutory 
functions, it states that the Commission should not allow Regional 
Entities to impose Reliability Standards developed by the regional 
reliability organizations as mandatory Reliability Standards.
    156. MidAmerican believes that it will be important to separate the 
compliance functions of the Regional Entities from non-compliance 
functions currently assigned to the regional reliability organizations. 
It states that this can be done by: (1) Separating these functions 
internally in the Regional Entities; (2) separating these functions in 
different organizations; or (3) separating these functions by assigning 
non-compliance related functions currently assigned to the regional 
reliability organizations to other users, owners and operators. This 
will minimize conflicts between the Regional Entity core compliance 
function and the non-compliance regional reliability organization 
requirements.
b. Commission Determination
    157. The Commission adopts the NOPR proposal to eliminate 
references to the regional reliability organization as a responsible 
entity in the Reliability Standards. We conclude that this approach is 
appropriate because, as explained in the NOPR, such entities are not 
users, owners or operators of the Bulk-Power System. NERC indicates 
that it can remove such references, except that the Regional Entity 
should be identified as the compliance monitor where appropriate. While 
the Commission originally proposed that the ERO should be designated as 
the compliance monitor, we agree with NERC's approach and believe that 
identifying the Regional Entity as the compliance monitor will provide 
useful specificity as to which entity will be immediately tasked with 
monitoring compliance with a particular Reliability Standard. However, 
as we stated in Order No. 672, the ERO retains responsibility to ensure 
that a Regional Entity implements its enforcement program in a 
consistent manner, and to periodically review the Regional Entity's 
enforcement activities.\76\
---------------------------------------------------------------------------

    \76\ Order No. 672 at P 654.
---------------------------------------------------------------------------

    158. For those Reliability Standards that identify the regional 
reliability organization as the sole applicable entity, and that relate 
to data gathering, data maintenance, reliability assessments and other 
process-type functions,\77\ the NOPR proposed:
---------------------------------------------------------------------------

    \77\ EOP-007, MOD-011, MOD-013, MOD-014, MOD-015, MOD-024, MOD-
025, PRC-002, PRC-003, PRC-006, PRC-012, PRC-013, PRC-014, PRC-020, 
TPL-005 and TPL-006.

    as an interim measure * * * to direct the ERO to use its 
authority pursuant to Sec.  39.2(d) of our regulations to require 
users, owners and operators to provide to the regional reliability 
organizations the information related to data gathering, data 
maintenance, reliability assessments and other ``process''-type 
functions. We believe that this approach is necessary to ensure that 
there will be no ``gap'' during the transition from the current 
voluntary reliability model to a mandatory system in which 
Reliability Standards are enforced by the ERO and Regional Entities. 
In the long run, we propose to make the Regional Entities 
responsible, through delegation by the ERO, for the functions 
currently performed by the regional reliability organizations. As 
part of this change, the delegation agreements to the Regional 
Entities should be modified to bind the Regional Entities to assume 
these duties and responsibility for noncompliance. In addition, the 
Reliability Standards should be modified to apply through the 
Functional Model, to the users, owners and operators of the Bulk-
Power System that are responsible for providing information.\78\
---------------------------------------------------------------------------

    \78\ NOPR at P 57 (footnotes omitted).

    159. We continue to believe that this is a reasonable interim 
measure, and note that EEI and others support this approach. To ensure 
that the ERO properly and timely addresses this matter, we direct the 
ERO to submit an informational filing within 90 days of the Final Rule 
that describes its plan and schedule for developing both an interim and 
long-term resolution based upon the above direction.
    160. In response to the Commission's inquiry in the NOPR, 
commenters identify a number of possible continuing roles for regional 
reliability organizations. Such activities are beyond the scope of this 
proceeding. Clearly, any such role must be limited to non-statutory 
functions. Some commenters suggest that regional reliability 
organizations may have a role in developing voluntary criteria. 
Regional reliability organizations should not develop voluntary 
criteria that address the same or similar matters as mandatory and 
enforceable Reliability Standards, because that is the responsibility 
of the Regional Entities.\79\
---------------------------------------------------------------------------

    \79\ See ERO Certification Order at P 281.
---------------------------------------------------------------------------

D. Mandatory Reliability Standards

1. Legal Standard for Approval of Reliability Standards
    161. The NOPR explained that section 215(d)(2) of the FPA states 
that the Commission may approve a Reliability Standard if it determines 
that it is just, reasonable, not unduly discriminatory or preferential 
and in the public interest. Further, Order No. 672 laid out a series of 
factors it would consider when assessing whether to approve or remand a 
Reliability Standard.\80\
---------------------------------------------------------------------------

    \80\ Order No. 672 at P 262, 321-37.
---------------------------------------------------------------------------

    162. In response to NERC's suggestion that a proposed Reliability 
Standard developed through its open and inclusive process is assured to 
be ``just, reasonable, and not unduly discriminatory or preferential,'' 
the NOPR explained that:

    While an open and transparent process certainly is extremely 
important to the overall success of implementing section 215 of the 
FPA, an evaluation of any proposed Reliability Standard must focus 
primarily on matters of substance rather than procedure. We will, 
therefore, review each Reliability Standard in addition to the 
process through which it was approved by NERC to ensure that the 
Reliability Standard is just, reasonable, not unduly discriminatory 
or preferential, and in the public interest.\81\
---------------------------------------------------------------------------

    \81\ NOPR at P 74.

    163. Further, with regard to NERC's ``benchmarks'' for evaluating a 
proposed Reliability Standard,\82\ the Commission explained that it 
would not be constrained by such benchmarks in approving or remanding a 
proposed Reliability Standard. Rather, Order No. 672 identified factors 
that the Commission will consider when determining whether a proposed

[[Page 16435]]

Reliability Standard satisfies the statutory requirements.
---------------------------------------------------------------------------

    \82\ Id. at P 9-12. The benchmarks are: applicability, purpose, 
performance requirements, measurability, technical basis in 
engineering and operations, completeness, consequences for 
noncompliance, clear language, practicality, and consistent 
terminology.
---------------------------------------------------------------------------

a. Comments
    164. NERC states that 83 of the Reliability Standards are ``just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest,'' and should therefore be approved and made effective 
as mandatory Reliability Standards. NERC believes that, by following 
NERC's Reliability Standards development process, a Reliability 
Standard should meet the requirement that a standard be ``just, 
reasonable, not unduly discriminatory or preferential.'' Further, NERC 
asserts that, by filing with the Commission the written record of 
development for each Reliability Standard, NERC has given the 
Commission strong evidence that those 83 Reliability Standards are 
just, reasonable, and not unduly discriminatory or preferential.
    165. NERC states that the requirement that a Reliability Standard 
be ``in the public interest'' provides the Commission with broad 
discretion to review and approve a Reliability Standard. According to 
NERC, implicit in the ``public interest'' test is that a Reliability 
Standard is technically sound and ensures an adequate level of 
reliability, and that the Reliability Standards provides a 
comprehensive and complete set of technically sound requirements that 
establish an acceptable threshold of performance necessary to ensure 
reliability of the Bulk-Power System. NERC states that it believes that 
approving those 83 Reliability Standards as enforceable as NERC begins 
operating as the ERO meets this objective and will achieve an adequate 
level of reliability as required by law. NERC asserts that adopting 
fewer of the Reliability Standards would both create potential 
reliability risks and communicate that some aspects of reliability are 
not viewed as important enough to be the subject of mandatory and 
enforceable Reliability Standards under the FPA.
    166. FirstEnergy states that each proposed standard should be 
reviewed against the following criteria: (1) Clarity; (2) technical 
means to comply; (3) practicability; (4) consistency and (5) costs.
b. Commission Determination
    167. The Commission agrees with NERC that an open and transparent 
process is important in implementing section 215 of the FPA and 
developing proposed mandatory Reliability Standards. However, in Order 
No. 672, the Commission rejected the presumption that a proposed 
Reliability Standard developed through an ANSI-certified process 
automatically satisfies the statutory standard of review.\83\ The 
Commission reiterates that simply because a proposed Reliability 
Standard has been developed through an adequate process does not mean 
that it is adequate as a substantive matter in protecting reliability. 
We will, therefore, review each Reliability Standard to ensure that the 
Reliability Standard is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest, giving due weight to the ERO.
---------------------------------------------------------------------------

    \83\ Order No. 672 at P 338.
---------------------------------------------------------------------------

    168. In response to FirstEnergy, the Commission has already laid 
out the factors against which to review a Reliability Standard, as well 
as other considerations.\84\ The Commission has no need to revisit this 
issue.
---------------------------------------------------------------------------

    \84\ Id. at P 262, 321-37. (A proposed Reliability Standard 
must: (1) Provide for the Reliable Operation of Bulk-Power System 
facilities; (2) be designed to achieve a specified reliability goal 
and must contain a technically sound means to achieve this goal; (3) 
be clear and unambiguous regarding what is required and who is 
required to comply; (4) clearly state the possible consequences for 
violating the proposed Reliability Standard; (5) include a clear 
criterion or measure of whether an entity is in compliance with a 
proposed Reliability Standard; (6) achieve its reliability goal 
effectively and efficiently; (7) not reflect the ``lowest common 
denominator.'')
---------------------------------------------------------------------------

2. Commission Options When Acting on a Reliability Standard
    169. In the NOPR, the Commission proposed that, for this 
rulemaking, it would take one of four actions with regard to each 
proposed Reliability Standard: (1) Approve; (2) approve as mandatory 
and enforceable; and direct modification pursuant to section 215(d)(5); 
(3) request additional information; or (4) remand. In fact, the NOPR 
did not propose to remand any proposed Reliability Standard.\85\
---------------------------------------------------------------------------

    \85\ NOPR at P 78-82.
---------------------------------------------------------------------------

    170. With regard to the second category, the Commission explained 
that it would take two separate and distinct actions under the statute. 
First, pursuant to section 215(d)(2) of the FPA, the Commission would 
approve a proposed Reliability Standard, which would be mandatory and 
enforceable upon the effective date of the Final Rule. Second, the 
Commission would direct NERC to submit a modification of the 
Reliability Standard to address specific issues or concerns identified 
by the Commission pursuant to section 215(d)(5) of the FPA.
    171. With regard to the third category, ``request additional 
information,'' the NOPR explained that some Reliability Standards do 
not contain sufficient information to enable the Commission to propose 
a disposition. For those Reliability Standards, the Commission 
identified the needed information, and proposed not to approve or 
remand these Reliability Standards until all the relevant information 
is received. As an example, the NOPR explained that many of the fill-
in-the-blank standards would not be approved or remanded until the 
Commission had received all the necessary information.
a. Comments
    172. Most commenters generally support the Commission's proposal to 
have four courses of action it may take on a Reliability Standard. 
However, Xcel has concerns about the legality of approving many of the 
proposed Reliability Standards as mandatory but, at the same time, 
ordering the ERO to make specific modifications to them. According to 
Xcel, section 215(d) does not expressly create this ``approve but 
modify'' option. To the contrary, section 215(d)(4) suggests that the 
Commission should remand to the ERO a standard that it disapproves ``in 
whole or in part.''
    173. While many commenters support the Commission proposal to 
approve certain Reliability Standards as mandatory and enforceable; and 
direct NERC to modify them pursuant to section 215(d)(5), they are 
concerned that the Commission's directives to modify certain 
Reliability Standards are too prescriptive.\86\ They contend that, in 
prescribing particular requirements, metrics, or specific language to 
be used, the Commission is setting the Reliability Standard outside the 
open Reliability Standards development process and not giving due 
weight to the ERO under section 215 of the FPA. NRECA, for example, 
argues there is a major distinction between (a) requiring a Reliability 
Standard to address a specific matter and (b) requiring (as opposed to 
suggesting) a specific Reliability Standard or requiring a reliability 
matter to be addressed in a specific way. These commenters ask that the 
Final Rule state that a directive to improve a Reliability Standards be 
in the form of an objective to be achieved or concern or deficiency to 
be resolved within the Reliability Standard, rather than a particular 
requirement, metric, or specific language to be used.
---------------------------------------------------------------------------

    \86\ See, e.g., NERC, Entergy, EEI, APPA, National Grid, NRECA, 
TAPS, ISO-NE and Duke.
---------------------------------------------------------------------------

    174. Many commenters request that the Commission require that 
changes to any Reliability Standard be made through NERC's Reliability 
Standard

[[Page 16436]]

development procedure.\87\ NERC states that there are areas where the 
Commission proposes a specific directive on a particular Reliability 
Standard that is well beyond the bounds of current utility practice. 
According to NERC, these recommendations are often derived from the 
Staff Preliminary Assessment or are based on a limited number of 
comments to that assessment. NERC anticipates that the issue of concern 
with respect to these Reliability Standards will be addressed, but the 
results may be somewhat different than anticipated by the Commission. 
Similarly, EEI and Progress state that NERC should not pre-determine 
the outcome of the Reliability Standard development procedure in 
response to the Commission's guidance. Ontario IESO states that the 
Commission should allow its detailed input on the proposed Reliability 
Standards to be considered through Reliability Standards development 
process.
---------------------------------------------------------------------------

    \87\ See, e.g., NERC, EEI, ELCON, CEA, NYSRC, TVA, LPPC, NPCC, 
Ontario IESO, Constellation, Progress and Dynegy.
---------------------------------------------------------------------------

    175. According to EEI, NERC should be permitted to provide, if the 
Commission's guidance for modification of a proposed Reliability 
Standard is not adopted in the Reliability Standard development 
procedure, an explanation for that outcome when it submits the modified 
standard to the Commission for approval. Constellation asks the 
Commission to clarify that, if the ERO Reliability Standards 
development process does not result in a Reliability Standard that 
includes the Commission's proposed modifications, the existing 
Reliability Standard would remain in effect until such time as NERC 
proposes and the Commission approves a different Reliability Standard 
(approved through the Reliability Standards development process).
    176. Manitoba and Northwest Requirements Utilities disagree with 
the Commission's proposal to approve certain Reliability Standards and, 
separately, direct NERC to make modifications. Some commenters, such as 
California PUC, Northwest Requirements Utilities and SMA state that the 
users, owners and operators of the Bulk-Power System should not be 
expected to comply with Reliability Standards that are not finalized or 
need modification. Northwest Requirements Utilities contends that 
complete and clear Reliability Standards and requirements are necessary 
to fair enforcement, particularly if monetary sanctions may apply. 
Manitoba and California PUC state that approving Reliability Standards 
that still require modification would lead to differing interpretations 
of the Reliability Standards and confusion.
    177. CEA asserts that the proposed directives to modify certain 
Reliability Standards, while not remands, reflect engagement in the 
standards-setting process that may interfere with the ERO's ability to 
effectively function as an international body. For example, Manitoba 
states that the Commission's proposed modifications without industry 
input may unintentionally place Manitoba in a position where it must 
recommend that the Government of Manitoba disallow the Commission's 
prescribed modifications to several NERC Reliability Standards, thus 
creating discrepancies between Reliability Standards across North 
America.
    178. FirstEnergy agrees with the Commission's rejection of the 
concept of ``conditional approval'' in favor of approve but modify to 
ensure that enforceable standards are in place. However, it asks that 
the Commission consider waiving, or at least substantially reducing, 
penalties for violations of some enforceable, but yet-to-be-completed 
or modified Reliability Standards because compliance with such 
Reliability Standards may prove difficult to determine. FirstEnergy 
therefore suggests that the Commission exercise due discretion in 
enforcing affected Reliability Standards, especially where the 
Commission itself has found that a standard is incomplete or ambiguous. 
International Transmission agrees that in instances where the 
Commission has proposed material changes to a Reliability Standard and 
its associated measurements, risk factors and Levels of Non-Compliance, 
it may be appropriate for the ERO to exercise enforcement discretion on 
a case-by-case basis.
    179. SoCal Edison is concerned that entities may not have an 
opportunity to (1) review the Reliability Standards that are adopted in 
the Final Rule and (2) make any necessary changes in their operating or 
planning practices in order to incorporate differences between the NOPR 
and the Final Rule. SoCal Edison recommends the Commission specifically 
state the ``effective date'' for compliance with each Reliability 
Standard in its Final Rule. SoCal Edison is concerned because some 
standards have a proposed NERC ``effective'' date after the Final Rule.
    180. Northern Indiana states it is concerned how a June 2007 
effective date will impact electric system reliability during the 
critical summer peak demand period, particularly given the many 
problems with the standards that have been identified. Northern Indiana 
believes the Commission's current actions may, in the near term, create 
a lower probability of success in achieving the Commission's stated 
objectives. Northern Indiana suggests that the traditional summer peak 
season is not a good time to implement broad changes in electric system 
operations, procedures and protocols.
    181. NRECA states it is concerned by the NOPR's efforts to 
establish specific one and three year time frames for resolution of 
various matters. It states that the Commission is authorized to comment 
on priorities and suggest timing, it must allow NERC to follow its 
ANSI-certified Reliability Standards development process.
    182. NERC requests that the Commission provide a directive in the 
Final Rule requiring NERC to address both the Commission's concerns 
with the existing Reliability Standards and all comments filed in this 
rulemaking proceeding suggesting specific improvements to the 
Reliability Standards. NERC states that if the Commission acts on the 
views expressed on a specific Reliability Standard by an individual 
commenter in this rulemaking, it may encourage others to avoid 
participating in the NERC process and instead wait until a proposed new 
or modified Reliability Standard reaches the Commission approval stage 
to express their views on the standards. NERC states that no commenter 
should be entitled to have its comments on a specific Reliability 
Standard resolved by the Commission in this rulemaking proceeding.
    183. NERC maintains that referring all comments to the NERC 
Reliability Standards development process for resolution is consistent 
with NERC's obligation to facilitate an open stakeholder process for 
the development of Reliability Standards. NERC asserts that it gives 
fair consideration to all comments and objections on a proposed new or 
revised Reliability Standard and such comments are either resolved to 
the satisfaction of the commenter, or reasons are stated as to why the 
commenter's recommendation should not be adopted.
b. Commission Determination
    184. The Commission affirms the four possible courses of action 
that it will take with regard to each proposed Reliability Standard: 
(1) Approve; (2) approve as mandatory and enforceable; and direct 
modification pursuant to section 215(d)(5); (3) request additional 
information; or (4) remand. Each course of action is justified and has 
a sound basis in the statute. Xcel questions the

[[Page 16437]]

legality of the second option above, which it incorrectly equates to 
``conditional acceptance.'' Rather, as explained in the NOPR,\88\ the 
Commission is taking two independent actions, both authorized by the 
statute. First, we are exercising our authority, contained in section 
215(d)(2) of the FPA, to approve a proposed Reliability Standard. 
Second, we are directing the ERO to submit a modification of the 
Reliability Standard to address specific issues or concerns identified 
by the Commission, pursuant to section 215(d)(5) of the FPA.\89\ 
Accordingly, we reject Xcel's contention and adopt the NOPR proposal on 
this matter.
---------------------------------------------------------------------------

    \88\ See NOPR at P 79-80.
    \89\ 16 U.S.C. 824o(d)(5) ( ``[t]he Commission * * * may order 
the Electric Reliability Organization to submit to the Commission a 
proposed Reliability Standard or 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.'').
---------------------------------------------------------------------------

    185. With regard to the many commenters that raise concerns about 
the prescriptive nature of the Commission's proposed modifications, the 
Commission agrees that a direction for modification should not be so 
overly prescriptive as to preclude the consideration of viable 
alternatives in the ERO's Reliability Standards development process. 
However, in identifying a specific matter to be addressed in a 
modification to a Reliability Standard, it is important that the 
Commission provide sufficient guidance so that the ERO has an 
understanding of the Commission's concerns and an appropriate, but not 
necessarily exclusive, outcome to address those concerns. Without such 
direction and guidance, a Commission proposal to modify a Reliability 
Standard might be so vague that the ERO would not know how to 
adequately respond.
    186. Thus, in some instances, while we provide specific details 
regarding the Commission's expectations, we intend by doing so to 
provide useful guidance to assist in the Reliability Standards 
development process, not to impede it.\90\ We find that this is 
consistent with statutory language that authorizes the Commission to 
order the ERO to submit a modification ``that addresses a specific 
matter'' if the Commission considers it appropriate to carry out 
section 215 of the FPA.\91\ In the Final Rule, we have considered 
commenters' concerns and, where a directive for modification appears to 
be determinative of the outcome, the Commission provides flexibility by 
directing the ERO to address the underlying issue through the 
Reliability Standards development process without mandating a specific 
change to the Reliability Standard. Further, the Commission clarifies 
that, where the Final Rule identifies a concern and offers a specific 
approach to address the concern, we will consider an equivalent 
alternative approach provided that the ERO demonstrates that the 
alternative will address the Commission's underlying concern or goal as 
efficiently and effectively as the Commission's proposal.
---------------------------------------------------------------------------

    \90\ Moreover, in the NOPR, the Commission first discussed in 
detail its substantive concerns regarding a particular proposed 
Reliability Standard and, to provide greater clarity regarding the 
Commission proposal, then summarized the proposed findings and 
modifications. It appears that such summaries of broader and fuller 
discussions led to misunderstandings of the NOPR proposals.
    \91\ 16 U.S.C. 824o(d)(5).
---------------------------------------------------------------------------

    187. Consistent with section 215 of the FPA and our regulations, 
any modification to a Reliability Standard, including a modification 
that addresses a Commission directive, must be developed and fully 
vetted through NERC's Reliability Standard development process. The 
Commission's directives are not intended to usurp or supplant the 
Reliability Standard development procedure. Further, this allows the 
ERO to take into consideration the international nature of Reliability 
Standards and incorporate any modifications requested by our 
counterparts in Canada and Mexico. Until the Commission approves NERC's 
proposed modification to a Reliability Standard, the preexisting 
Reliability Standard will remain in effect.
    188. We agree with NERC's suggestion that the Commission should 
direct NERC to address NOPR comments suggesting specific new 
improvements to the Reliability Standards, and we do so here. We 
believe that this approach will allow for a full vetting of new 
suggestions raised by commenters for the first time in the comments on 
the NOPR and will encourage interested entities to participate in the 
ERO Reliability Standards development process and not wait to express 
their views until a proposed new or modified Reliability Standard is 
filed with the Commission. As noted throughout the standard-by-standard 
analysis that follows, various commenters provide specific suggestions 
to improve or otherwise modify a Reliability Standard that address 
issues not raised in the NOPR. In such circumstances, the Commission 
directs the ERO to consider such comments as it modifies the 
Reliability Standards during the three-year review cycle contemplated 
by NERC's Work Plan through the ERO Reliability Standards development 
process. The Commission, however, does not direct any outcome other 
than that the comments receive consideration.
    189. We disagree with commenters, such as Xcel, suggesting that the 
Commission should not approve Reliability Standards that we require 
NERC to modify. The Commission is only approving those Reliability 
Standards that it has determined to be just, reasonable, not unduly 
discriminatory or preferential, and in the public interest. As 
discussed more fully in the discussion of the individual Reliability 
Standards, we have determined that each approved Reliability Standard 
is sufficiently clear and independently enforceable. Because we believe 
that these Reliability Standards are enforceable as written, the 
Commission will not exempt them from enforcement.
    190. The Commission disagrees with Northern Indiana that the 
Reliability Standards should not be implemented in summer of 2007.\92\ 
Most or all users, owners and operators of the Bulk-Power System have 
participated in NERC's voluntary reliability regime for years and are 
familiar with the proposed Reliability Standards. Others have had 
notice of the Reliability Standards since they were filed by NERC in 
April 2006. We are not persuaded that making Reliability Standards 
enforceable, most of which were being complied with on a voluntary 
basis, will require broad changes in electric system operations, 
procedures and protocols. Therefore, we do not see any reason to 
further delay implementation of the mandatory Reliability Standards.
---------------------------------------------------------------------------

    \92\ See discussion below regarding the Trial Period, section 
II.D.4.
---------------------------------------------------------------------------

    191. In response to SoCal Edison, Reliability Standards will become 
effective the latter of the effective date of this Final Rule or the 
ERO's proposed NERC effective date. The Commission disagrees with SoCal 
Edison that users, owners and operators of the Bulk-Power System will 
not have an opportunity to review the Reliability Standards that are 
adopted in the Final Rule and incorporate differences between the NOPR 
and the Final Rule into their operating practices. The Reliability 
Standards approved in this Final Rule are approved as proposed by the 
ERO. No changes will be made immediately based on the Commission's 
direction to modify those Reliability Standards. Any modifications will 
be developed through the ERO's Reliability Standards development 
process and should have a

[[Page 16438]]

proposed effective date that will take into account any time needed for 
users, owners and operators of the Bulk-Power System to incorporate the 
necessary changes. Therefore, there is no need for any entity to make 
any changes based on differences between the NOPR and the Final Rule.
    192. NRECA's assertion that the Commission should not establish 
timelines to resolve matters is a collateral attack on Order No. 672. 
In that order, the Commission adopted its regulations to provide that 
the Commission, when ordering the ERO to submit to the Commission a 
proposed Reliability Standard or proposed modification to a Reliability 
Standard that addresses a specific matter, may order a deadline by 
which the ERO must submit a proposed or modified Reliability 
Standard.\93\
---------------------------------------------------------------------------

    \93\ See 18 CFR 39.5(g).
---------------------------------------------------------------------------

3. Prioritizing Modifications to Reliability Standards
    193. As discussed above, the Commission proposed to approve certain 
Reliability Standards and, as a separate action, proposed to direct the 
ERO to modify many of the same Reliability Standards pursuant to 
section 215(d)(5) of the FPA. In the NOPR, the Commission recognized 
that it is not reasonable to expect the modification of such a 
substantial number of Reliability Standards in a short period of time. 
Thus, the NOPR provided guidance on the prioritization of needed 
modifications.\94\
---------------------------------------------------------------------------

    \94\ NOPR at P 85-87.
---------------------------------------------------------------------------

    194. The NOPR proposed that NERC first focus its resources on 
modifying those Reliability Standards that have the largest impact on 
near-term Bulk-Power System reliability, including many of the proposed 
modifications that reflect Blackout Report recommendations. Further, 
the Commission identified a group of Reliability Standards that it 
believes should be given the highest priority by the ERO based on the 
above guidance.\95\ The NOPR explained that the list is not meant to be 
exclusive or inflexible and solicited ERO and commenter input. The NOPR 
proposed that NERC address the ``high priority'' modifications within 
one year of the effective date of the Final Rule.
---------------------------------------------------------------------------

    \95\ Id. at Appendix D (High Priority List).
---------------------------------------------------------------------------

    195. In addition, the NOPR proposed that the ERO promptly address 
certain proposed modifications that are not necessarily identified as 
``high priority'' but may be addressed in a relatively short time frame 
because the proposed modifications are relatively minor or 
``administrative'' in nature. The NOPR further proposed that the ERO 
develop a detailed, comprehensive Work Plan to address all of the 
modifications that are directed pursuant to a Final Rule. The Work Plan 
would take a staggered approach and complete all the proposed 
modifications within either two or three years from the effective date 
of the Final Rule.
    196. As noted above, on December 1, 2006, NERC submitted its Work 
Plan as an informational filing. According to the Work Plan, NERC will 
revise the existing Reliability Standards to incorporate improvements. 
A total of 31 different projects will be completed over a three-year 
period.\96\ Some of the projects address revising a single Reliability 
Standard. The largest project includes revising 19 Reliability 
Standards focusing on related topics. NERC asserts that grouping the 
Reliability Standards in this manner will be the most efficient use of 
the resources and will allow consistency in requirements on related 
standards. NERC states that the Work Plan incorporates modifications 
that were proposed in the NOPR, but it will modify its Work Plan to 
align it with the modifications the Commission orders in the Final 
Rule. In addition, the Work Plan will remain dynamic as new Reliability 
Standards are proposed and priorities evolve. The Work Plan will be 
updated on an annual basis, and more frequently if needed.
---------------------------------------------------------------------------

    \96\ Some projects relate to new Reliability Standards that are 
not before the Commission in the instant rulemaking.
---------------------------------------------------------------------------

    197. According to the Work Plan, NERC will periodically report 
progress and revisions to the Work Plan and timetable to the 
Commission. NERC's intent is to provide accountability for the revision 
and development of Reliability Standards, while recognizing it is 
impossible to have a fixed schedule when working in a consensus-driven 
process addressing complex technical matters.
a. Comments
    198. NERC states that it is pleased that the Commission did not 
propose specific deadlines in the NOPR for completing the directives to 
improve the Reliability Standards. NERC requests that the Commission 
not state specific delivery dates, because developing consensus 
Reliability Standards on complex technical matters within fixed time 
frames may not be realistic in all cases. NERC states that it will 
report the reasons for any delays in the schedule and will work to 
ensure that no unnecessary delays occur due to lack of attention or 
effort.
    199. NERC expresses concern that the Commission suggests in the 
NOPR that it may direct some early modifications to the Reliability 
Standards that appear to provide quick results.\97\ According to NERC, 
because of the procedural requirements of the Reliability Standards 
development process, this would delay work that is more important. NERC 
states that it can make such changes quickly for a particular 
Reliability Standard if there are no other changes to that standard. 
However, NERC's Work Plan contemplates that almost every Reliability 
Standard is to be upgraded; modifying each standard in multiple steps 
would add significant delay.
---------------------------------------------------------------------------

    \97\ NOPR at P 86.
---------------------------------------------------------------------------

    200. APPA similarly cautions the Commission that the industry does 
not have unlimited ability to simultaneously reevaluate the Reliability 
Standards, prepare for NERC's and the Regional Entities' compliance 
monitoring and enforcement programs, and actually plan and operate 
their utility systems on a reliable basis. According to APPA, NERC 
should promptly address the administrative elements of those 
Reliability Standards that are now at best incomplete, with missing 
Compliance Measures, Levels of Non-Compliance and Violation Risk 
Factors. NERC must also deal with the regional fill-in-the-blank 
standards and criteria that have not yet been submitted to either NERC 
or to the Commission for review and approval.
    201. International Transmission states that the Commission should 
not direct NERC to make changes to the Reliability Standards within a 
specific time frame because this would circumvent the Reliability 
Standard development process. It asks the Commission to instruct the 
ERO to initiate the Reliability Standards development process in a time 
frame that would likely result in their presentation to the Commission 
by a desired date, acknowledging that a revised Reliability Standard 
may not reach industry consensus and thus not meet the Commission's 
desired time frame. Further, International Transmission believes that 
the priority of a Reliability Standard for subsequent modification 
should be based on the standard's ``Violation Risk Factor.'' 
Reliability Standards that have the greatest impact on bulk electric 
system reliability should be addressed first. All high risk 
requirements should be addressed in the 2007 Work Plan. International 
Transmission states the addition of Measures and Levels of Non-

[[Page 16439]]

Compliance is neither minor nor administrative in nature, although 
designated by the Commission as such and called for an accelerated time 
period for their addition.
    202. MRO recommends that the Commission place a greater emphasis on 
directing NERC to develop clear and measurable Requirements. If the 
Requirements are not clear and measurable, the Measures and Levels of 
Non-Compliance will be fundamentally flawed. MRO also states that there 
are numerous Requirements that are now part of the Reliability 
Standards that came from elements of the former NERC Operating Manual 
that were never intended as Requirements. It believes that this, in 
part, has created certain difficulties that have resulted in a lack of 
Measures or Levels of Non-Compliance in the Reliability Standards. MRO 
provides examples of such difficulties in its comments regarding 
specific Reliability Standards. MRO suggests grouping each Requirement 
with its associated Measure and Level of Non-Compliance thus making it 
clear to the user, owner or operator as to which Requirements, Measures 
and Levels of Non-Compliance are related thereby reducing confusion.
    203. APPA and Alcoa state that the Commission did not give 
sufficient time for comments on NERC's submitted Work Plan. APPA notes 
that the Work Plan will have to be revised following issuance of the 
Final Rule.
b. Commission Determination
    204. Given the concerns raised by commenters, the Commission will 
not adopt the NOPR's proposal to direct some early modifications to the 
Reliability Standards. We agree with NERC that modifying each 
Reliability Standard first to address administrative concerns, then 
sending it back to the Reliability Standards development process to 
address any modifications directed by the Commission or requested by 
stakeholders, might lead to an unacceptable delay.
    205. While the Commission agrees with International Transmission 
that a good starting point for prioritizing modifications to a 
Reliability Standard could be based on the Reliability Standard's 
``Violation Risk Factor,'' the Commission will not mandate that the ERO 
do so. The ERO should take into account the views of its stakeholders, 
including the concerns raised in this proceeding by APPA, International 
Transmission and MRO, in revising its Work Plan following issuance of 
this Final Rule.
    206. In Order No. 890, the Commission directed public utilities, 
working through NERC, to modify the ATC-related Reliability Standards 
within 270 days of publication of Order No. 890 in the Federal 
Register.\98\ Our action there affects approximately nine MOD 
Reliability Standards and one FAC Reliability Standard that are before 
us in this proceeding. The ERO must submit its revised Work Plan within 
90 days of the effective date of the Reliability Standards approved in 
this order as an informational filing to: (1) Reflect modification 
directives contained in the Final Rule; (2) include the timeline for 
completion of ATC-related Reliability Standards as ordered in Order No. 
890 and (3) account for the views of its stakeholders, including those 
raised in this proceeding.
---------------------------------------------------------------------------

    \98\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, 72 FR 12266(March 15, 2007), 
FERC Stats. & Regs. ] 31,241 (2007) at P 223.
---------------------------------------------------------------------------

    207. The Commission disagrees with NERC that we should not set 
specific delivery dates. A Work Plan with specific target dates will 
provide a valuable tool and incentive to timely address the 
modifications directed in this Final Rule. We note that the ERO 
previously prepared and submitted to the Commission for informational 
purposes one iteration of such a Work Plan that identifies target dates 
for the modification of Reliability Standards. Accordingly, we direct 
the ERO to submit as an informational filing, within 90 days of the 
effective date of this Final Rule, a Work Plan that identifies a plan 
for addressing the modifications to the Reliability Standards directed 
by the Commission in this Final Rule and a schedule with delivery dates 
for completing such modifications. The ERO should make every effort to 
meet such delivery dates. However, we understand that there may be 
certain cases in which the ERO is not able to meet a Commission's 
deadline. In those instances, the ERO must inform the Commission of its 
inability to meet the specified delivery date and explain why it will 
not meet the deadline and when it expects to complete its work.
4. Trial Period
    208. NERC and some commenters to the Staff Preliminary Assessment 
recommended that the Commission establish a ``trial period'' during 
which time the ERO would determine, but not collect, monetary 
penalties. In the NOPR, the Commission expressed concern that a trial 
period that commences with the effective date of mandatory and 
enforceable Reliability Standards may interfere with their being made 
effective by summer 2007. Thus, the NOPR did not propose a trial 
period.\99\
---------------------------------------------------------------------------

    \99\ Id. at P 92-93.
---------------------------------------------------------------------------

    209. However, the Commission recognized that there are entities 
that have not historically participated in the pre-existing voluntary 
reliability system (including some relatively small entities) that may 
not be familiar with what is required for compliance with the proposed 
mandatory Reliability Standards. For such entities, the NOPR proposed 
that the ERO and Regional Entities use their discretion in imposing 
penalties on such entities for the first six months the Reliability 
Standards are in effect. However, the Commission, the ERO and the 
Regional Entities would still retain the authority to impose penalties 
on such entities if warranted by the circumstances.
a. Comments
    210. Most commenters request that the Commission reconsider the 
proposal to reject a trial period during which the Reliability 
Standards are mandatory and enforceable but during which penalties 
would not be assessed for violating a Reliability Standard.\100\ EEI, 
for example, notes that the compliance enforcement program and the 
delegation agreements have not yet been approved by the Commission and 
there may be a short time between their approval and the projected 
start date for enforcing the Reliability Standards. Therefore, 
commenters generally state that a trial period is appropriate to ensure 
that the compliance monitoring and enforcement processes work as 
intended and that entities have time to implement new processes, such 
as required data systems; after June 2007, commenters generally state 
that NERC and the Regional Entities would be able to require remedial 
actions where there is an immediate actual or potential risk to 
reliable interconnected operations. Further, some state that a trial 
period would allow NERC to resolve issues with unfinished standards or 
ambiguous standards for which the Commission has directed improvements. 
If the Commission rejects a six-month trial period, several entities, 
such as EEI, PG&E, Xcel and NYSRC, request that the Commission extend 
NERC's discretionary enforcement to all entities, not just those new to 
the Reliability Standards.
---------------------------------------------------------------------------

    \100\ See, e.g., EEI, APPA, TAPS, EPSA, CAISO, Bonneville, 
California PUC, Cleveland, Otter Tail, Northwest Requirements 
Utilities, TVA and SMA.
---------------------------------------------------------------------------

    211. NPCC essentially agrees with the Commission that there should 
be no trial period, but if the definition of Bulk-Power System is 
substantially altered to

[[Page 16440]]

draw in a broad range of entities that have not traditionally been 
subject to pre-existing reliability standards, a transition period is 
appropriate to bring them into compliance. Where a Reliability Standard 
has missing or incomplete compliance measures, ATC states that the 
Commission should make these standards mandatory to avoid gaps, but not 
assess monetary penalties for non-compliance. ATC agrees with the 
Commission that the new mandatory reliability regime should be 
operational by June 2007, noting that it has been over three years 
since the August 2003 Blackout and over a year since EPAct 2005 was 
enacted.
    212. Several entities state that the Commission's proposal to allow 
the ERO and Regional Entities discretion in setting penalties does not 
go far enough, even if it is applied to all users, owners and operators 
of the Bulk-Power System. For example, SERC maintains that its proposed 
delegation agreement and the NERC Compliance Monitoring and Enforcement 
Program may not allow discretion in imposing penalties.
    213. NERC states that it understands and supports the importance 
the Commission places on the ERO having the ability to impose a 
financial penalty if a Bulk-Power System user, owner or operator 
violates a mandatory Reliability Standard that is in effect, especially 
for egregious behavior. However, NERC continues to maintain that a 
validation period for the compliance process and the calculation of 
penalties is important and proposes a modified approach to that taken 
by the Commission. NERC asks the Commission to authorize NERC and the 
Regional Entities to exercise discretion to calculate financial 
penalties, but not collect them in the case of most violations through 
December 31, 2007. At the same time it asks the Commission to specify 
that in a situation in which an entity violates a clear and well-
understood Reliability Standard that causes a significant disturbance 
on the Bulk-Power System, or in the face of other aggravating 
circumstances such as repeated or intentional violations, the ERO and 
the Regional Entities would have the authority and responsibility to 
hold the offending entity fully accountable for the violation, by the 
assessment of financial penalties.
    214. NERC states that this alternative approach is supported by the 
newness of the compliance enforcement program, the Sanctions Guidelines 
and the penalty matrix, and the Violation Risk Factors, which have not 
been approved by the Commission. Further, NERC claims that initiating 
operations under mandatory Reliability Standards with the collection of 
penalties as the rule rather than the exception may increase the risk 
of numerous legal challenges occurring in the early stages of 
implementing mandatory Reliability Standards, whereas NERC would expect 
a rapid decline in such challenges after its proposed validation 
period. In a reply comment, Xcel supports NERC's proposed approach.
    215. If the Commission rejects NERC's proposed modified approach, 
NERC asks that it and the Regional Entities be given broad discretion 
in setting penalties during this time period and that this discretion 
not be limited to small entities or those who are new to Reliability 
Standards. Avista/Puget also urges the Commission, the ERO and the 
Regional Entities to exercise enforcement discretion more broadly than 
proposed in the NOPR. Penalties should be waived for an initial period 
in several situations, including where a Reliability Standard is 
applied based on new or different interpretations.
    216. Some commenters request that the Commission grant a longer 
trial period in certain cases. For instance, TANC believes that for 
smaller entities the Commission should, at a minimum, adopt a trial 
period of at least one year to provide adequate time to evaluate and 
comply with the new mandatory Reliability Standards. Bonneville and 
NPCC suggest that, for Reliability Standards that have an annual 
reporting requirement, the compliance cycle should start on June 2007 
so that a Reliability Standard that relies on data reporting back into 
the prior year should have an initial compliance measurement date of 
June 2008. AMP-Ohio states that the Commission's proposal does not go 
far enough and suggests a ``ramp-up'' period for entities that are new 
to standards, through and including the entity's first compliance audit 
or, if the Commission rejects this proposal, the Commission should 
extend the trial period from six to twelve months. Reliant also 
advocates a phase-in of penalties over six to twelve months, with an 
increasing scale of penalties over time.
    217. Portland General and Tacoma request that the Commission 
institute a one-year trial period to allow the industry time to 
finalize the language of the mandatory Reliability Standards and to 
allow users, owners and operators time to adapt to the final language. 
For any Reliability Standard that requires modification, Tacoma 
requests that the Commission provide a six-month trial period beyond 
the date when the Reliability Standard is completed. Bonneville asks 
that the Commission extend the trial period for Reliability Standards 
that have missing or ambiguous measures or severity levels until those 
issues are resolved. National Grid states that enforcement discretion 
should not be limited in scope or duration and should be extended to 
any situation in which a Reliability Standard is applied in a novel 
manner, including when a Reliability Standard is interpreted for the 
first time.
    218. PG&E asserts that NERC and the Regional Entities should have 
discretion in imposing fines for violations of Reliability Standards 
during a transition period. Where an entity shows a good faith effort 
to comply with a new or changed Reliability Standard promptly and 
thoroughly, NERC and/or the Regional Entity should be permitted to 
consider those efforts in assessing fines. PG&E suggests a transition 
period of three to six months. Without such discretion, entities may be 
pressured to implement Reliability Standards hastily and inadequately. 
PG&E also notes that some entities in WECC have voluntarily 
participated in WECC's enforcement program. The new regime entails 
procedural and substantive changes. Entities that have complied 
voluntarily should not be penalized by denying them an opportunity to 
adjust.
    219. WECC states that it continues to believe that a trial period 
of more than six months is appropriate, but it is not requesting that 
the Commission revisit its decision on this issue. WECC asks that 
Regional Entities have somewhat greater flexibility in monitoring and 
enforcing compliance during the initial period of implementation. 
According to WECC, the Commission should recognize that, in the early 
stages of implementation, penalties should be reserved for clear 
situations where Registered Entities are refusing to comply. 
Unreasonably harsh enforcement in the early stages of implementation 
may damage the current level of reliability by diverting resources away 
from developing solutions in order to avoid fines and support 
litigation. This flexibility should continue beyond six months after 
the effective date, if necessary, for those Reliability Standards 
requiring modification, until such modifications have become effective.
    220. According to WECC, it is extremely important that United 
States, Canadian and Mexican authorities enforce their respective 
standards within WECC in a way that avoids conflicting obligations. 
WECC thus suggests that the Commission grant WECC substantial 
discretion to focus on education and facilitation of compliance with 
NERC Reliability Standards while

[[Page 16441]]

it seeks to promote consistent enforcement internationally.
b. Commission Determination
    221. The Commission adopts its proposal not to institute a formal 
trial period. As we explained in the NOPR, a trial period is 
inconsistent with mandatory and enforceable Reliability Standards 
taking effect in a timely manner.\101\ The Commission's overriding 
concern is the reliability of the Bulk-Power System, and mandatory and 
enforceable Reliability Standards becoming effective in a timely manner 
are essential to ensuring the reliability of the Bulk-Power System. 
Accordingly, the Commission will not adopt a formal trial period.
---------------------------------------------------------------------------

    \101\ NOPR at P 92.
---------------------------------------------------------------------------

    222. The Commission is, however, also cognizant of commenters' 
concerns. In the NOPR, the Commission proposed that the ERO and 
Regional Entities use their enforcement discretion in imposing 
penalties on entities that historically had not participated in the 
pre-existing voluntary reliability regime, although authority to impose 
a penalty on such an entity would be retained ``if warranted by the 
circumstances.'' \102\ In light of commenters'' concerns, including the 
fact that there are new aspects to the Reliability Standards and the 
proposed compliance program that will apply to all users, owners and 
operators of the Bulk-Power System, the Commission directs the ERO and 
Regional Entities to focus their resources on the most serious 
violations during an initial period through December 31, 2007. This 
thoughtful use of enforcement discretion should apply to all users, 
owners and operators of the Bulk-Power System, and not just those new 
to the program as originally proposed in the NOPR. This approach will 
allow the ERO, Regional Entities and other entities time to ensure that 
the compliance monitoring and enforcement processes work as intended 
and that all entities have time to implement new processes.
---------------------------------------------------------------------------

    \102\ Id. at P 93.
---------------------------------------------------------------------------

    223. By directing the ERO and Regional Entities to focus their 
resources on the most serious violations through the end of 2007, the 
ERO and Regional Entities will have the discretion necessary to assess 
penalties for such violations, while also having discretion to 
calculate a penalty without collecting the penalty if circumstances 
warrant. Further, even if the ERO or a Regional Entity declines to 
assess a monetary penalty during the initial period, they are 
authorized to require remedial actions where a Reliability Standard has 
been violated. Furthermore, where the ERO uses its discretion and does 
not assess a penalty for a Reliability Standard violation, we encourage 
the ERO to establish a process to inform the user, owner or operator of 
the Bulk-Power System of the violation and the potential penalty that 
could have been assessed to such entity and how that penalty was 
calculated. We leave to the ERO's discretion the parameters of the 
notification process and the amount of resources to dedicate to this 
effort. Moreover, the Commission retains its power under section 
215(e)(3) of the FPA to bring an enforcement action against a user, 
owner or operator of the Bulk-Power System.
    224. The Commission believes that the goal should be to ensure 
that, at the outset, the ERO and Regional Entities can assess a 
monetary penalty in a situation where, for example, an entity's non-
compliance puts Bulk-Power System reliability at risk. Requiring the 
ERO and Regional Entities to focus on the most serious violations will 
allow the industry time to adapt to the new regime while also 
protecting Bulk-Power System reliability by allowing the ERO or a 
Regional Entity to take an enforcement action against an entity whose 
violation causes a significant disturbance. Our approach strikes a 
reasonable balance in ensuring that the ERO and Regional Entities will 
be able to enforce mandatory Reliability Standards in a timely manner, 
while still allowing users, owners and operators of the Bulk-Power 
System time to acquaint themselves with the new requirements and 
enforcement program. In addition, our approach ensures that all users, 
owners and operators of the Bulk-Power System take seriously mandatory, 
enforceable reliability standards at the earliest opportunity and 
before the 2007 summer peak season.
    225. National Grid, among others, states that the Commission should 
allow enforcement discretion on an ongoing basis, for example, when the 
ERO or a Regional Entity interprets a Reliability Standard for the 
first time. The Commission agrees that, separate from our specific 
directive that all concerned focus their resources on the most serious 
violations during an initial period, the ERO and Regional Entities 
retain enforcement discretion as would any enforcement entity. Such 
discretion, in fact, already exists in the guidelines; as we stated in 
the ERO Certification Order, the Sanction Guidelines provide 
flexibility as to establishing the appropriate penalty within the range 
of applicable penalties.\103\
---------------------------------------------------------------------------

    \103\ ERO Certification Order at P 451.
---------------------------------------------------------------------------

5. International Coordination
    226. In response to concerns regarding international coordination 
of action on proposed Reliability Standards, the Commission reaffirmed 
its recognition of the importance of international coordination, 
previously discussed in both Order No. 672 \104\ and the ERO 
Certification Order.\105\
---------------------------------------------------------------------------

    \104\ See Order No. 672 at P 400.
    \105\ ERO Certification Order at P 286.
---------------------------------------------------------------------------

a. Comments
    227. Ontario IESO agrees with the Commission ``that NERC's 
development of a coordination process, together with the existing means 
of communications and coordination such as the United States--Canada 
Bilateral Electric Oversight Group will provide the necessary 
mechanisms for international coordination'' and supports the 
coordination process proposed by NERC in its October 18, 2006 filing in 
Docket No. RR06-1-003.\106\
---------------------------------------------------------------------------

    \106\ Compliance Filing of the North American Electric 
Reliability Council and the North American Electric Reliability 
Corporation Addressing Non-Governance Issues, Appendix 3C, Docket 
No. RR06-1-000 (October 18, 2006).
---------------------------------------------------------------------------

    228. EEI and National Grid state that it is not sufficient to 
coordinate remands through NERC alone because both the Commission and 
Canadian provincial authorities have the ultimate say in approving 
applicable Reliability Standards. They advocate that the various 
regulators commit to coordinate through a formal mechanism, such as a 
memorandum of understanding. According to EEI, the Commission should 
coordinate with its international counterparts when directing 
modifications to Reliability Standards to ensure that the resulting 
Reliability Standards are uniform to the greatest extent possible. NPCC 
adds that the Commission should coordinate with its international 
counterparts when proposing to hold, remand or reject a proposed 
Reliability Standard to avoid inconsistencies in Reliability Standards 
application.
    229. National Grid states that, where similar interpretations and 
modifications to Reliability Standards are not adopted by the 
provincial authorities in Canada, there is potential for conflicting 
requirements for interconnected facilities. The Alberta ESO is also 
concerned that, due to regulatory/legislative requirements and industry 
structures in Canada, some of the Reliability Standards may not be 
implemented as they are written.

[[Page 16442]]

Therefore it requests that the Commission require that the 
international coordination process include a provision where variances 
are identified by these international governmental authorities to 
minimize the possibility of a governmental authority remanding a 
Reliability Standard. According to Alberta ESO, while the goal should 
be consistent, North America-wide Reliability Standards, there will be 
instances where this is not achievable.
    230. WIRAB advises that some Canadian provinces or Mexican 
authorities may approve NERC-proposed Reliability Standards with 
changes or modifications. It is important to allow minor variations 
across such jurisdictions to minimize the possibility of a governmental 
authority remanding a Reliability Standard. According to WIRAB, the 
goal should be a consistent system throughout North America with enough 
flexibility for some jurisdictional variation when uniformity is not 
immediately possible.
b. Commission Determination
    231. In the January 2007 Compliance Order, the Commission stated 
that, to minimize the possibility of a governmental authority directing 
a remand, it seemed appropriate for such governmental authorities to 
have an opportunity to provide NERC with input prior to its filing for 
governmental approval of a proposed Reliability Standard.\107\ In that 
order, the Commission agreed with NERC's proposal to facilitate 
informal conferences to provide an opportunity for governmental 
authorities to consult with NERC and stakeholder representatives 
regarding Reliability Standard development work-plans, objectives and 
priorities, and emerging Reliability Standards.\108\ While we did not 
initiate a formal mechanism for coordination as EEI and National Grid 
now suggest, we did state that we anticipate that the Commission and 
counterpart governmental authorities in Canada and Mexico will convene 
regular meetings to coordinate on issues relating to reliability. We 
reaffirm that approach as an appropriate framework for addressing 
matters of international coordination in the context of continent-wide 
Reliability Standards.
---------------------------------------------------------------------------

    \107\ January 2007 Compliance Order at P 44.
    \108\ Id.
---------------------------------------------------------------------------

    232. We agree with Alberta ESO and WIRAB that the goal should be 
consistent, North America-wide Reliability Standards, but that this may 
not be achievable in all instances. For example, in this rulemaking the 
Commission is approving several regional differences in Reliability 
Standards; in the United States, NERC identifies regional variations by 
submitting them to the Commission in the form of a Reliability 
Standard.\109\
---------------------------------------------------------------------------

    \109\ Order No. 672 at P 296.
---------------------------------------------------------------------------

    233. In response to WIRAB, if a governmental authority in Canada or 
Mexico requests that NERC modify a continent-wide Reliability Standard 
rather than create a regional variance, NERC must submit any revised 
Reliability Standard to the Commission. The Commission will then have 
an opportunity to review the proposed revised Reliability Standard, 
taking into account the request of the foreign governmental authority.

E. Common Issues Pertaining to Reliability Standards

1. Blackout Report Recommendation on Liability Limitations
    234. In the NOPR, the Commission stated that the Blackout Report 
recommendations, many of which address key issues for assuring Bulk-
Power System reliability, have received international support and 
represent a well-reasoned and sound basis for action. Thus, in the 
discussion of a particular proposed Reliability Standard, the NOPR 
often recognized the merit of a specific Blackout Report recommendation 
and reaffirmed the reasoning behind such recommendation in proposing to 
approve, with a proposed directive to modify, a specific Reliability 
Standard. Further, the Commission indicated that a modification to a 
proposed Reliability Standard based on a Blackout Report recommendation 
should receive the highest priority in terms of NERC's Work Plan.\110\
---------------------------------------------------------------------------

    \110\ NOPR at P 99-100.
---------------------------------------------------------------------------

    235. The Blackout Report's Recommendation No. 8 recognized that 
timely and sufficient action to shed load on August 14, 2003, would 
have prevented the spread of the blackout beyond northern Ohio, and 
recommended that legislative bodies and regulators should: (1) 
Establish that operators (whether organizations or individuals) who 
initiate load shedding pursuant to operational guidelines are not 
subject to liability suits and (2) affirm publicly that actions to shed 
load pursuant to such guidelines are not indicative of operator 
failure.\111\
---------------------------------------------------------------------------

    \111\ Blackout Report at 147
---------------------------------------------------------------------------

a. Comments
    236. EEI states that the Commission should adopt OATT liability 
limitations to implement Blackout Report Recommendation No. 8 because 
compliance with mandatory Reliability Standards may expose transmission 
operators to liability for actions required by a Reliability Standard; 
Blackout Report Recommendation No. 8 identified this concern and 
recommended that legislative bodies and regulators establish that 
operators who initiate load shedding are not subject to liability. EEI 
disagrees with the suggestion that the Commission cannot shield 
operators from liability suits. EEI states that the Commission has the 
authority under FPA sections 205 and 206 to provide liability 
protection and has done so for several transmission operators in 
several cases by approving amendments to open access transmission 
tariffs providing for liability limitations.\112\ However, it notes 
that the Commission has rejected efforts by other parties to implement 
similar protections.\113\
---------------------------------------------------------------------------

    \112\ EEI at 16, citing Southwest Power Pool, Inc., 112 FERC ] 
61,100 (2005); Midwest Independent Transmission System Operator, 
Inc., 110 FERC ] 61,164 (2005); ISO New England, Inc., 106 FERC ] 
61, 280, order on reh'g, 109 FERC ] 61,147 (2004).
    \113\ Id., citing Southern Company Services, Inc., 113 FERC ] 
61,239 (2005).
---------------------------------------------------------------------------

b. Commission Determination
    237. Consistent with Order No. 890, the Commission does not adopt 
new liability protections.\114\ The Commission does not believe any 
further action is needed to implement Blackout Report Recommendation 
No. 8. First, the Task Force found that no further action is 
needed.\115\ Further, the Blackout report indicated that some states 
already have appropriate protection against liability suits.\116\ 
Finally, in Order No. 888, the Commission declined to adopt a uniform 
federal liability standard and decided that, while it was appropriate 
to protect the transmission provider through force majeure and 
indemnification provisions from damages or liability when service is 
provided by the transmission provider without negligence, it would 
leave the determination of liability in other instances to other 
proceedings.\117\ Order

[[Page 16443]]

No. 890 reaffirmed this decision. EEI has offered no arguments that 
demonstrate that an OATT limit on liability is warranted.
---------------------------------------------------------------------------

    \114\ Order No. 890 at P 1671-77.
    \115\ U.S.-Canada Power System Outage Task Force, Final Report 
on Implementation of Task Force Recommendations at 22 (Oct. 3, 
2006), available at http://www.oe.energy.gov/news/blackout.htm 
(``Action Required at Fully Implement Recommendation 8: No further 
action under this recommendation is needed'').
    \116\ Id. (``In the United States, some state regualtors have 
informally expressed the view that there is appropriate protection 
against liability suits for parties who shed load according to 
approved guidelines.'')
    \117\ Order No. 888-B, 81 FERC ] 61,248 at 62,081 (1997), order 
on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in 
relevant part sub nom. Transmission Access Policy Study Group v. 
FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. 
FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------

2. Measures and Levels of Non-Compliance
    238. The NOPR noted that, according to the Staff Preliminary 
Assessment, a number of proposed Reliability Standards do not contain 
Measures \118\ or Levels of Non-Compliance,\119\ or both. NERC, in its 
petition, identified 21 Reliability Standards that lack Measures or 
Levels of Non-Compliance and indicated that it planned to file modified 
Reliability Standards that include the missing Measures and Levels of 
Non-Compliance in November 2006. On November 15, 2006, NERC made this 
filing.
---------------------------------------------------------------------------

    \118\ Although NERC does not formally define ``Measures,'' NERC 
explains that they ``are the evidence that must be presented to show 
compliance'' with a standard and ``are not intended to contain the 
quantitative metrics for determining satisfactory performance.'' 
NERC Comments to the Staff Preliminary Assessment at 104.
    \119\ ``Levels of Non-Compliance'' are established criteria for 
determining the severity of non-compliance with a Reliability 
Standard. The Levels of Non-Compliance range from Level 1 to Level 
4, with Level 4 being the most severe.
---------------------------------------------------------------------------

    239. In the NOPR, while the Commission recognized the importance of 
having Measures and Levels of Non-Compliance specified for each 
Reliability Standard, the Commission also stated that the absence of 
these two elements is not critical to the determination of whether to 
approve a proposed Reliability Standard. Rather, the most critical 
elements of a Reliability Standard are the Requirements, and, if 
properly drafted, a Reliability Standard may be enforced even in the 
absence of specified Measures or Levels of Non-Compliance.\120\ Thus, 
the NOPR proposed to approve a Reliability Standard even though it may 
lack Measures or Levels of Non-Compliance, or where these elements 
contain ambiguities, provided that the Requirement is sufficiently 
clear and enforceable. Where a Reliability Standard would be improved 
by providing missing Measures or Levels of Non-Compliance or by 
clarifying ambiguities with respect to Measures or Levels of Non-
Compliance, the NOPR proposed to approve the Reliability Standard and 
concurrently direct NERC to modify the Reliability Standard 
accordingly.
---------------------------------------------------------------------------

    \120\ NOPR at P 105-07.
---------------------------------------------------------------------------

    240. The NOPR explained that the common format of NERC's proposed 
Reliability Standards calls for a ``data retention'' metric. Yet, some 
proposed Reliability Standards either do not contain a data retention 
requirement or state that no record retention period applies. In the 
NOPR, the Commission requested comment on: (1) Whether the retention 
time periods specified in various Reliability Standards proposed by 
NERC are sufficient to foster effective enforcement and (2) what, if 
any, additional records retention requirements should be established 
for the proposed Reliability Standards.
a. Improving Measures and Levels of Non-Compliance
i. Comments
    241. A number of commenters raise concerns regarding the adequacy 
of current Measures and Levels of Non-Compliance. Some commenters, such 
as Nevada Companies, state that some Reliability Standards do not need 
multiple Measures and multiple Levels of Non-Compliance when such items 
do not fit the context of the specific Reliability Standard. According 
to Nevada Companies, some proposed Reliability Standards are more like 
business practices that are susceptible to a pass/fail test, and are 
not necessarily amenable to multiple Measures and Levels of Non-
Compliance. Progress and Xcel maintain that Measures and Levels of Non-
Compliance do not necessarily need to be added to every Reliability 
Standard.
    242. Constellation is concerned that the Levels of Non-Compliance 
do not appear to be based on objective criteria, but rather appear to 
be based on arbitrary criteria and assumptions regarding the impact on 
reliability, which could lead to penalties that are excessive compared 
to the violation. MISO states that the original intent of the Levels of 
Non-Compliance was to assign a scale based on the impact on the 
Interconnection. MISO asserts that many Requirements are rated at too 
high a level and that many events that would be rated ``level 4'' are 
really just administrative requirements. It asserts that there are more 
``level 4'' events than other categories, when logic would imply a 
pyramid structure with only a few items at the highest ``level 4.'' 
MISO states there should be a simplified process that measures the true 
impact on reliability. MISO and Dynegy state that there should also be 
an ``administrative infraction'' category created in addition to the 
current ``low,'' ``medium'' and ``high,'' so that the enforcement of 
supporting tasks can be handled expeditiously.
    243. NYSRC states that, in NERC's rush to file with the Commission 
the 20 revised Reliability Standards with new Measures and Levels of 
Non-Compliance, the revised Reliability Standards were submitted to the 
NERC ballot body as a group, rather than individually. It maintains 
that the group treatment prevented stakeholders from providing the 
careful attention that each revised Reliability Standard deserves. 
NYSRC believes that, as a result, Requirements for a number of these 
Reliability Standards are flawed. While their prompt approval may be 
justified to have them in place for the upcoming summer, there is not a 
sufficient basis for the Commission to conclude that the weaknesses 
identified in these 20 Reliability Standards have been adequately 
addressed. NYSRC recommends that the Commission approve the 20 revised 
Reliability Standards and direct the ERO to more carefully address the 
weaknesses identified in those standards and to individually submit 
each revised standard to a ballot for separate consideration.
    244. MISO, International Transmission and Constellation also raise 
concerns with NERC's Violation Risk Factors. They are concerned that 
risk is, in some cases, being confused with importance. For example, 
MISO states that NERC appears to be assigning risk to every sentence in 
each proposed Reliability Standard, including explanatory information 
and administrative requirements, thereby confusing risk with 
importance. MISO states that, while there may be many things that a 
transmission operator does that are important, failure to do an 
important thing one time would not necessarily jeopardize the 
Interconnection or cause a cascading failure.
    245. MISO believes the definition of risk should reflect the 
likelihood that something serious is likely to happen if an event 
occurs. International Transmission, Constellation and MISO believe that 
a high risk event should, in and of itself, pose a significant threat 
to reliability and should not assume that multiple events occur 
simultaneously. According to MISO, only a small number of Requirements 
in the Reliability Standards fit the true definition of high risk. 
Constellation maintains that rating too many Requirements as high risk 
will water down the Requirements, and could shift the focus of 
attention away from the truly high risk Requirements, leading to a less 
effective, less efficient reliability program.

[[Page 16444]]

ii. Commission Determination
    246. With regard to the comments of Nevada Companies, Progress and 
others, we believe that the ERO should have flexibility in initially 
developing appropriate Measures and Levels of Non-Compliance. For 
example, the ERO in the first instance should determine whether a 
Measure is necessary for every Requirement of a particular Reliability 
Standard, or whether every Reliability Standard must have the same 
number of Levels of Non-Compliance. Entities interested in developing 
meaningful Measures and Levels of Non-Compliance should, we find, 
participate in the ERO's Reliability Standards development process to 
ensure that their opinions are considered.
    247. With regard to the concerns of MISO and Constellation, we 
agree as a general principle that Levels of Non-Compliance should be 
based on objective criteria and that a ``level 4'' violation should 
reflect a commensurate level of severity in its impact on Bulk-Power 
System reliability. However, we will allow the ERO in the first 
instance to determine whether specific revisions to particular 
Reliability Standards are needed to address these concerns. While we 
consider the appropriateness of Measures and Levels of Non-Compliance 
in our standard-by-standard review, we believe in the first instance it 
is the responsibility of the ERO to develop meaningful Measures and 
Levels of Non-Compliance, and those seeking to influence the process, 
as we have already found, should participate in the ERO's Reliability 
Standards development process. Likewise, we leave it to the ERO to 
determine initially whether there is any merit in developing a category 
of ``administrative infraction'' as suggested by some commenters.
    248. The Commission agrees with NYSRC that, as a general matter, 
each Reliability Standard should be independently balloted in the 
Reliability Standards development process. However, the Commission will 
not require the ERO to resubmit each of the 20 revised Reliability 
Standards to the Reliability Standards development process for separate 
consideration. We do not believe such an action is required by the 
statute and would otherwise unnecessarily delay implementation of the 
proposed Reliability Standards. However, we expect that the ERO's 
Reliability Standards development process will provide adequate 
opportunity for independent consideration by stakeholders of each 
standard under consideration in the future.
    249. MISO, International Transmission and Constellation raise 
concerns with NERC's Violation Risk Factors. The NERC board approved 
the Violation Risk Factors for Version 0 Reliability Standards and 
submitted them to the Commission on February 23, 2007. The Commission 
is reviewing the Violation Risk Factors in a seprate proceeding in 
Docket No. RR07-9-000. Thus, these issues are not ripe for 
consideration in this Final Rule. MISO, International Transmission and 
Constellation may raise concerns they have with the Violation Risk 
Factors in that separate proceeding.
b. Enforcement Implications
i. Comments
    250. Certain commenters, such as EEI, Northeast Utilities, APPA and 
TAPS, state that Reliability Standards that lack clear Measures or 
Levels of Non-Compliance should not be fully enforced because they are 
not just and reasonable and raise potential due process concerns. APPA 
states that this is equally true of Reliability Standards that lack 
Violation Risk Factors or Violation Severity Levels because there is 
not proper notice as to the amount or range of monetary penalties to be 
assessed for a particular violation. APPA recommends that the 
Commission approve Reliability Standards that lack Measures and 
Violation Severity Levels, but that, until the deficiencies are 
corrected, require NERC and Regional Entities to waive imposition of 
monetary penalties. APPA would, however, reserve the Commission's right 
to impose monetary sanctions where warranted and also require 
compliance with NERC and Regional Entity remedial action directives for 
these Reliability Standards.
    251. WIRAB disagrees that Reliability Standards can be consistently 
enforced based solely on sufficiently clear and enforceable 
Requirements. According to WIRAB, Levels of Non-Compliance are needed 
to inform parties of the consequences of non-compliance. WIRAB is 
concerned that a complex penalty structure that requires Regional 
Entities to consider multiple subjective mitigating and aggravating 
factors will compound the problems of missing and ambiguous Measures 
and Levels of Non-Compliance. A simple penalty structure would reduce 
enforcement ambiguities, increase uniformity and promote greater 
clarity. FirstEnergy states that, without Measures and Levels of Non-
Compliance, a Reliability Standard cannot meet the Commission's 
requirement that a Reliability Standard must have a ``clear criterion 
or measure of whether an entity is in compliance with a proposed 
Reliability Standard.'' \121\
---------------------------------------------------------------------------

    \121\ FirstEnergy at 10-11, citing NOPR at P 16; see also Order 
No. 672 at P 262, 321-37.
---------------------------------------------------------------------------

    252. Progress and Xcel state that the Commission should clarify 
that the Measures and Levels of Non-Compliance are included solely for 
guidance and that only violations of the Requirements are subject to 
penalties. Portland General maintains that the Measures are an integral 
part of each Reliability Standard because entities will need to know 
the Measures so that they can build them into their compliance efforts 
from the beginning. In a similar vein, National Grid states that the 
lack of clear Measures or Levels of Non-Compliance also makes it 
difficult for users, owners and operators to tailor their businesses 
and practices toward compliance or to track ongoing compliance.
ii. Commission Determination
    253. The Commission disagrees with commenters that a Reliability 
Standard cannot reasonably be enforced, or is otherwise not just and 
reasonable, solely because it does not include Measures and Levels of 
Non-Compliance. The Commission adopts the position it took in the NOPR 
that, while Measures and Levels of Non-Compliance provide useful 
guidance to the industry, compliance will in all cases be measured by 
determining whether a party met or failed to meet the Requirement given 
the specific facts and circumstances of its use, ownership or operation 
of the Bulk-Power System. As we explained in the NOPR, and reiterate 
here:

    The most critical element of a Reliability Standard is the 
Requirements. As NERC explains, ``the Requirements within a standard 
define what an entity must do to be compliant * * * [and] binds an 
entity to certain obligations of performance under section 215 of 
the FPA.'' If properly drafted, a Reliability Standard may be 
enforced in the absence of specified Measures or Levels of Non-
Compliance.\122\

    \122\ NOPR at P 105 (footnote omitted).
---------------------------------------------------------------------------

    254. APPA, WIRAB and others contend that, without Measures and 
Levels of Non-Compliance, a Reliability Standard should not be 
enforced. We disagree. Where a Reliability Standard has Requirements 
that are sufficiently clear so that an entity is aware of what it must 
do to comply, sufficient notice has been provided. While it can be 
helpful to provide additional guidance

[[Page 16445]]

regarding the amount or range of monetary penalties that may be 
assessed for a particular violation, the absence of such information is 
not a defect that renders a Reliability Standard unenforceable. Where 
the Requirement in a Reliability Standard is sufficiently clear, an 
entity will know what it should be doing to comply and will know that 
there are consequences for failure to comply. Therefore, where a 
Requirement in a Reliability Standard is sufficiently clear, we approve 
the Reliability Standard even though it may lack Measures or Levels of 
Non-Compliance. Where a Reliability Standard can be improved by 
providing missing Measures or Levels of Non-Compliance or by clarifying 
ambiguities with respect to Measures or Levels of Non-Compliance, we 
approve the Reliability Standard and concurrently direct NERC to modify 
it accordingly.\123\
---------------------------------------------------------------------------

    \123\ APPA raises concerns regarding the completeness or 
adequacy of Measures and Levels of Non-Compliance in its discussion 
of specific Reliability Standards. In such instances, APPA argues 
that the Reliability Standard should not be enforced until current 
Measures and Levels of Non-Compliance are improved or, where 
incomplete, new ones developed. Applying our above rationale to 
these particular circumstances, while the ERO should improve or 
develop Measures and Levels of Non-Compliance where necessary, we 
will not delay the enforcement of such Reliability Standards until 
the ERO develops such improvements or additions.
---------------------------------------------------------------------------

    255. In response to FirstEnergy, where the Requirement in a 
Reliability Standard is sufficiently clear, that Reliability Standard 
meets the requirement that it must have a ``clear criterion or measure 
of whether an entity is in compliance with a proposed Reliability 
Standard.'' The fact that NERC, in certain circumstances, did not 
include Measures and Levels of Non-Compliance does not make an 
otherwise clear Requirement unenforceable. Neither section 215 nor the 
Commission's regulations require the level of specificity sought by 
FirstEnergy in order for a Reliability Standard to be enforceable.
    256. Progress and Xcel seek clarification that Measures and Levels 
of Non-Compliance are included solely for guidance and that only 
violations of the Requirements are subject to penalties. While the 
Commission generally agrees that it is a violation of the Requirements 
that is subject to a penalty, we recognize that because Measures are 
intended to gauge or document compliance, failure to meet a Measure is 
almost always going to result in a violation of a Requirement.
    257. While we applaud NERC for adding additional levels of detail 
to its compliance enforcement program, we note that NERC and the 
Regional Entities should have further guidance as to how to use their 
enforcement discretion from the Commission's Policy Statement on 
Enforcement.\124\ Further, if NERC does not submit Violation Risk 
Factors and Violation Severity Levels before NERC's enforcement program 
becomes effective, the Commission has reserved the ability to take 
appropriate action to ensure that the penalty-setting process described 
in the Sanction Guidelines is operative.\125\
---------------------------------------------------------------------------

    \124\ Enforcement of Statutes, Orders, Rules, and Regulations, 
113 FERC ] 61,068 (2005) (Policy Statement on Enforcement).
    \125\ January 2007 Compliance Order at P 93.
---------------------------------------------------------------------------

c. Data Retention
i. Comments
    258. In the NOPR, the Commission solicited comments regarding the 
sufficiency of data retention requirements in the Reliability 
Standards.\126\ NERC states that the compliance data retention 
requirement is a defined element in the Reliability Standard template 
and that all data retention requirements, even those that are currently 
missing, will be reviewed and updated as part of the Reliability 
Standards Work Plan. NERC requests that the Commission not attempt to 
fix specific data retention requirements on the basis of comments 
received during this proceeding. NERC would prefer that the Commission 
direct those comments and any goals the Commission may have with regard 
to data retention back to NERC for resolution through the Reliability 
Standards development process.
---------------------------------------------------------------------------

    \126\ NOPR at P 107.
---------------------------------------------------------------------------

    259. SoCal Edison supports the data retention requirements in the 
Reliability Standards. APPA and SERC recommend that data retention 
requirements should be stated in each Reliability Standard and 
determined on a case-by-case basis through the Reliability Standards 
development process.
    260. SERC agrees with NERC that an appropriate retention period is 
five years unless otherwise specified in a Reliability Standard. ISO-NE 
submits that any data retention policy established by the ERO should be 
in line with the five year civil penalty statute of limitations for 
violations of NERC Standards, while APPA cautions that detailed 
operational data may be so voluminous that a five-year retention 
requirement would be burdensome and of questionable value. MRO believes 
that the Reliability Standards retention period should be commensurate 
with operating and planning horizons, documentation related to a 
planning standard should be retained longer and that there should be a 
retention period of at least three years.
    261. FirstEnergy states that individual record retention 
requirements on a standard-by-standard basis will create confusion and 
will be difficult to track. It therefore suggests that the Commission 
establish a uniform records retention standard of ``current calendar 
year plus three years'' for all proposed Reliability Standards that 
include a data retention requirement. Similarly, Entergy states that 
data retention requirements established for the Reliability Standards 
should be uniform and asks the Commission to direct the ERO to 
implement records retention requirements of no longer than three years.
    262. International Transmission and Entergy comment that only the 
relevant core reliability requirements of the Reliability Standards 
should be subject to data retention requirements. International 
Transmission states that, in instances where retaining evidence of 
compliance is impractical or where no evidence exists of compliance, it 
is appropriate that no documentation be retained. Otherwise the record 
retention period should be no less than the prevailing audit frequency. 
Progress and Xcel agree that inclusion of data retention metrics in the 
Reliability Standards would be useful, but the Commission should make 
clear that violations of the data retention metrics are not subject to 
separate penalties under section 215 of the FPA.
ii. Commission Determination
    263. The Commission agrees that it is appropriate for each 
Reliability Standard to have a data retention requirement. We are not 
persuaded that a one-size fits all approach to data retention is 
appropriate, however, because different Reliability Standards may 
require data to be retained for shorter or longer periods. Nor are we 
persuaded that the Commission should set a data retention requirement 
for any Reliability Standard for which one is currently lacking. 
Therefore, the Commission will not prescribe a set data retention 
period to apply to all Reliability Standards. Instead, the Commission 
directs the ERO to review and update the data retention requirements in 
each Reliability Standard as it is reevaluated through its Reliability 
Standards development process and submit the result for Commission 
approval. In doing so, NERC should take into account the comments 
raised in this proceeding and should seek input from other industry 
stakeholders.

[[Page 16446]]

3. Ambiguities and Potential Multiple Interpretations
    264. In the NOPR, the Commission proposed that a proposed 
Reliability Standard that has Requirements that are so ambiguous as to 
not be enforceable should be remanded.\127\ A Reliability Standard that 
has sufficiently clear Requirements, Measures and Levels of Non-
Compliance language and otherwise satisfies the statutory standard of 
review should be approved. A proposed Reliability Standard that has 
sufficiently clear Requirements, but Measures or Levels of Non-
Compliance that are ambiguous (or none at all), should be approved in 
some cases with a directive that the ERO develop clear and objective 
Measures and Levels of Non-Compliance language. In other cases, where 
some ambiguity may exist but there is also a common interpretation for 
certain terms based on the best practices within the industry, the 
Commission proposed to adopt that interpretation in the NOPR.
---------------------------------------------------------------------------

    \127\ NOPR at P 110-12.
---------------------------------------------------------------------------

a. Comments
    265. NERC maintains that, even if the Commission believes that 
there is some degree of ambiguity in some of the Reliability Standards, 
making the Reliability Standards mandatory enables NERC and Regional 
Entities to respond to questionable performance by clarifying to the 
responsible entity, and others, on a going-forward basis what behavior 
would constitute compliance with the Reliability Standards. Thereafter, 
participants would know how NERC and the Regional Entities were 
interpreting the Reliability Standards. According to NERC, this 
information would become part of the public record and help to 
eliminate any ambiguity as to what constitutes compliant and 
noncompliant behavior under a Reliability Standard. In contrast, if the 
Reliability Standards remain voluntary or temporarily unapproved, NERC 
contends that it and the Regional Entities will lack a legal basis to 
compel corrective behavior.
    266. In contrast, Reliant urges the Commission to either not 
approve ambiguous Reliability Standards or approve them without 
subjecting entities to penalties. The level of ambiguity in many cases 
appears to violate the ``just and reasonable'' criteria for approval. 
It states that entities should not be found in violation based on 
retroactive interpretation of a Reliability Standard.
    267. EEI expresses concern that approval and enforcement of a 
Reliability Standard that includes ambiguous requirements or lacks 
certain technical features or specificity may raise due process 
concerns if the required performance or performance measurements are 
not ``clear and unambiguous.'' Both in this docket and on a going 
forward basis, EEI questions whether proposed Reliability Standards 
with various shortcomings or deficiencies are sufficiently clear to 
meet the legal standard of review.
    268. EEI and Wisconsin Electric state that it is not clear what 
``common interpretations'' the Commission refers to in the NOPR or 
whether they are accepted or known across the industry. Wisconsin 
Electric states that common interpretations and best practices must be 
clearly spelled out and made available for review. These 
interpretations should be incorporated into the audit guidelines. 
Further, EEI states that common interpretations should not supersede 
provisions that are clearly stated in a Reliability Standard. According 
to EEI, if part of a proposed Reliability Standard is not clear, the 
NERC Reliability Standards development process should be used to 
clarify it. Further, EEI maintains that the Commission should require 
the ERO to review all existing industry sources, such as the NERC 
glossary or Institute of Electrical and Electronics Engineers (IEEE) 
standards, to supplement the interpretation of Reliability Standards. 
Undocumented ``common interpretations'' should be relied on only as a 
last resort. Moreover, EEI contends that, if such interpretations are 
to be used as a basis for assessing compliance and enforcement, they 
must be clearly spelled out and made available in advance.
    269. MISO notes that some Reliability Standards may have portions 
applicable to five or more entities and that there are situations where 
a particular functional entity is not mentioned in the 
``Applicability'' section of the Reliability Standard, but they show up 
in the Requirements. It believes that the industry needs a database-
style tool that is a companion to the Reliability Standards that 
permits any functional entity to sort and find all requirements and 
supporting compliance information applicable to it. Such a tool would 
help entities prevent oversights and also help NERC eliminate 
redundancy in the Reliability Standards.
    270. MISO also states that, in developing the Version 0 Reliability 
Standards, there was a conscious decision to include supporting 
information in the Reliability Standards themselves. As a result, there 
is now explanatory material in the Reliability Standards that is 
presented in context as Requirements. According to MISO, users now are 
trying to figure out how to measure Requirements that are really 
supporting text. MISO believes that the process should be simplified by 
separating each Reliability Standard into its core requirements and 
supporting information.
    271. Similarly, Constellation, International Transmission and 
Dynegy comment that the Commission should distinguish between those 
Requirements in each Reliability Standard that are core requirements as 
opposed to supporting information, an explanatory statement, or an 
administrative process. International Transmission and Dynegy state 
that Measures should only apply to these core reliability requirements. 
Reliant is also concerned that each Reliability Standard contains a 
great deal of explanatory text, formatted to appear as enforceable 
obligations.
    272. International Transmission, Reliant and MISO note that the 
proposed Reliability Standards contain many inherently ambiguous 
phrases or terms that can be misapplied, including ``adequate'' or 
``adequately,'' ``sufficient,'' ``immediate,'' ``where technically 
feasible,'' ``as soon as possible'' and ``where practical.'' Reliant 
states that all ambiguous language must be eliminated before penalties 
can be assessed. MISO and Wisconsin Electric state that, while use of 
such terms may be acceptable in explanatory information, if a term 
cannot be definitively and objectively defined, it should not appear in 
the core Requirements of a Reliability Standard.
    273. Alcoa reiterates its concern that the Commission has not 
defined the target level of reliability of the Bulk-Power System that 
the Reliability Standards are intended to achieve. Further, Alcoa is 
concerned that the proposed Reliability Standards are fragmented and 
overlap and in some cases may result in inconsistent treatment of the 
same issue. Alcoa states that the ERO should move towards a more 
encompassing approach for developing Reliability Standards in which a 
reliability goal is addressed from all aspects in a more consistent 
manner. Therefore, Alcoa maintains that the Commission should require 
NERC to engage in advance planning, mapping out what kind of 
reliability is adequate for the Bulk-Power System and then developing a 
plan to get there.
b. Commission Determination
    274. The Commission finds that it is essential that the 
Requirements for each Reliability Standard, in particular, are 
sufficiently clear and not subject to

[[Page 16447]]

multiple interpretations. Where the Requirements portion of a 
Reliability Standard is sufficiently clear (and no other issues have 
been identified), we approve the Reliability Standard. Upon review of 
the Reliability Standards and the comments submitted in response to the 
NOPR, the Commission finds that none of the Reliability Standards that 
we approve today contain an ambiguity that renders it unenforceable or 
otherwise unjust and unreasonable. As discussed in our standard-by-
standard review, each Reliability Standard that we approve contains 
Requirements that are sufficiently clear as to be enforceable and do 
not create due process concerns.
    275. The underlying assumption of many of the commenters seems to 
be that the Reliability Standards must spell out in minute detail all 
factual scenarios that might violate a Requirement and the precise 
consequences of that violation. But due process requirements do not go 
so far. Indeed, many government regulatory schemes provide far less 
specificity in terms of what is required or proscribed, and yet those 
regulations are routinely enforced.\128\ Indeed, many tariffs on file 
with the Commission do not specify every compliance detail, but rather 
provide some level of discretion as necessary to carry out a particular 
act. This does not mean the tariffs are unenforceable; rather, it means 
that, if a dispute arises over compliance and there is a legitimate 
ambiguity regarding a particular fact or circumstance, that ambiguity 
can be taken into account in the exercise of the Commission's 
enforcement discretion. Therefore, we find that the Reliability 
Standards must strike a balance between a level of specificity that 
places users, owners and operators on notice of what is required, and a 
level of generality that encompasses unanticipated but serious actions 
or omissions that could affect Bulk-Power System reliability. We are 
satisfied that the Requirements portions of each Reliability Standard 
that we approve in this Final Rule appropriately strike this balance.
---------------------------------------------------------------------------

    \128\ Many sections of the FPA, including section 215, use such 
terms as just and reasonable or unduly discriminatory or 
preferential or even the public interest.
---------------------------------------------------------------------------

    276. Some commenters argue that certain Reliability Standards 
require additional specificity or else users, owners and operators will 
not understand the consequences of a violation. This notion is 
similarly misplaced because the potential (if not actual) consequences 
for any violation are clearly spelled out--the statute permits the ERO 
to assess civil penalties of up to ``$1 million per violation, per 
day'' in addition to other remedies. The Commission has explained how 
it will approach civil penalties in its Enforcement Policy Statement. 
The ERO has provided guidance in its compliance filings, and will 
continue to do so, as to how it will administer compliance and 
enforcement functions. Clarity should not be confused with certainty. 
The former is provided by the statute, the Final Rule and the 
aforementioned authorities. The latter is simply unavailable in this 
context. Indeed, guaranteeing in advance specific enforcement outcomes 
hampers necessary and appropriate enforcement flexibility and poses the 
danger of users, owners and operators of the Bulk-Power System simply 
calculating the cost of a violation into the cost of doing business--a 
dynamic that would frustrate the very purpose of a mandatory 
Reliability Standards system, which is to promote reliability.
    277. The Commission agrees with NERC that, even if some 
clarification of a particular Reliability Standard would be desirable 
at the outset, making it mandatory allows the ERO and the Regional 
Entities to provide that clarification on a going-forward basis while 
still requiring compliance with Reliability Standards that have an 
important reliability goal. Further, we support the ERO's efforts to 
review each of the current Reliability Standards to improve them and 
provide yet further clarity. We encourage all interested entities, 
especially those that have identified specific suggestions for 
improvement, to participate in the ERO's Reliability Standards 
development process.
    278. The Commission finds that these Reliability Standards, with 
the interpretations provided by the Commission in the standard-by-
standard discussion, meet the statutory criteria for approval as 
written and should be approved. In any event, penalties are warranted 
under section 215 only when an entity knew or reasonably should have 
known that its acts or omissions were contrary to the Reliability 
Standards. Wisconsin Electric seems to interpret the Commission as 
requiring that users, owners and operators of the Bulk-Power System 
comply with best practices under the Reliability Standards. We 
disagree. While we appreciate that many entities may perform at a 
higher level than that required by the Reliability Standards, and 
commend them for doing so, the Commission is focused on what is 
required under the Reliability Standards; we do not require that they 
exceed the Reliability Standards. We agree with EEI that a common 
interpretation cannot supplant a provision that is clearly stated in a 
Reliability Standard. We also agree, however, that, over time, these 
interpretations could be incorporated either into the Reliability 
Standard itself through the Reliability Standards development process 
or the ERO and Regional Entity audit guidelines.
    279. The Commission disagrees with MISO that some Reliability 
Standards as proposed are unclear with respect to applicability. In 
certain situations, Bulk-Power System reliability depends on more than 
one entity complying with a Reliability Standard. Further, in certain 
situations, the Requirement of a Reliability Standard may reference an 
entity that is not itself responsible for compliance with the 
Reliability Standard, for example, where an entity responsible for 
compliance must report information to or communicate with another 
entity, without that other entity being required to comply with the 
Reliability Standard. However, in its review of Reliability Standards, 
the ERO should ensure that, if a functional entity must comply with the 
Reliability Standards, it must be mentioned in the Applicability 
section. In this regard, we encourage the ERO to consider development 
of a database-style tool that is a companion to the Reliability 
Standards that permits any user, owner or operator to sort and find all 
Requirements applicable to it.
    280. In response to MISO, Constellation, International Transmission 
and Dynegy, the Commission believes that the Requirements in each 
Reliability Standard are core obligations and that the Measures and 
Levels of Non-Compliance provide useful guidance to the industry and 
can be supporting information, an explanatory statement or an 
administrative process. As discussed above, NERC is to enforce the 
Requirements in a Reliability Standard. The Measures are part of the 
Reliability Standards and, if not met, are almost always going to 
result in a violation of a Requirement.
    281. The Commission has previously addressed Alcoa's concerns about 
defining the target level of reliability of the Bulk-Power System that 
the Reliability Standards are intended to achieve. In the January 2007 
Compliance Order, the Commission directed the ERO to establish a 
stakeholder process to define adequate level of reliability.\129\ While 
the Commission agrees that this is a worthwhile effort, we disagree 
with

[[Page 16448]]

Alcoa that Reliability Standards cannot be approved until this analysis 
is done. Such analysis is not required by the statute, and Alcoa has 
not identified any compelling reason why the proposed Reliability 
Standards are defective without the benefit of such analysis.
---------------------------------------------------------------------------

    \129\ January 2007 Compliance Order at P 16.
---------------------------------------------------------------------------

4. Technical Adequacy
    282. In the NOPR, we stated that we are cautious about drawing any 
general conclusions about technical adequacy as we consider this a 
matter that can only be addressed on a standard-by-standard basis. 
Where we have specific concerns regarding whether a Requirement set 
forth in a proposed Reliability Standard may not be sufficient to 
ensure an adequate level of reliability or represents a ``lowest common 
denominator'' approach, we address those concerns in the context of 
that particular Reliability Standard.\130\
---------------------------------------------------------------------------

    \130\ NOPR at P 115.
---------------------------------------------------------------------------

a. Comments
    283. NYSRC shares the Commission's concerns regarding the use of a 
``lowest common denominator'' approach in the development of 
Reliability Standards and agrees that this concern can be addressed 
only on a standard-by-standard basis. NYSRC maintains that, in 
commenting on pending ERO Reliability Standards, the NYSRC believed 
could weaken existing Reliability Standards, the NERC drafting team 
responded that a region is free to develop more stringent Reliability 
Standards. NYSRC maintains that the ability of a Regional Entity to 
propose more stringent Reliability Standards to meet the reliability 
needs of that region does not justify the weakening of continent-wide 
Reliability Standards by use of a ``lowest common denominator'' 
approach to achieve greater support for a proposed Reliability 
Standard. NYSRC recommends that the Commission reaffirm that it will 
carefully review subsequent proposed ERO Reliability Standards to 
ensure that they are technically adequate and do not weaken the current 
level of reliability.
    284. ATC agrees with the Commission that the industry, organized in 
Regional Entities under the ERO, must continue to be wholly accountable 
for the technical adequacy of the Reliability Standards. ATC thus 
suggests that the Commission's efforts to ``independently assess the 
technical adequacy of any proposed Reliability Standard'' focus on 
Commission participation in and support of the Reliability Standards 
development processes at NERC and at the regions.
b. Commission Determination
    285. The Commission fully intends to address technical adequacy on 
a standard-by-standard basis and the Commission agrees that the ability 
of a Regional Entity to propose more stringent Reliability Standards to 
meet the reliability needs of that region does not justify the 
weakening of continent-wide Reliability Standards. In this regard, we 
note that, in the January 2007 Compliance Order, we directed the ERO to 
closely monitor the voting results for Reliability Standards and to 
report to us quarterly for the next three years its analysis of the 
voting results, including trends and patterns that may signal a need 
for improvement in the voting process, such as the rejection of a 
Reliability Standard and subsequent ballot approval of a less stringent 
version of the Reliability Standard.\131\ The Commission will use this 
information to evaluate whether it needs to re-examine the Reliability 
Standard development procedure. In doing so, the Commission will also 
be sensitive to concerns that ``lowest common denominator'' Reliability 
Standards are being developed.
---------------------------------------------------------------------------

    \131\ January 2007 Compliance Order at P 18.
---------------------------------------------------------------------------

    286. The Commission agrees that its staff should participate in and 
support the Reliability Standards development processes, to the extent 
consistent with its regulatory role. The Commission's participation in 
those processes will not constitute its entire assessment of the 
technical adequacy of a proposed Reliability Standard. The Commission 
will also conduct an assessment during its rulemaking or order process 
after the Reliability Standard is submitted by the ERO to the 
Commission for approval.
5. Fill-in-the-Blank Standards
    287. The NOPR explained that certain Reliability Standards, 
referred to as fill-in-the-blank standards, require the regional 
reliability organizations to develop criteria for use by users, owners 
or operators within each region.\132\ In the NOPR, the Commission 
expressed concern regarding the potential for the fill-in-the-blank 
standards to undermine uniformity. With regard to NERC's stated 
intention to submit an action plan and schedule for completing the 
fill-in-the-blank standards, the NOPR explained that NERC's plan must 
be consistent with the discussion in Order No. 672 regarding uniformity 
and the limited circumstances in which a regional difference would be 
permitted.\133\
---------------------------------------------------------------------------

    \132\ NOPR at P 116.
    \133\ Id. at P 121, citing Order No. 672 at P 292; ERO 
Certification Order at P 274.
---------------------------------------------------------------------------

    288. Further, the NOPR proposed to require supplemental information 
regarding any Reliability Standard that requires a regional reliability 
organization to fill in missing criteria or procedures. The Commission 
explained that, ``where important information has not been provided to 
us to enable us to complete our review, we are not in a position to 
approve those Reliability Standards.'' \134\ Therefore, the NOPR 
proposed to not approve or remand such Reliability Standards until all 
necessary information is provided, although compliance would still be 
expected as a matter of good utility practice.
---------------------------------------------------------------------------

    \134\ NOPR at P 123.
---------------------------------------------------------------------------

a. Comments
    289. NERC, APPA and TAPS support the Commission's proposal to defer 
consideration of fill-in-the-blank standards. APPA believes that the 
Commission's proposal balances the need for greater uniformity against 
the need for regional flexibility.
    290. NERC agrees with the Commission's proposal to hold 24 
Reliability Standards (mainly fill-in-the-blank standards) as pending 
at the Commission until further information is provided, and to require 
that Bulk-Power System users, owners and operators follow these pending 
standards as ``good utility practice'' pending their approval by the 
Commission. NERC also agrees that it and the Regional Entities can 
monitor compliance with these pending standards using the ERO's 
authority pursuant to Sec.  39.2(d) of the Commission's regulations. 
NERC believes this approach is necessary to ensure that there will be 
no gap during the transition from the current voluntary reliability 
regime to mandatory and enforceable Reliability Standards.
    291. While TAPS supports deferring consideration of fill-in-the-
blank standards, it urges the Commission to view with skepticism 
regional differences within an Interconnection that are not justified 
by physical differences. It states that such regional Reliability 
Standards, even if more stringent, can wreak havoc on competitive 
markets, especially where entities within the same transmission system 
or RTO footprint are subject to different regional Reliability 
Standards. For example, TAPS maintains that inconsistent regional 
underfrequency load shedding (UFLS) Reliability Standards not justified 
by physical differences impose unjust burdens on joint action agencies 
whose integrated load is split between NERC regions. Further, according 
to TAPS, a region's

[[Page 16449]]

choice may reflect the historical lack of a balanced process for 
developing Reliability Standards at the regional level, allowing 
certain classes of market participants to determine the region's 
choice.
    292. According to ISO-NE, if the Commission withholds approval of 
these 24 Reliability Standards, the Commission should also withhold 
approval of Reliability Standards that rely, by reference, on such 
fill-in-the-blank Reliability Standards.\135\ ISO-NE submits that, 
until the missing information has been provided in the cross-referenced 
fill-in-the-blank Reliability Standard, it will be impossible for the 
applicable entities to determine exactly what criteria they are 
expected to satisfy. APPA raises similar concerns, and suggests that 
the Commission approve such Reliability Standards but not enforce them 
until the cross-referenced fill-in-the-blank Reliability Standards are 
approved.
---------------------------------------------------------------------------

    \135\ ISO-NE and ISO/RTO Council state that the following 
Reliability Standards are dependent upon ``fill-in-the-blank'' 
standards: FAC-013-1, MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, 
MOD-018-0, MOD-019-0, MOD-021-0, PRC-004-1, PRC-007-0, PRC-008-0, 
PRC-009-0, PRC-015-0, PRC-016-0, PRC-018-1 and PRC-021-0.
---------------------------------------------------------------------------

    293. MISO and Wisconsin Electric believe that the fill-in-the-blank 
standards may be acceptable in certain situations. They give regions 
some flexibility in implementation, and allow the deployment of a 
Reliability Standard where it would be difficult to get consensus 
across several regions. They also move the reliability agenda forward 
on issues that are historically under state jurisdiction, and some are 
an accommodation to those regions that want to have a higher 
Reliability Standard.
    294. EEI agrees with the NOPR that, regarding Reliability Standards 
for which the Commission needs additional information, compliance in 
the interim would be expected as a matter of good utility practice. 
While EEI agrees with this approach, it also cautions that the good 
utility practice provision of an OATT should not be used as an 
alternative means of enforcement outside of section 215 of the FPA. 
Similarly, FirstEnergy posits that good utility practice is subject to 
interpretation and by itself does not provide the level of guidance 
needed for a mandatory and enforceable Reliability Standard. It asserts 
that the Commission should not impose compliance burdens indirectly 
where it has not imposed them directly. Xcel asserts that the 
Commission should rescind the Reliability Policy Statement that defines 
good utility practice under the pro forma OATT, effective when the 
Reliability Standards become mandatory in June 2007, because a 
reliability-related violation should not be subject to two separate 
enforcement schemes.
    295. NPCC recommends that any of the 24 fill-in-the-blank standards 
that are required to be Reliability Standards should be developed as 
regional Reliability Standards by the Regional Entity for compliance 
monitoring and enforcement, backed by the Commission and Canadian 
provincial regulatory and/or governmental authorities.
    296. California PUC states that the NOPR seeks national uniformity 
notwithstanding regional differences. It states that, in the Western 
Interconnection, there are 15 existing, enforceable WECC standards 
pursuant to the WECC Reliability Management System (RMS) that overlap 
the proposed mandatory Reliability Standards. Five of these WECC 
standards fall into the fill-in-the-blank standards category. However, 
there are three additional WECC RMS standards already in effect in the 
Western Interconnection that do not have a corresponding proposed 
Reliability Standard. California PUC asks that the Commission consider 
approving these additional three standards for enforcement in the 
Western Interconnection. California PUC states that there is no reason 
for the Commission to exclude any WECC standard already in effect, and 
that ignoring these established standards when the Reliability 
Standards are scheduled to go into effect can threaten reliability 
already being achieved in the Western Interconnection.
b. Commission Determination
    297. The Commission requires supplemental information for any 
Reliability Standard that currently requires a regional reliability 
organization to fill in missing criteria or procedures. Where important 
information has not yet been provided to us to enable us to complete 
our review, we are not in a position to approve or remand those 
Reliability Standards.\136\ Accordingly, we will not approve or remand 
such Reliability Standards until the ERO submits further information. 
Until such information is provided, compliance with fill-in-the-blank 
standards should continue on a voluntary basis, and the Commission 
considers compliance with such Reliability Standards to be a matter of 
good utility practice.
---------------------------------------------------------------------------

    \136\ NOPR at P 123.
---------------------------------------------------------------------------

    298. As noted above, some commenters such as TAPS urge the 
Commission to view most regional differences with skepticism, while 
others such as MISO and Wisconsin Electric favor some regional 
variation. The Commission affirms the approach that it articulated in 
the NOPR.\137\ We share commenters' concerns regarding the potential 
for fill-in-the-blank standards to undermine uniformity. While 
uniformity is the goal with respect to Reliability Standards, we 
recognize that it may not be achievable overnight. Over time, we would 
expect that the regional differences will decline and uniform and best 
practices will develop. In Order No. 672, the Commission identified two 
instances where regional differences may be permitted, i.e., regional 
differences that are more stringent than continent-wide Reliability 
Standards (including those that address matters not addressed by a 
continent-wide Reliability Standard) and a regional difference 
necessitated by a physical difference in the Bulk-Power System.
---------------------------------------------------------------------------

    \137\ Id. at P 121 (footnote omitted).
---------------------------------------------------------------------------

    299. The ERO should develop the needed information for the 
Commission to act on the fill-in-the-blank standards consistent with 
these criteria. If a regional difference is warranted, a regional fill-
in-the-blank proposal must be developed through an approved regional 
Reliability Standards development process, and submitted to the ERO. If 
approved by the ERO, the ERO will then submit it to the Commission for 
approval.
    300. The Commission disagrees with ISO-NE, ISO/RTO Council and APPA 
that 16 additional Reliability Standards should not be acted on or 
enforced at this time. The fact that a Reliability Standard simply 
references another, pending Reliability Standard, one that is not being 
approved or remanded here, does not alone justify not approving the 
former Reliability Standard. Rather, such a reference may be considered 
in an enforcement action, if relevant, but is not a reason to delay 
approval of enforcement of the Reliability Standard. We find that the 
Reliability Standards that reference a pending Reliability Standard 
contain the appropriate level of specificity necessary to provide 
notice to users, owners and operators of the Bulk-Power System as to 
what is required.
    301. The Commission has reviewed the 16 Reliability Standards 
identified by commenters as referencing a Reliability Standard that the 
Commission proposed not to approve or remand. It appears that many of 
these Reliability Standards either refer to the process of collecting 
data or reference Requirements that entities are generally

[[Page 16450]]

aware of because they have already been following these Reliability 
Standards on a voluntary basis. For example, MOD-012-0 requires 
transmission and generator owners to provide data to the regional 
reliability organization to support system modeling required by MOD-
013-0. The NOPR proposed not to approve or remand MOD-013-0 partly 
because MOD-013-0 requires development of dynamics data requirements 
and reporting procedures that have not been submitted for our review. 
In addition, we proposed not to act on MOD-013-0 partly because it 
applies to a regional reliability organization and the Commission was 
not persuaded that a regional reliability organization's compliance 
with a Reliability Standard can be enforced by NERC. That is not the 
case with MOD-012-0, which applies to entities that are clearly users, 
owners and operators of the Bulk-Power System. Although MOD-012-0 
references MOD-013-0, its applicability to a subset of users, owners 
and operators is not at issue. Accordingly, the Commission denies the 
requests to leave pending this and similar data-related Reliability 
Standards and reaffirms the NOPR approach described above.
    302. While EEI and others agree with the proposal that, in the 
interim, compliance with Reliability Standards for which the Commission 
needs additional information should continue as a matter of good 
utility practice, they caution that this should not lead to an 
alternative means of enforcement outside of section 215 of the FPA. In 
our Reliability Policy Statement, we explained that compliance with 
NERC Reliability Standards (or more stringent regional standards) is 
expected as a matter of good utility practice as that term is used in 
the pro forma OATT.\138\ The Commission continues to expect compliance 
with such Reliability Standards as a matter of good utility practice. 
That being said, the Commission agrees that retaining a dual mechanism 
to enforce Reliability Standards both as good utility practice and 
under section 215 of the FPA is inappropriate; the OATT only applies to 
entities subject to our jurisdiction as public utilities under the FPA, 
while section 215 defines more broadly our jurisdiction with respect to 
mandatory Reliability Standards. We therefore do not intend to enforce, 
as an OATT violation, compliance with any Reliability Standard that has 
not been approved by the Commission under section 215.
---------------------------------------------------------------------------

    \138\ Policy Statement on Matters Related to Bulk Power System 
Reliability, 107 FERC ] 61,052 at P 23-26 (2004) (Reliability Policy 
Statement).
---------------------------------------------------------------------------

    303. With regard to California PUC's comments, we recognize the 
desire to retain certain existing regional standards that apply to the 
Western Interconnection, which are currently enforceable pursuant to 
WECC's RMS program. However, these regional Reliability Standards have 
not been submitted to the Commission by the ERO pursuant to the process 
set forth in Order No. 672. Accordingly, California PUC's concerns are 
beyond the scope of this proceeding. The Commission will review the 
WECC standards once they are approved by the ERO and submitted to the 
Commission for approval.

F. Discussion of Each Individual Reliability Standard

    304. The NOPR reviewed each proposed Reliability Standard and 
provided an analysis by chapter according to the categories of 
Reliability Standards defined in NERC's petition. Each chapter began 
with an introduction to the category, followed by a discussion of each 
proposed Reliability Standard. The Final Rule takes a similar approach.
1. BAL: Resource and Demand Balancing
    305. The six Balancing (BAL) Reliability Standards address 
balancing resources and demand to maintain interconnection frequency 
within prescribed limits.
a. Real Power Balancing Control Performance (BAL-001-0)
    306. The purpose of this Reliability Standard is to maintain 
Interconnection steady-state frequency within defined limits by 
balancing real power demand and supply in real-time. The proposed 
Reliability Standard would apply to balancing authorities. In the NOPR, 
the Commission proposed to approve BAL-001-0 as mandatory and 
enforceable.\139\
---------------------------------------------------------------------------

    \139\ NOPR at P 136.
---------------------------------------------------------------------------

i. Comments
    307. APPA agrees with the Commission that BAL-001-0 is sufficient 
for approval as a mandatory Reliability Standard.
ii. Commission Determination
    308. For the reasons stated in the NOPR, the Commission approves 
BAL-001-0 as mandatory and enforceable.
b. Regional Difference to BAL-001-0: ERCOT Control Performance Standard 
2
    309. NERC approved a regional difference for ERCOT by allowing it 
to be exempt from Requirement R2 in BAL-001-0, which requires that the 
average area control error (ACE) for each of the six ten-minute periods 
during the hour must be within specific limits, and that a balancing 
authority achieve 90 percent compliance. This Requirement is referred 
to as Control Performance Standard 2 (CPS2).
    310. NERC explains that ERCOT requested a waiver of CPS2 because: 
(1) ERCOT, as a single control area \140\ asynchronously connected to 
the Eastern Interconnection, cannot create inadvertent flows or time 
errors in other control areas and (2) CPS2 may not be feasible under 
ERCOT's competitive balancing energy market. In support of this 
argument, ERCOT cites to a study that it performed showing that under 
the new market structure, the ten control areas in its region 
individually were able to meet CPS2 standards while the aggregate 
performance of the ten control areas was not in compliance. Since 
requesting the waiver from CPS2, ERCOT has adopted section 5 of the 
ERCOT protocols which identify the necessary frequency controls needed 
for reliable operation in ERCOT.
---------------------------------------------------------------------------

    \140\ At the time NERC granted this regional difference, the 
term ``control area'' was used instead of ``balancing authority.'' 
For purposes of this discussion, they are the same.
---------------------------------------------------------------------------

    311. In the NOPR, the Commission proposed to approve the ERCOT 
regional difference and have the ERO submit a modification of the ERCOT 
regional difference to include the requirements concerning frequency 
response contained in section five of the ERCOT protocols.\141\
---------------------------------------------------------------------------

    \141\ Id. at P 143.
---------------------------------------------------------------------------

i. Comments
    312. No comments were filed on this regional difference.
ii. Commission Determination
    313. The Commission approves the ERCOT regional difference as 
mandatory and enforceable. Order No. 672 explains that ``uniformity of 
Reliability Standards should be the goal and the practice, the rule 
rather than the exception.'' \142\ However, the Commission has stated 
that, as a general matter, regional differences are permissible if they 
are either more stringent than the continent-wide Reliability Standard, 
or if they are necessitated by a physical difference in the Bulk-Power 
System.\143\ Regional differences must still be just, reasonable, not 
unduly discriminatory or

[[Page 16451]]

preferential and in the public interest.\144\
---------------------------------------------------------------------------

    \142\ Order No. 672 at P 290.
    \143\ Id. at P 291.
    \144\ Id.
---------------------------------------------------------------------------

    314. The Commission finds that ERCOT's approach under section 5 of 
the ERCOT protocols appears to be a more stringent practice than 
Requirement R2 in BAL-001-0 and therefore approves the regional 
difference.
    315. As proposed in the NOPR, the Commission directs the ERO to 
file a modification of the ERCOT regional difference to include the 
requirements concerning frequency response contained in section 5 of 
the ERCOT protocols. As with other new regional differences, the 
Commission expects that the ERCOT regional difference will include 
Requirements, Measures and Levels of Non-Compliance sections.
c. Disturbance Control Performance (BAL-002-0)
    316. The stated purpose of this Reliability Standard is to use 
contingency reserves to balance resources and demand to return 
Interconnection frequency to within defined limits following a 
reportable disturbance. The proposed Reliability Standard would apply 
to balancing authorities, reserve sharing groups \145\ and regional 
reliability organizations.
---------------------------------------------------------------------------

    \145\ A ``reserve sharing group'' is a group of two or more 
balancing authorities that collectively maintain, allocate and 
supply operating reserves. See NERC Glossary at 15.
---------------------------------------------------------------------------

    317. In the NOPR, the Commission proposed to approve Reliability 
Standard BAL-002-0 as mandatory and enforceable.\146\ In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct NERC to submit a 
modification to BAL-002-0 that: (1) Includes a Requirement that 
explicitly allows demand-side management (DSM) to be used as a resource 
for contingency reserves; (2) develops a continent-wide contingency 
reserve policy; \147\ (3) includes a Requirement that measures response 
for any event or contingency that causes a frequency deviation; \148\ 
(4) substitutes the ERO for the regional reliability organization as 
the compliance monitor and (5) refers to the ERO rather than the NERC 
Operating Committee in Requirements R4.2 and R6.2.
---------------------------------------------------------------------------

    \146\ NOPR at P 151.
    \147\ The NOPR explained that this could be accomplished by 
modifying Requirement R2 or developing a new Reliability Standard.
    \148\ This proposed Requirement addressed modifications to 
Requirement R3.1 which are described in the ``Disturbance Control 
Standard and the Associated Reserve Requirement'' section of this 
Final Rule.
---------------------------------------------------------------------------

i. General Comments
    318. Constellation supports the Commission's proposals with respect 
to BAL-002-0.
    319. Xcel notes that this Reliability Standard would apply to a 
reserve sharing group, which is not defined in the NERC Functional 
Model but generally consists of a group of separate entities. Xcel 
states it is not clear how compliance and penalties would be applied to 
a reserve sharing group and seeks clarification from the Commission. As 
a second concern, Xcel states it is not clear who calculates ACE 
between a balancing authority and a reserve sharing group and states 
that the Commission should require the ERO to clarify this issue when 
modifying the Reliability Standard.
ii. Commission Determination
    320. The Commission approves BAL-002-0. With regard to Xcel's 
concern, the NERC glossary defines a reserve sharing group as ``two or 
more balancing authorities that collectively maintain, allocate, and 
supply operating reserves required for each balancing authority's use 
in recovering from contingencies within the group.'' \149\ The 
Commission notes that the Reliability Standard's Requirements and 
Levels of Non-Compliance are applicable to both balancing authorities 
and reserve sharing groups and are clear as to the roles and 
responsibilities of these entities. The ERO will be responsible for 
ensuring compliance with this Reliability Standard for all applicable 
entities. A reserve sharing group, however, as an independent 
organization, is able to determine on its own as a commercial matter 
whether any penalties related to non-compliance should be re-
apportioned among the members of the group. With regard to Xcel's 
concern about which entity calculates ACE, it is not clear from Xcel's 
comments what it believes needs clarification. In general, we 
understand that all balancing authorities are required to calculate ACE 
with the exception of balancing authorities that use dynamic schedules 
to provide all regulating reserves from another balancing authority. As 
such, reserve sharing groups will not calculate ACE; they will rely on 
balancing authorities to do so.
---------------------------------------------------------------------------

    \149\ NERC Glossary at 15.
---------------------------------------------------------------------------

    321. The Commission adopts the NOPR's proposal to require the ERO 
to develop a modification to the Reliability Standard that refers to 
the ERO rather than to the NERC Operating Committee in Requirements 
R4.2 and R6.2. The ERO has the responsibility to assure the reliability 
of the Bulk-Power System and should be the entity that modifies the 
Disturbance Recovery Period as necessary. As identified in the 
Applicability Issues section, the Commission directs the ERO to modify 
this Reliability Standard to substitute Regional Entity for regional 
reliability organization as the compliance monitor.\150\ The remaining 
modifications to this Reliability Standard proposed in the NOPR are 
discussed below.
---------------------------------------------------------------------------

    \150\ See Applicability Issues: Regional Reliability 
Organizations, supra section II.C.5. This directive applies 
generically to all Reliability Standards that identify the regional 
reliability organization as the compliance monitor.
---------------------------------------------------------------------------

iii. Including Demand-Side Management as a Resource
(a) Comments
    322. SMA supports the Commission's proposed requirement explicitly 
allowing demand-side response as a resource and agrees with the 
Commission that DSM and direct load control should be considered on the 
same basis as conventional generation or any other technology with 
respect to contingency reserves. SMA states that nationwide its members 
provide over 1,300 MW of demand that is curtailable on 10 minutes 
notice or less and indicates that most of this curtailable capacity is 
committed to utilities pursuant to retail tariffs or contracts for 
operating reserves.
    323. FirstEnergy states that demand-side resources should be 
included as another tool for the balancing authority to use in meeting 
the control performance and disturbance control standards. According to 
FirstEnergy, demand-side resources should mimic the requirements of 
generation resources but with a decrease in load rather than an 
increase in generation response.
    324. Process Electricity Committee generally supports the proposal 
to treat demand response resources in a manner similar to conventional 
generation so long as such demand resources participate in such DSM 
programs voluntarily and comply with all applicable Reliability 
Standards and requirements. Process Electricity Committee recommends 
that the Commission modify its proposal to clarify that any such demand 
response resources may be used only with the end-user's express written 
agreement pursuant to clear contractual rights and obligations.
    325. NY Major Consumers states that many large end use customers 
currently have the ability to provide all ancillary

[[Page 16452]]

services, or are capable of providing these services in the near future 
and that this capability has been recognized by Commission staff in 
Docket No. AD06-2-000, Assessment of Demand Response Resources. NY 
Major Consumers further states that there remains some ambiguity in the 
proposed Reliability Standards as to the eligibility of technically-
qualified loads to provide these services and requests that the 
Commission eliminate any such uncertainty and amend the proposed 
Reliability Standards as further described in its comments.
    326. Some commenters \151\ disagree with the Commission's proposal 
to add a requirement explicitly allowing DSM as a resource for 
contingency reserves. NERC, APPA and ISO-NE state that this requirement 
is too prescriptive. NERC maintains that explicitly allowing DSM goes 
well beyond the bounds of current utility practice and suggests an 
improved directive would simply place DSM on the same basis as other 
resources. APPA states that DSM resources should be included as an 
option for a balancing authority to use in meeting its reserve 
obligations, but that the Commission should not require NERC to modify 
the Reliability Standard to explicitly identify DSM or any other type 
of capacity as a resource for meeting reserve contingencies.
---------------------------------------------------------------------------

    \151\ See NERC, ISO-NE, APPA and SDG&E.
---------------------------------------------------------------------------

    327. In addition, ISO-NE states that DSM, to which it has access, 
responds to capacity requirements and may not provide relief on a 
contingency basis, but states that it has a limited number of resources 
that could meet this requirement. SDG&E argues that DSM participation 
in real-time is often unknown in comparison to conventional generation 
and further states that the NOPR does not explain how DSM could be used 
in real-time dispatch. Further, SDG&E maintains that the Commission has 
not established a clear and workable definition of DSM.
    328. MISO states that it is not clear about the meaning and 
questions the value of the Commission's proposed requirement to include 
DSM as a contingency reserve resource.\152\
---------------------------------------------------------------------------

    \152\ MISO-PJM comments jointly with respect to IRO-006-3 only.
---------------------------------------------------------------------------

    329. While EEI and MRO do not disagree with the Commission's 
proposed requirement to include DSM, EEI states that both generation 
and controllable load should comply with the same requirements to the 
maximum extent possible, while MRO suggests that this requirement 
should also include study and testing requirements.
(b) Commission Determination
    330. We direct the ERO to submit a modification to BAL-002-0 that 
includes a Requirement that explicitly provides that DSM may be used as 
a resource for contingency reserves, subject to the clarifications 
provided below.
    331. 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.
    332. Many commenters argue that the Commission's proposed directive 
that would explicitly allow DSM as a resource for contingency reserves 
is too prescriptive. Concerns in this area generally fall into three 
categories: (1) that DSM should be treated on a comparable basis as 
other resources; (2) that the Reliability Standard should be based on 
meeting an objective as opposed to stating how that objective is met 
and (3) that DSM may not be technically capable of providing this 
service.
    333. 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.\153\ 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.\154\
---------------------------------------------------------------------------

    \153\ NOPR at P 157.
    \154\ Order No. 672 at P 260.
---------------------------------------------------------------------------

    334. With regard to commenters' concern that DSM may not be 
technically possible, we first clarify that in order for DSM to 
participate, it must be technically capable of providing contingency 
reserve service. We expect that the ERO would determine what technical 
requirements DSM would need to meet to provide contingency 
reserves.\155\ While ISO-NE, APPA and SDG&E suggest that there is 
limited access to qualified DSM or that DSM may not be optimal from a 
technical standpoint, we note that SMA's comments state that its 
members are currently providing over 1,300 MW of contingency reserve 
service through retail tariffs or contracts. Alcoa states that it could 
use the digital controls of its aluminum smelters to provide load 
control that would be superior to conventional generation in terms of 
ramp rate and speed of response. Also, the Commission notes that New 
Zealand is currently using DSM for contingency reserves.\156\ 
Nonetheless, our requirement is that BAL-002-0 explicitly provides that 
demand resources may be used as a resource for contingency reserves 
without requiring the use of a specific resource or type of resource.
---------------------------------------------------------------------------

    \155\ Id. (``We leave it to the ERO to develop proposed 
Reliability Standards that appropriately balance reliability 
principles and implementation features.'')
    \156\ See http://www.electricitycommission.govt.nz/pdfs/rulesandregs/rules/rulespdf/Part-C-sched-C5-1Dec06.pdf.
---------------------------------------------------------------------------

    335. Accordingly, the Commission directs the ERO to explicitly 
allow DSM as a resource for contingency reserves, and clarifies that 
DSM should be treated on a comparable basis and must meet similar 
technical requirements as other resources providing this service.\157\
---------------------------------------------------------------------------

    \157\ ERCOT presently uses ``Load Acting as a Resource'' as part 
of its reserves which are triggered at a specified frequency. This 
is similar to but not the same as generation and is an example of 
how load can perform as a resource.
---------------------------------------------------------------------------

iv. Continent-Wide Contingency Reserve Policy
(a) Comments
    336. The Commission proposed in the NOPR to direct the ERO to 
develop one uniform continent-wide contingency reserves policy. 
Specifically, the Commission noted that the appropriate mix of 
operating reserves, spinning reserves and non-spinning reserves should 
be addressed on a consistent basis and consideration should be given to 
the amount of frequency response from generation or load needed to 
assure reliability. The Commission proposed that this policy be neutral 
as to the source of the contingency reserves in terms of ownership or 
technology.
    337. SMA supports the Commission's proposal to develop a continent-
wide contingency reserve policy and agrees with the Commission that the 
policy should be neutral as to the source of the

[[Page 16453]]

contingency reserves in terms of ownership or technology. EEI and 
FirstEnergy both support development of a continent-wide contingency 
reserve policy but suggest the need for regional variations across the 
Bulk-Power System. For instance, FirstEnergy suggests that a one 
percent peak load spinning requirement in the Eastern Interconnection 
could be the equivalent of a two percent spinning requirement in the 
Western Interconnection.
    338. Other commenters \158\ disagree with the Commission's proposal 
to have NERC develop a continent-wide contingency reserve policy and 
instead support an Interconnection-wide or regional approach. APPA, 
LPPC and MISO state that a continent-wide policy would not work because 
of regional differences such as size, topology, mix of resources and 
likely contingencies. While APPA supports the Commission's proposal 
that contingency reserves should be based on the reliability risk of a 
balancing authority not meeting load, it favors an Interconnection-wide 
approach. MISO suggests that defining certain terms such as 
``spinning,'' ``non-spinning,'' ``contingency'' and ``replacement'' and 
having common calculations would be of value. It contends, however, 
that EPAct does not apply to resource adequacy requirements, implying 
that the Commission therefore is prevented from directing the 
development of a continent-wide contingency reserve policy. 
International Transmission shares this view.
---------------------------------------------------------------------------

    \158\ See APPA, International Transmission, MISO-PJM, LPPC and 
California PUC.
---------------------------------------------------------------------------

    339. California PUC states that some customers can tolerate a 
limited number of outages and suggests that it may be more cost-
effective to provide back-up power to customers with high reliability 
needs rather than designing the entire system to a very high and 
expensive level. California PUC disagrees with the Commission that 
contingency reserves should be based only on the reliability risk of a 
balancing authority not meeting load. It suggests that certain other 
relevant factors should be considered, such as the number of customers 
or MW lost, the value that customers in a certain area place on 
reliability and the costs of avoiding outages (the cost of reserves).
(b) Commission Determination
    340. We direct the ERO to submit a modification to BAL-002-0 to 
include a continent-wide contingency reserve policy. We are not 
prescribing the details of that policy. As the Commission stated in the 
NOPR, ``[w]hile the Commission believes it is appropriate for balancing 
authorities to have different amounts of contingency reserves, these 
amounts should be based on one uniform continent-wide contingency 
reserves policy. The policy should be based on the reliability risk of 
not meeting load associated with a particular balancing authority's 
generation mix and topology.'' \159\ In addition, the contingency 
reserves should include sufficient frequency responsive resources such 
that the net frequency response of the balancing authority is 
sufficient for either interconnected or isolated operation.\160\
---------------------------------------------------------------------------

    \159\ NOPR at P 156.
---------------------------------------------------------------------------

    341. The Commission agrees with MISO that certain terms such as 
``spinning'' and ``non-spinning'' or any other term used to describe 
contingency or operating reserves could be developed continent-wide. 
Additionally, we believe the technical requirements for resources that 
provide contingency reserves should not change from region to region.
---------------------------------------------------------------------------

    \160\ Although Frequency Response and Bias are discussed at 
length in Reliability Standard BAL-003-0, the Commission notes here 
that it is important that contingency reserves have adequate 
frequency response to assure recovery immediately following an 
incident.
---------------------------------------------------------------------------

    342. We believe a continent-wide contingency reserves policy would 
assure that there are adequate magnitude and frequency responsive 
contingency reserves in each balancing authority. This will improve 
performance so that no balancing authority will be doing less than its 
fair share.
    343. With regard to California PUC's concerns regarding the cost of 
providing reserves, and the suggestion that loss of firm load may be an 
acceptable alternative to enhanced reliability of the system, the 
Commission disagrees. Loss of firm load should not be permitted in 
planning the system for a single contingency. However, the Commission 
recognizes the appropriate concern of California PUC regarding costs. 
The California PUC can have a strong role in this area by encouraging 
or requiring DSM programs that can reduce the demand on the 
transmission system.
    344. With regard to statements that EPAct does not apply to 
resource adequacy, we note that this Reliability Standard does not 
concern resource adequacy, but addresses contingency reserves, which 
are operating and not planning reserves. Operating reserves are not the 
same as resource adequacy, a planning element. Section 215 authorizes 
the Commission to approve Reliability Standards for contingency 
reserves because they are necessary for real-time Reliable Operation of 
the Bulk-Power System.
    345. Accordingly, the Commission requires the ERO to develop a 
continent-wide contingency reserve policy through the Reliability 
Standards development process, which should include uniform elements 
such as certain definitions and requirements as discussed in this 
section. The Commission clarifies that the continent-wide policy can 
allow for regional differences pursuant to Order No. 672, but that the 
policy should include procedures to determine the appropriate mix of 
operating reserves, spinning and non-spinning, as well as requirements 
pertaining to the specific amounts of operating reserves based on the 
load characteristics and magnitude, topology, and mix of resources 
available in the region.
v. Disturbance Control Standard and the Associated Reserve Requirement
(a) Comments
    346. The Commission identified two items in the Disturbance Control 
Standard section of the NOPR. In the first item, the Commission agreed 
with the interpretation that the 15 minute limit on a reportable 
disturbance was ``absolute, objective, and measurable'' and therefore 
enforceable in the present Reliability Standard. The second item 
resulted in a proposal to modify Requirement R3.1, which currently 
requires that a balancing authority to carry at least enough 
contingency reserves to cover ``the most severe single contingency.'' 
The Commission proposed to change the Requirement to include enough 
contingency reserves to cover any event or single contingency, 
including a transmission outage, which results in a significant 
deviation in frequency from the loss or mismatch of supply either from 
local generation or imports. The Commission noted that this approach 
would address staff's concern with Requirement R3.1--specifically, 
addressing the ambiguity over whether the Requirement meant the loss of 
generation or the loss of supply resulting from a transmission or 
generation contingency.\161\
---------------------------------------------------------------------------

    \161\ NOPR at P 153.
---------------------------------------------------------------------------

    347. Most commenters \162\ express concern over the Commission's 
proposal to add a Requirement that measures response for any event or 
contingency that causes a frequency deviation. NERC states that this 
proposed directive is overly prescriptive and suggests that an improved 
modification would be to direct the ERO to resolve the ambiguity

[[Page 16454]]

in Requirement R3.1 as pointed out in the Staff Preliminary Assessment. 
APPA suggests that the Commission should not require NERC to modify the 
Reliability Standard, but should allow NERC to address the Commission's 
concerns in its Reliability Standards development process and, while 
doing so, NERC should consider defining ``Most Severe Single 
Contingency'' contained in the WECC Frequency Response Standard White 
Paper.\163\ Xcel has concerns about the compliance aspects of this 
proposed modification stating that there is no equitable method to 
assess an individual entity's performance for an occurrence that is 
potentially Interconnection-wide.
---------------------------------------------------------------------------

    \162\ See NERC, APPA, Xcel, MRO, ISO-NE, EEI and Nevada 
Companies.
    \163\ See NOPR at n.116.
---------------------------------------------------------------------------

    348. NRC notes the NERC and Commission observations regarding the 
declining trend in frequency response and states that this Reliability 
Standard provides the opportunity to establish a frequency response 
performance standard. NRC staff suggests that a Measure be added to 
establish a frequency response.
    349. MRO suggests that, if this requirement is adopted, a clear 
definition of the event that causes a frequency deviation will be 
required. ISO-NE comments that Requirement R3.1 is already clear and 
the suggested modification is not clear because: (1) It is not possible 
to plan for all such events and (2) it is not clear what is a 
``significant deviation.'' EEI states that a requirement to measure 
frequency response for any event or contingency could provide 
beneficial information for system operators but states that there is 
presently no requirement for generators to report all outages so 
measurements cannot be made. EEI further states that the compliance 
costs of this requirement may outweigh the benefits. The Nevada 
Companies disagree with the proposed modification and state that the 
Reliability Standard must instead focus strictly on the loss of supply. 
The Nevada Companies further state that, for purposes of this 
Reliability Standard, WECC's present contingency reserve criterion, 
which requires consideration of loss of generation that would result 
from the most severe single contingency, is most applicable.
    350. Georgia Operators comment that the Commission's intent in this 
proposed modification should not be interpreted to require a balancing 
authority to carry enough reserves to cover any event resulting in a 
significant deviation in frequency and should not be read to suggest 
that frequency rather than ACE should be used to measure a balancing 
authority's deployment of reserves for contingencies.
    351. MISO and ERCOT comment on the Commission's suggestion that 
NERC should consider defining a frequency deviation of 20 milli Hertz 
lasting longer than the 15 minute recovery period as a significant 
deviation. MISO argues that the value could vary in different 
Interconnections and believes the current method is acceptable. ERCOT 
states that it is not feasible to apply a single frequency-deviation 
number to ERCOT and the other Interconnections and asks the Commission 
to instead consider a Reliability Standard that is proportional to the 
size of each Interconnection. ERCOT notes that 20 milli Hertz would be 
far more strict than ERCOT's historic frequency performance.
(b) Commission Determination
    352. On this issue, the Commission will not direct the ERO to 
modify BAL-002-0 in the manner proposed in the NOPR. Rather, the 
Commission directs the ERO to address the concerns expressed by the 
Commission about having enough contingency reserves to respond to an 
event on the system in Requirement R3.1 and how such reserves are 
measured. The ERO should address this through adoption or modification 
of Requirements and metrics in the Reliability Standards development 
process.
    353. NERC correctly points out that the Commission's proposal on 
this point stemmed from the ambiguity in Requirement R3.1 that 
Commission staff highlighted in the Staff Preliminary Assessment. 
Requirement R3.1 currently requires that a balancing authority carry at 
least enough contingency reserves to cover ``the most severe single 
contingency.'' The Commission emphasizes that the goal of this 
Reliability Standard is to insure against the reliability risk of not 
serving load by matching generation and load following any disturbance 
or event that results in a significant deviation in frequency. 
Consistent with this goal, the Commission believes that this 
Reliability Standard should be inclusive of all events, i.e., loss of 
supply, loss of load or significant scheduling problems, which can 
cause frequency disturbances and should address how balancing 
authorities should respond. The Commission notes that PJM recently 
issued a paper addressing frequency excursion related to scheduling 
problems.\164\
---------------------------------------------------------------------------

    \164\ Id. at n.134.
---------------------------------------------------------------------------

    354. In the NOPR, the Commission identified two concerns in the 
Disturbance Control Standard section of BAL-002-0. The first discussed 
NERC's comment that the Reliability Standard is ``absolute, objective, 
and measurable'' because it allows up to 15 minutes for the recovery 
from a reportable disturbance,\165\ and second, the Commission asked 
whether a frequency deviation of 20 milli Hertz lasting longer than the 
15 minute recovery period should be used to define a significant 
deviation in frequency.\166\ No commenters address the first concern 
but many commented on the second.
---------------------------------------------------------------------------

    \165\ NERC Comments on the Staff Preliminary Assessment at 41.
    \166\ NOPR at P 153.
---------------------------------------------------------------------------

    355. First, the Commission directs the ERO to develop a 
modification to the Reliability Standard requiring that any single 
reportable disturbance that has a recovery time of 15 minutes or longer 
be reported as a violation of the Disturbance Control Standard. This is 
consistent with our position in the NOPR and NERC's position in 
response to the Staff Preliminary Assessment of the Requirements in 
BAL-002-0, and was not disputed or commented upon by any NOPR 
commenters.
    356. Taking into account commenters' concerns about defining a 
significant deviation as a frequency deviation of 20 milli Hertz 
lasting longer than the 15 minute recovery period, the Commission will 
not direct a specific change. Instead, we direct the ERO, through the 
Reliability Standards development process, to modify this Reliability 
Standard to define a significant deviation and a reportable event, 
taking into account all events that have an impact on frequency, e.g., 
loss of supply, loss of load and significant scheduling problems, which 
can cause frequency disturbances and to address how balancing 
authorities should respond. As suggested by NRC, this or a related 
Reliability Standard should also include a frequency response 
requirement. The present Control Performance Standards represent the 
monthly and yearly averages which are appropriate for measuring long-
term trends but may not be appropriate for measuring short-term events. 
In addition, the measures should be available to the balancing 
authorities to assist in real-time operations.\167\
---------------------------------------------------------------------------

    \167\ It is the Commission's understanding that the Balancing 
Authority ACE Limit Standards that are currently being field tested 
are triggered on frequency deviations and can be used as feedback to 
the real-time operations personnel.
---------------------------------------------------------------------------

vi. Summary of Commission Determination
    357. The Commission approves Reliability Standard BAL-002-0 as

[[Page 16455]]

mandatory and enforceable. In addition, the Commission directs the ERO 
to develop a modification to BAL-002-0 through the Reliability 
Standards development process that: (1) Includes a Requirement that 
explicitly provides that DSM may be used as a resource for contingency 
reserves; (2) develops a continent-wide contingency reserve 
policy;\168\ and (3) refers to the ERO rather than the NERC Operating 
Committee in Requirements R4.2 and R6.2. In addition, the Commission 
directs the ERO to modify the Reliability Standard in a manner that 
recognizes the loss of transmission as well as generation, thereby 
providing a realistic simulation of possible events that might affect 
the contingency reserves.
---------------------------------------------------------------------------

    \168\ This could be accomplished by modifying Requirement R2 or 
developing a new Reliability Standard.
---------------------------------------------------------------------------

d. Frequency Response and Bias (BAL-003-0)
    358. The purpose of BAL-003-0 is to ensure that a balancing 
authority's frequency bias setting \169\ is accurately calculated to 
match its actual frequency response.\170\ In the NOPR, the Commission 
proposed to approve Reliability Standard BAL-003-0 as mandatory and 
enforceable. In addition, pursuant to section 215(d) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission proposed to direct 
NERC to submit a modification to BAL-003-0 that: (1) Includes Levels of 
Non-Compliance and (2) modifies Measure M1 to include yearly surveys of 
frequency response.\171\
---------------------------------------------------------------------------

    \169\ Frequency bias setting is a value expressed in MW/0.1 Hz, 
set into a balancing authority ACE algorithm, which allows the 
balancing authority to contribute its frequency response to the 
Interconnection. See NERC glossary at 7.
    \170\ The actual frequency response is the increase in output 
from generators after the loss of a generator and determines the 
frequency at which generation and load return to balance.
    \171\ NOPR at P 177.
---------------------------------------------------------------------------

    359. The Commission further requested comments on whether BAL-003-0 
appropriately addresses frequency bias setting during normal as well as 
emergency conditions and whether a requirement should be added for 
balancing authorities to calculate the frequency response necessary for 
reliability in each of the Interconnections and identify a method of 
obtaining that frequency response from a combination of generation and 
load resources.\172\
---------------------------------------------------------------------------

    \172\ Id. at P 175.
---------------------------------------------------------------------------

i. Comments
    360. Several commenters address the Commission's proposal to direct 
the ERO to modify Measurement M1 to include yearly surveys.
    361. LPPC agrees with the Commission's proposed directive. EEI 
states that NERC currently conducts an annual frequency response 
characteristic survey that appears to address the Commission's proposed 
directive. If the yearly survey would replace the frequency response 
characteristic survey, EEI states that the survey should include 
questions regarding the scope of potential new requirements. ISO/RTO 
Council believes that yearly surveys are unnecessary and would prefer 
that NERC focus on surveying balancing authority responses to large 
frequency disturbances.
    362. APPA agrees that the Commission has correctly identified 
shortcomings in this Reliability Standard and states that, while the 
Commission may have identified appropriate modifications, the 
determination should be left to NERC to address in the first instance. 
APPA supports the development of a consistent Interconnection-wide 
policy and suggests that NERC should consider procedures similar to 
those used in ERCOT and WECC.
    363. FirstEnergy suggests that Requirements R5 and R5.1 of this 
Reliability Standard should be required in lieu of Requirement R2 if a 
balancing authority has load but no generation (R5) or if a balancing 
authority has generation but no load (R5.1). FirstEnergy states that 
without this change the Reliability Standard is not clear because it 
implies that a balancing authority could choose between two options. 
Most commenters responded to the Commission's request for comments in 
the NOPR by stating that additional requirements do not need to be 
added for balancing authorities to calculate the frequency response 
necessary for reliability in each of the Interconnections. NERC states 
that frequency bias is currently over-compensated across the 
Interconnections and that requiring frequency bias to be actual 
frequency response may reduce control performance. Additionally, NERC 
states that some studies have shown a decline in frequency (e.g., 
governor) response over several decades and that it is addressing this 
issue through the request for a new Reliability Standard on frequency 
response. NERC also notes that BAL-003-0 will be replaced soon by the 
new balancing Reliability Standards that are approaching ballot.
    364. In general, EEI believes that systemic over-biasing does not 
present a reliability problem and the Commission should exercise 
caution in requesting changes to this Reliability Standard. EEI states 
that the frequency bias varies continuously in terms of the type and 
magnitude of load changes, and the types and loading of generation 
resources. Therefore, EEI suggests that the accuracy of any estimate of 
frequency bias is highly questionable. Further, EEI states that the one 
percent default value was deliberately set to over-bias the system to 
ensure adequate frequency response. EEI is unaware of any evidence of 
undamped oscillations due to this over-biasing and states that the one 
percent floor should be recognized by the Commission as just and 
reasonable until an optimum frequency bias value can be studied. EEI 
sees the potential need for developing requirements for modifying 
frequency bias during emergency conditions, citing evidence from the 
August 2003 blackout suggesting that oscillations following the ISO New 
England separation from the Eastern Interconnection may have been 
caused by over-biasing.
    365. ISO/RTO Council comments that the details of the procedures 
that are used to ensure frequency bias are appropriate and no 
additional requirements for balancing authorities are needed. It 
disagrees with the Commission's proposal to develop uniform 
requirements for frequency bias.\173\ ISO/RTO Council states that there 
is no single right way to develop and apply a frequency bias setting 
and no universally accepted norm. ISO/RTO Council believes the key 
point is that the frequency bias setting be greater than the natural 
frequency response of the system and believes that the percent minimum 
currently in place is sufficient. ISO/RTO Council recommends that NERC 
investigate (1) reliability issues associated with low natural 
response; (2) causes of decreasing natural response and (3) possible 
opportunities for creating markets for load and generator response to 
frequency changes.
---------------------------------------------------------------------------

    \173\ See id. at P 129.
---------------------------------------------------------------------------

    366. Xcel responds that there is no need for this Reliability 
Standard to address frequency bias during black start, restoration and 
islanding due to the transitional nature of those events. Northern 
Indiana opposes imposing greater restrictions on frequency bias and 
frequency response calculations, stating that they could be counter-
productive by making procedural errors more likely, which could harm 
reliability. Northern Indiana suggests that the approach suggested in 
the NOPR would require frequency

[[Page 16456]]

response to be calculated based on various contingencies in a way that, 
if a particular contingency does not occur, the balancing authority 
might contribute to an incorrect frequency response. Northern Indiana 
maintains that the existing Reliability Standard is appropriate because 
it reflects the unique characteristics of each utility's operating 
characteristics and allows experienced, certified operators to act to 
avoid adverse effects on the electric system.
    367. MidAmerican believes that a requirement for balancing 
authorities to calculate the necessary frequency response is not 
necessary for reliability, nor should balancing authorities be required 
to identify the method to obtain that frequency response. MidAmerican 
states that the bias settings addressed in BAL-003-0 are appropriate 
for normal and emergency conditions. It further explains that large 
disturbances resulting in large frequency shifts can only be corrected 
by bringing load and generation into balance. MidAmerican further 
states that the annual review of bias settings uses tie line and 
frequency deviations during large disturbances to provide bias settings 
representative of relatively large frequency excursions and adds that 
these settings, along with automatic generation control and governor 
response, provide an over-biased response to steady-state frequency 
deviations. MidAmerican states that as long as system disturbances are 
continually tracked to ensure frequency decay is sufficiently 
mitigated, enough frequency bias will be on the system and the current 
Reliability Standard can be considered sufficient.
    368. MISO states that it expects the Commission's concerns with the 
frequency response and bias standard to be addressed in NERC's 
frequency response Reliability Standard Authorization Request.
ii. Commission Determination
    369. The Commission approves Reliability Standard BAL-003-0 as 
mandatory and enforceable. In addition, the Commission directs the ERO 
to develop a modification to BAL-003-0 as discussed below.
    370. With respect to the frequency of frequency response surveys, 
EEI states that NERC currently conducts an annual frequency response 
characteristic survey that appears to address the Commission's concern. 
The Commission disagrees. The surveys that were performed on a yearly 
basis are not available on NERC's Web site and the ISO/RTO Council 
believes that more frequent analysis after large frequency disturbances 
is appropriate. The Commission understands that the last analysis was 
performed in 2002. Currently, Measure M1 only requires balancing 
authorities to perform surveys when requested by the NERC operating 
committee. As identified in Order No. 672, the Reliability Standards 
should be based on actual data.\174\ Therefore, on further 
consideration, instead of requiring yearly surveys as proposed in the 
NOPR, the Commission believes that the frequency of these surveys 
should be based on the data requirements that will assist the ERO to 
determine if the balancing authorities are providing adequate and 
equitable frequency response to disturbances on the Bulk-Power System. 
Accordingly, we direct the ERO to determine the optimal periodicity of 
frequency response surveys necessary to ensure that Requirement R2 and 
other Requirements of the Reliability Standard are being met and to 
modify Measure M1 based on this determination.\175\
---------------------------------------------------------------------------

    \174\ Order No. 672 at P 324.
    \175\ As input to the Reliability Standards development process, 
the Commission suggests that the ERO perform sufficient analysis to 
understand how the frequency response varies between balancing 
authorities and Interconnections.
---------------------------------------------------------------------------

    371. With respect to FirstEnergy's comment, Requirement R2 states 
that the frequency bias setting should be as close as practical to, or 
greater than, the balancing authority's frequency response. That is the 
Requirement concerning the relationship between frequency response and 
frequency bias, with Requirement R5 and R5.1 providing minimum 
frequency bias values for specific types of balancing authorities. The 
three Requirements do not conflict. A balancing authority must use a 
frequency bias of at least one percent and they must have a frequency 
bias that is as close as practical to, or greater than, the balancing 
authority's actual frequency response. As will be discussed more fully 
below, the Commission expects each balancing authority to meet these 
Requirements to be in compliance with the existing BAL-003-0.
    372. With respect to the Commission's request for comments, most 
commenters are opposed to additional requirements for balancing 
authorities to calculate the frequency response necessary for 
reliability in each of the Interconnections. NERC states that frequency 
bias is currently over-compensated across the Interconnections, while 
EEI states that the one percent default value was deliberately set to 
over-bias the system to ensure adequate Frequency Response. The ISO/RTO 
Council comments that frequency bias settings are appropriate and all 
agree that no additional requirements are needed. However, NERC 
acknowledges that the frequency response of the Eastern and Western 
Interconnection is decreasing and states it will address the issue with 
a new frequency response Reliability Standard. There is no similar need 
in ERCOT because ERCOT has adopted an approach to calculate the 
necessary frequency response needed for Reliable Operation and has 
identified a method of obtaining the necessary frequency response as 
discussed in BAL-001-0 regional difference. The Commission understands 
that this approach was based on lessons learned from the May 15, 2003 
event \176\ that resulted in larger than anticipated amounts of firm 
load shedding by underfrequency relays operation due to less than 
desirable amounts of frequency response.
---------------------------------------------------------------------------

    \176\ See Underfrequency Load Shedding 2006 Assessment and 
Review by ERCOT Dynamics Working Group, available at http://www.ercot.com/meetings/ros/keydocs/2007/0111/10a._DWG_2006_UFLS_Assessment_12-18-06.doc.
---------------------------------------------------------------------------

    373. The Commission is not persuaded by the commenters. We conclude 
that the minimum frequency response needed for Reliable Operation 
should be defined and methods of obtaining the frequency response 
identified. In addition to the ERCOT experience, EEI provides an 
additional example that underscores the Commission's concern in this 
area with its discussion of the ISO-NE frequency oscillations resulting 
from the August 14, 2003 blackout. Severe oscillations were observed in 
the ISO-NE frequency when it separated from the Eastern Interconnection 
during the August 14, 2003 blackout.\177\ The ISO-NE operators acted 
quickly to reduce the bias setting so as to eliminate the self-induced 
frequency oscillations before they affected system reliability. This 
apparent mismatch between the bias and the actual frequency response 
might have caused the ISO-NE system to cascade if it had not been for 
the quick actions of its operators. Therefore, we direct the ERO to 
either modify this Reliability Standard or develop a new Reliability 
Standard that defines the necessary amount of frequency response needed 
for Reliable Operation and methods of obtaining and measuring that 
frequency response is available.
---------------------------------------------------------------------------

    \177\ See Performance of the New England and Maritimes Power 
Systems During the August 14, 2003 Blackout by Independent System 
Operator New England, available at https://www.npcc.org/publicFiles/blackout/archives/Restoration_of_the_NPCC_Areas.pdf.
---------------------------------------------------------------------------

    374. As the Commission noted in the NOPR and in our response to 
FirstEnergy, Requirement R2 of this

[[Page 16457]]

Reliability Standard states that ``[e]ach Balancing Authority shall 
establish and maintain a Frequency Bias Setting that is as close as 
practical to, or greater than, the Balancing Authority's Frequency 
Response.'' The Commission believes that the achievement of this 
Requirement is fundamental to the tie line bias control schemes that 
have been in use to assist in balancing generation and load in the 
Interconnections for many years.\178\ We understand that the present 
Reliability Standard sets the required frequency response of the 
balancing authorities to be approximately one percent or greater by 
requiring that the frequency bias shall not be less than one percent 
and that the frequency bias be as close as practical to, or greater 
than, the actual frequency response.
---------------------------------------------------------------------------

    \178\ Cohn, Nathan, Control of Generation and Power Flow on 
Interconnected Systems, (John Wiley and Sons 1966).
---------------------------------------------------------------------------

    375. While EEI supports additional requirements related to 
frequency bias during emergency conditions, Xcel states that frequency 
response during black start, restoration and islanding situations need 
not be addressed in a Reliability Standard due to the transient nature 
of these events. The Commission disagrees with Xcel and agrees with 
EEI. The Bulk-Power System should be operated in a reliable manner at 
all times.
    376. Accordingly, the Commission approves Reliability Standard BAL-
003-0 as mandatory and enforceable. In addition, the Commission directs 
the ERO to develop a modification to BAL-003-0 through the Reliability 
Standards development process that: (1) Includes Levels of Non-
Compliance; (2) determines the appropriate periodicity of frequency 
response surveys necessary to ensure that Requirement R2 and other 
requirements of the Reliability Standard are being met, and to modify 
Measure M1 based on that determination and (3) defines the necessary 
amount of Frequency Response needed for Reliable Operation for each 
balancing authority with methods of obtaining and measuring that the 
frequency response is achieved.
e. Time Error Correction (BAL-004-0)
    377. The purpose of BAL-004-0 is to ensure that time error 
corrections are conducted in a manner that does not adversely affect 
the reliability of the Interconnection.\179\ In the NOPR, the 
Commission proposed to approve Reliability Standard BAL-004-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, the Commission 
proposed to direct that NERC submit a modification to BAL-004-0 that 
includes Levels of Non-Compliance and additional Measures.\180\
---------------------------------------------------------------------------

    \179\ The NERC glossary defines ``time error correction'' as 
``an offset to the Interconnection's scheduled frequency to return 
the Interconnection Time Error to a predetermined value.'' NERC 
Glossary at 18. Time error is caused by the accumulation of 
frequency error over a given period.
    \180\ NOPR at P 184.
---------------------------------------------------------------------------

    378. Further, the Commission noted that WECC has implemented an 
automatic time error correction procedure \181\ that, according to data 
on the NERC Web site, is more effective in minimizing both time error 
corrections and inadvertent interchange.\182\ The NOPR asked for 
comment on whether the Commission should require NERC to adopt 
Requirements similar to those in the WECC automatic time error 
correction procedure.
---------------------------------------------------------------------------

    \181\ See http://www.wecc.biz/documents/library/procedures/Time_Error_ Procedure--10-04-02.pdf.
    \182\ See http://www.nerc.com/~filez/inadv.html (regarding 
inadvertent interchange data) and http://www.nerc.com/~filez/
timerror.html (regarding time error correction).
---------------------------------------------------------------------------

i. Comments
    379. MISO states that it is unclear what the Commission had in mind 
with its proposed directive to include Levels of Non-Compliance and 
additional Measures and that the reliability benefit of such Levels of 
Non-Compliance and additional Measures is also unclear.
    380. While APPA and EEI favor adopting the WECC approach to time 
error correction, NERC and the majority of other commenters \183\ are 
either opposed to adopting the WECC automatic time error correction 
procedure in other regions or think time error correction is more 
appropriately addressed as a business practice. NERC notes that the 
WECC procedure is in lieu of an equivalent procedure contained within 
the business practices of the North American Energy Standards Board 
(NAESB) and suggests that instructions for implementing a time error 
correction are more appropriately addressed as a business practice. 
Northern Indiana maintains that WECC-type procedures are unnecessary, 
and could result in unintended process errors or operational problems. 
It urges the Commission to allow time error issues to remain within the 
jurisdiction of NAESB and suggests that time error correction is not 
essential to reliability and is more appropriately treated as a non-
essential guide. ISO-NE agrees that time error correction is not a 
reliability issue.
---------------------------------------------------------------------------

    \183\ See Xcel, Northern Indiana, ISO-NE, LPPC and MISO-PJM.
---------------------------------------------------------------------------

    381. Xcel states that its operating company located in WECC has 
experienced problems with WECC's automatic time error correction 
procedure and therefore does not support adoption of this procedure by 
other regions. In addition, Xcel states that time error correction is 
not necessary for utilities in regional markets where imbalances are 
settled financially and the regional market operator manages the 
scheduled interchange offsets. LPPC suggests that there is not enough 
evidence to show that WECC's time error correction procedure is 
appropriate for the Eastern Interconnection. LPPC adds that the choice 
of switching to the WECC procedure should be left up to the NERC 
Reliability Standards development process.
    382. MISO states that, while the WECC procedure has advantages with 
regard to reducing inadvertent interchange values, it does not reduce 
the number of time error corrections because WECC monitors and performs 
time error correction on a shorter time frame than the Eastern 
Interconnection. MISO argues that this is more of a technical 
requirement and not a Reliability Standard and suggests there are 
simpler ways to control time error and manage inadvertent balances. 
MISO states that NERC previously allowed unilateral payback of 
inadvertent balance of up to 20 percent of bias when the payback is in 
a direction to reduce time error and states that this reduced the 
number of time error corrections while giving balancing authorities a 
tool to balance their accounts. In its comments addressing BAL-006-1, 
MISO suggests that the number of time error corrections could be 
reduced by following the European methodology which has a wider window 
of allowable time and implements full clock-day, but with a smaller 
offset.
ii. Commission Determination
    383. The Commission approves Reliability Standard BAL-004-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, the Commission directs 
the ERO to develop a modification to BAL-004-0 through the Reliability 
Standards development process that includes Levels of Non-Compliance 
and additional Measures for Requirement R3. Further, based on 
commenters' concerns that there is no engineering basis for changing 
the time error correction to the WECC approach or any other approach, 
when reviewing the Reliability Standard during the ERO's scheduled 
five-year cycle of review, we direct the ERO to perform

[[Page 16458]]

research that would provide a technical basis for the present approach 
or for any alternative approach.
    384. Many commenters aver that the time error correction procedure 
belongs within the realm of NAESB and is not a reliability issue. The 
Commission disagrees, as BAL-004-0 is intended to ensure that time 
error corrections are performed in a manner that does not adversely 
affect the reliability of the Interconnection. The financial aspects of 
time error correction such as MISO's concern about the unilateral 
payback of interchange imbalances remain with NAESB. However, the 
technical details, including the means to carry out the procedure, are 
a reliability issue.
    385. We believe that the efficiency of the time error correction 
can be viewed as a measure of whether all balancing authorities are 
participating in time error correction. Requirement R3 states that each 
balancing authority, when requested, shall participate in a time error 
correction. The Commission believes that this is a critical 
requirement, but the data on the NERC Web site indicates that 
efficiency is decreasing, indicating that fewer balancing authorities 
are employing time error correction.\184\ Therefore, the Commission 
affirms its preliminary finding that the efficiency of time error 
corrections has decreased over the last ten years and that 
participation in time error corrections may be lacking.\185\ 
Accordingly, we direct the ERO to develop additional Measures and add 
Levels of Non-Compliance to assure that the requirements in Requirement 
R3 are achieved. One approach to achieving this would be to use the 
existing measurement of efficiency as a metric of participation of all 
balancing authorities. If the efficiency is significantly less than 100 
percent, the Measures should provide a process to identify which 
balancing authorities are not meeting the requirements of the 
Reliability Standard.
---------------------------------------------------------------------------

    \184\ See W.R. Prince, et al., Cost Aspects of AGC, Inadvertent 
Energy and Time Error, IEEE Transactions on Power Systems, February 
1990, at 111.
    \185\ NOPR at P 179, 183.
---------------------------------------------------------------------------

    386. Although the Commission noted in the NOPR that WECC's time 
error correction procedure appears to serve as a more effective means 
of accomplishing time error correction, based on concerns that there is 
no engineering basis for changing the time error correction to the WECC 
approach, the Commission will not direct the ERO to adopt requirements 
similar to WECC's procedure. With the exception of comments from APPA 
and EEI, most commenters do not believe or are uncertain about whether 
the WECC procedure is appropriate for the Eastern Interconnection. 
However, when this Reliability Standard is scheduled for its regular 
five-year cycle of review, the Commission directs the ERO to perform 
whatever research it and the industry believe is necessary to provide a 
sound technical basis for either continuing with the present practice 
or identifying an alternative practice that is more effective and helps 
reduce inadvertent interchange.
    387. The Commission agrees with MISO regarding the number of time 
error corrections using WECC's procedure. However, the magnitude of the 
frequency change in the WECC automatic time error correction is smaller 
than the manual correction and timing of the corrections are better 
correlated to when the error was created. These two characteristics of 
the WECC procedure avoid placing the system in less secure conditions 
and tie the payback to the initiating action, both of which appear to 
better serve both reliability and equity.
f. Automatic Generation Control (BAL-005-0)
    388. The goal of this Reliability Standard is to maintain 
Interconnection frequency by requiring that all generation, 
transmission, and customer load be within the metered boundaries of a 
balancing authority area, and establishing the functional requirements 
for the balancing authority's regulation service, including its 
calculation of ACE.
    389. In the NOPR, the Commission proposed to approve Reliability 
Standard BAL-005-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to submit a modification to BAL-
005-0 that: (1) Includes Requirements that identify the minimum amount 
of automatic generation control or regulating reserves a balancing 
authority must have at any given time; (2) changes the title of the 
Reliability Standard to be neutral as to source of the reserves; (3) 
includes DSM and direct control load management as part of contingency 
reserves and (4) includes additional Levels of Non-Compliance and 
Measures, including a Measure that provides for a verification process 
over the minimum required automatic generation control or regulating 
reserves a balancing authority maintains.\186\
---------------------------------------------------------------------------

    \186\ NOPR at P 197.
---------------------------------------------------------------------------

    390. Further, the NOPR stated that the Commission is interested in 
knowing whether any balancing authority is experiencing or is 
predicting any difficulty in obtaining sufficient automatic generation 
control.
i. Minimum Amount of Regulating Reserves
(a) Comments
    391. South Carolina E&G and SMA support the Commission's proposal 
to include a requirement that addresses minimum regulating reserves. It 
states that the control performance standard metric is a lagging 
indicator of necessary reserves and other standards such as frequency 
response may eventually provide a more dynamic real-time indicator. 
South Carolina E&G believes the Commission's proposal provides a good 
interim solution.
    392. Alcoa comments that, in establishing a minimum amount of 
reserves, NERC should be required to consider the quality of each 
source of reserves. Alcoa suggests that digitally controlled DC loads, 
such as an aluminum smelter, could respond much more rapidly and 
accurately than thermal generators and that using such resources could 
reduce the response time for recovery, allowing thermal units to carry 
fewer spinning reserves and increasing operating efficiencies of the 
grid.
    393. NERC and other commenters \187\ suggest that the Commission's 
proposed directive to have NERC include ``Requirements that identify 
the minimum amount of automatic generation control or regulating 
reserves a balancing authority must have at any given time'' is too 
prescriptive. They also object to this proposed requirement since a 
balancing authority's failure to maintain sufficient regulating 
reserves will result in violations of control performance standard 
criteria already found in BAL-001-0.
---------------------------------------------------------------------------

    \187\ See APPA, EEI, International Transmission, MISO-PJM, 
MidAmerican and LPPC.
---------------------------------------------------------------------------

    394. NERC further states that a requirement to have a minimum 
amount of regulating reserves would result in an arbitrary constraint 
that would not add to reliability and suggests that the Commission 
instead direct NERC to consider the issue of a minimum requirement in 
its Reliability Standards process in order to determine the reliability 
benefit.
    395. EEI states that the industry currently has no consensus-based, 
sound engineering methodology for determining a minimum regulating 
reserve requirement given widely varying needs throughout the country.

[[Page 16459]]

Nonetheless, EEI offers several guidelines that it says could be used 
to provide estimates for minimum regulating reserves. Similarly, 
MidAmerican states that normal regulating margins can vary from one 
balancing authority to another, and even within one balancing 
authority, due to frequently changing load characteristics making it 
extremely difficult to quantify an hourly required level of reserves. 
MidAmerican suggests that instead of prescriptively quantifying reserve 
levels, the ERO should continue to allow the industry to find efficient 
ways to comply with the control performance standards of BAL-001-0.
    396. FirstEnergy suggests that a single entity should have the 
responsibility to establish, through an annual review process, the 
level of regulating reserves that a balancing authority must maintain 
pursuant to the control performance standard requirements. FirstEnergy 
suggests that all generators and technically qualified DSM that 
participate in energy markets should install automatic generation 
control as a condition of market participation. In non-market areas, 
FirstEnergy suggests that balancing authorities could meet requirements 
through bilateral contracts or the normal scheduling process and 
suggests that the Commission might have to assert its jurisdiction and 
order technically qualified DSM providers to install automatic 
generation control at their facilities. FirstEnergy states that further 
work would need to be conducted on the technical qualifications and 
capacity thresholds that would control whether installation of 
automatic generation control would be required.
(b) Commission Determination
    397. On this issue, the Commission directs the ERO to modify BAL-
005-0 through the Reliability Standards development process to develop 
a process to calculate the minimum regulating reserve for a balancing 
authority, taking into account expected load and generation variation 
and transactions being ramped into or out of the balancing authority.
    398. As a general matter, the Commission believes that a single 
entity should establish the level of regulating reserve required based 
on the generation mix and ramping rates in the region. We disagree with 
commenters that minimum regulating reserve requirements are not 
necessary. As South Carolina E&G correctly points out, the control 
performance standard metric is a lagging indicator and, as such, does 
not provide a good indication that the necessary amounts of regulating 
reserve are being carried at all times. The Commission notes that 
Requirement R2 requires maintenance of a level of regulating reserves 
in order to prospectively meet the control performance standard but 
does not provide a calculation for the exact level which would be 
required. In particular, the Commission believes that, while the 
control performance standard metric is useful in identifying trends 
relating to poor regulating practices, specification of minimum reserve 
requirements to be maintained at all times would complement the control 
performance standard metrics by providing real-time requirements 
necessary for proper control.
    399. With regard to Alcoa's comment, the Commission agrees that the 
quality of reserves is relevant in determining if the resource is able 
to technically qualify as regulation.
    400. Nevertheless, the Commission recognizes commenters' concerns 
related to the calculation of minimum regulation. EEI has offered 
several possible methods to calculate the minimum amount of regulation 
needed for reliability, which may or may not be consistent with others 
in the industry. The fundamental reason for regulating reserves is to 
balance load and generation in the short term due to the random 
variations in the balancing authorities' loads and to accommodate 
ramping of transactions. The Commission therefore directs the ERO to 
develop a process to calculate the minimum regulating reserve for a 
balancing authority, taking into account expected load and generation 
variation and transactions being ramped into or out of the balancing 
authority.
ii. Title Change and Inclusion of DSM.
(a) Comments
    401. As an initial matter, many commenters express confusion about 
the Commission's proposal to require NERC to change the title of the 
Reliability Standard to be neutral as to the source of the reserves, 
and include DSM and direct control load management as part of 
contingency reserves.\188\ In particular, these commenters argue that 
this Reliability Standard pertains to regulating reserve and not 
contingency reserves.
---------------------------------------------------------------------------

    \188\ EEI, TVA, International Transmission, Multiple 
Interveners, MISO-PJM, South Carolina E&G and Wisconsin Electric.
---------------------------------------------------------------------------

    402. Constellation agrees with the Commission that DSM and direct 
control load management should be included as viable options for 
regulating reserves.\189\ MidAmerican agrees with the Commission on the 
proposed title change to allow it to be neutral as to the source of 
reserves but cautions the Commission on including DSM as a source of 
contingency reserves. While MidAmerican believes it proper to include 
direct control load management, which is under direct control of the 
system operator in contingency reserves, it states that the term DSM 
(as defined in the NERC glossary) is too general and includes programs 
that cannot contribute toward contingency reserves.
---------------------------------------------------------------------------

    \189\ Since the Commission used the term ``contingency 
reserves'' inappropriately in this section, we assume that 
Constellation intended this to be regulating reserves.
---------------------------------------------------------------------------

    403. APPA and International Transmission both disagree with the 
Commission's proposals to change the title of this Reliability Standard 
and to include DSM and direct control load management. APPA suggests 
that DSM and direct control load management are not operationally 
equivalent to dispatchable generation resources and does not believe 
these programs are an effective source of regulating reserve given the 
current state of technology. International Transmission simply states 
that regulating reserves required by BAL-005-0 are specifically 
responsive to automatic generation control.
    404. ISO-NE disagrees with the Commission's proposal to include DSM 
and direct control load management as part of this service, stating 
that responsive load has not demonstrated the load following capability 
necessary to provide regulation and that it is not aware of any load-
based resources that can closely follow automatic generation control 
signals sent every four seconds. As an alternative to the Commission's 
approach, ISO-NE suggests that the Reliability Standard should define 
the reliability purpose or objective and then be resource-neutral.
(b) Commission Determination
    405. At the outset, the Commission agrees with commenters that this 
Reliability Standard applies to regulating reserves and not contingency 
reserves. The references to contingency reserves under this Reliability 
Standard in the NOPR are confusing. The Commission clarifies that its 
direction to the ERO in this section is for it to develop a 
modification to BAL-005-0 through the Reliability Standards development 
process that changes the title of the Reliability Standard to be 
neutral as to the source of regulating reserves and allows the 
inclusion of technically qualified DSM and direct

[[Page 16460]]

control load management as regulating reserves, subject to the 
clarifications provided in this section.
    406. We disagree that it is not possible to use DSM and direct 
control load management as a source of regulating reserves or any other 
type of operating reserves. The Commission notes that, while DSM and 
direct control load management may not be widely used today as a source 
of operating reserves, comments received and other evidence suggest 
that certain types of loads are technically capable of providing this 
service. For example, comments received from Alcoa suggest that certain 
loads, such as digitally controlled DC loads, are capable of responding 
much faster than generation to a reserve need.
    407. Given that most of the commenters' concerns over the inclusion 
of DSM as part of regulating reserves relate to the technical 
requirements, the Commission clarifies that to qualify as regulating 
reserves, these resources must be technically capable of providing the 
service. In particular, all resources providing regulation must be 
capable of automatically responding to real-time changes in load on an 
equivalent basis to the response of generation equipped with automatic 
generation control. From the examples provided above, the Commission 
understands that it may be technically possible for DSM to meet 
equivalent requirements as conventional generators and expects the 
Reliability Standards development process to provide the qualifications 
they must meet to participate. These qualifications will be reviewed by 
the Commission when the revised Reliability Standard is submitted to 
the Commission for approval.
iii. Whether Balancing Authorities Are Experiencing or Predicting 
Difficulty in Obtaining Sufficient Automatic Generation Control
(a) Comments
    408. Constellation states that its ability to obtain regulating 
reserves is hampered by a lack of resources that qualify as regulation 
and the practices that some transmission service providers have adopted 
in implementing dynamic transfers needed to procure regulating reserves 
from other balancing authorities. In particular, Constellation states 
that many transmission service providers impose a requirement that 
regulation services must be provided using firm transmission. 
Constellation suggests that purchasing regulation from another 
balancing authority using non-firm transmission service is allowed 
under the Reliability Standards and that Requirement R5 of BAL-005-0 
provides that balancing authorities must have back-up plans to provide 
replacement regulation service if the purchased regulation service is 
lost. Constellation requests that the Commission clarify that the 
transmission providers may not impose a requirement to rely exclusively 
on firm transmission for the dynamic transfers of regulating reserves.
(b) Commission Determination
    409. In response to Constellation's concerns, the Commission notes 
that, if regulation is being provided over non-firm transmission 
service, the entity receiving the regulation should be responsible for 
having a back-up plan to include loss of the non-firm transmission 
service as referenced in Requirement R5. The Commission believes that a 
balancing authority may use non-firm transmission service for procuring 
regulation, so long as that balancing authority has a back-up plan that 
it can implement to include loss of non-firm transmission service.
iv. Other Comments
(a) Comments
    410. MISO states that it is uncertain of the basis of the claim 
that there have been an increased number of ``[automatic generation 
control] controllable'' frequency excursions.\190\ MISO further states 
that data in the Eastern Interconnection shows the number of larger-
slower excursions has decreased over the past few years.
---------------------------------------------------------------------------

    \190\ NOPR at P 194.
---------------------------------------------------------------------------

    411. Xcel requests that the Commission reconsider Requirement R17 
of this Reliability Standard stating that the accuracy ratings for 
older equipment (current and potential transformers) may be difficult 
to determine and may require the costly replacement of this older 
equipment on combustion turbines and older units while adding little 
benefit to reliability. Xcel states that the Commission should clarify 
that Requirement R17 need only apply to interchange metering of the 
balancing area in those cases where errors in generating metering are 
captured in the imbalance responsibility calculation of the balancing 
area.
    412. FirstEnergy states that Requirement R17 should include only 
``control center devices'' instead of devices at each substation. 
FirstEnergy states that accuracy at the substation level is unnecessary 
and the costs to install automatic generation control equipment at each 
substation would be high. FirstEnergy also states that the term 
``check'' in Requirement R17 needs to be clarified.
    413. California Cogeneration states that the Commission has 
previously ruled that separate metering for the gross generation of a 
customer-owned generator is not proper or necessary, and states that 
the Commission should clarify that this Reliability Standard does not 
establish metering requirements for individual generators, and does not 
allow separate metering of generation and load on an end-user's 
site.\191\
---------------------------------------------------------------------------

    \191\ See California Cogeneration at 6, citing California 
Independent System Operator Corp., Opinion No. 464, 104 FERC ] 
61,196 (2003).
---------------------------------------------------------------------------

    414. LPPC notes that BAL-005-0 has 17 requirements but no Measures, 
and that it uses phrases such as ``adequate metering'' and ``burden on 
the interconnection.'' LPPC contends that there is no definition for 
these ambiguous terms and that there is no way to determine if terms 
like ``adequate metering'' will mean the same thing in different parts 
of the country or ensure consistent penalties will be assessed for the 
same violation.
(b) Commission Determination
    415. The Commission agrees with MISO that, while the number of 
frequency deviations due to loss of generation has decreased, the 
Commission is concerned with the implications of the actual data 
presented by PJM that shows two frequency deviations each week day 
without the loss of generation.\192\ This concern is supplemented by 
documents that identify that some balancing authorities are restricting 
automatic generation control actions during schedule changes.\193\
---------------------------------------------------------------------------

    \192\ NOPR at n.134.
    \193\ See R. L. Vice, Frequency Issues 2005, available at: 
http://www.wecc.biz/documents/library/RITF/Frequency_Issues_2005_rev_0.pdf.
---------------------------------------------------------------------------

    416. Both Xcel and FirstEnergy question Requirement R17 but do not 
oppose the Commission's proposal to approve this Reliability Standard. 
Earlier in this Final Rule, we direct the ERO to consider the comments 
received to the NOPR in its Reliability Standards development process. 
Thus, the comments of Xcel and FirstEnergy should be addressed by the 
ERO when this Reliability Standard is revisited as part of the ERO's 
Work Plan.
    417. California Cogeneration requests clarification that Commission 
rulings made prior to the enactment of FPA section 215 would still be 
applicable. The case cited by California Cogeneration was issued before 
EPAct 2005 was enacted and gave the Commission direct responsibility 
over

[[Page 16461]]

Bulk-Power System reliability. By its terms, BAL-005-0 requires each 
generator operator with generating facilities operating within an 
Interconnection to ensure that those generating facilities are included 
within the metered boundaries of a balancing authority area. Therefore, 
any generator that is subject to the Reliability Standards, as 
discussed in the Applicability Issues section of this Final Rule,\194\ 
is subject to the metering requirements in this Reliability Standard. 
Our conclusion, however, does not determine the appropriate ratemaking 
treatment.
---------------------------------------------------------------------------

    \194\ See Applicability Issues: Bulk-Power Ststem v. Bulk 
Electric System and Applicability to Small Entities, supra sections 
II.C.1-2.
---------------------------------------------------------------------------

    418. With respect to LPPC's concern that terms used in the 
Reliability Standard are not definitive when viewed individually, and 
LPPC's statement that the Reliability Standard is ambiguous because it 
does not include Measures, we disagree. The Commission finds each 
Requirement of BAL-005-0 is clear and enforceable. The Requirements 
provide sufficient guidance for an entity to understand its 
obligations. When Measures are incorporated into the Reliability 
Standard, the Measures will provide guidance on assessing non-
compliance with the Requirements. For these reasons and as previously 
addressed in the NOPR, the Commission disagrees that the enforceable 
obligations set forth in Requirements are unclear absent Measures.
    419. The Commission notes that no one commented on the proposal to 
include Levels of Non-Compliance and Measures, including a Measure that 
provides for a verification process over the minimum required automatic 
generation control or regulating reserves a balancing authority 
maintains. The Commission adopts the NOPR proposal to require the ERO 
to modifiy the Reliability Standards to include a Measure that provides 
for a verification process over the minimum required automatic 
generation control or regulating reserves a balancing authority 
maintains. However, as discussed in the Common Issues section of this 
Final Rule, we will leave it to the discretion of the ERO whether to 
include other Measuers.\195\
---------------------------------------------------------------------------

    \195\ See Common Issues Pertaining to Reliability Standards: 
Measures and Levels of Non-Compliance, supra section II.E.2.
---------------------------------------------------------------------------

    420. FirstEnergy has a number of suggestions to improve the 
existing Reliability Standard and the ERO is directed to consider those 
suggestions in its Reliability Standards development process.
v. Summary of Commission Determinations
    421. The Commission approves Reliability Standard BAL-005-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, the Commission directs 
the ERO to develop a modification to BAL-002-0 through the Reliability 
Standards development process that: (1) Develops a process to calculate 
the minimum regulating reserve a balancing authority must have at any 
given time taking into account expected load and generation variation 
and transactions being ramped into or out of the balancing authority; 
(2) changes the title of the Reliability Standard to be neutral as to 
the source of regulating reserves and to allow the inclusion of 
technically qualified DSM and direct control load management; (3) 
clarifies Requirement R5 of this Reliability Standard to specify the 
required type of transmission or backup plans when receiving regulation 
from outside the balancing authority when using non-firm service and 
(4) includes Levels of Non-Compliance and a Measure that provides for a 
verification process over the minimum required automatic generation 
control or regulating reserves a balancing authority must maintain.
g. Inadvertent Interchange (BAL-006-1)
    422. BAL-006-1 requires that each balancing authority calculate and 
record inadvertent interchange on an hourly basis.
    423. In the NOPR, the Commission proposed to approve Reliability 
Standard BAL-006-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct that NERC submit a modification to 
BAL-006-1 that adds Measures and additional Levels of Non-Compliance 
including Measures concerning the accumulation of large inadvertent 
imbalances.\196\
---------------------------------------------------------------------------

    \196\ NOPR at P 212.
---------------------------------------------------------------------------

    424. In addition, the NOPR solicited comment on whether 
accumulation of large amounts of inadvertent imbalances is a concern to 
the industry and if so, options to address the accumulation.
i. Measures and Additional Levels of Non-Compliance Including Measures 
Concerning the Accumulation of Large Inadvertent Imbalances
(a) Comments
    425. Certain commenters \197\ do not support the Commission's 
proposal to add Measures and additional Levels of Non-Compliance, 
including Measures concerning the accumulation of large inadvertent 
imbalances. Xcel states that such a measure would not enhance 
reliability and involves primarily a commercial matter. MRO suggests 
that large inadvertent balances are an equity issue and as such should 
be addressed through business practices and not through the Reliability 
Standards. MidAmerican states that no additional measures addressing 
inadvertent imbalances are needed in this Reliability Standard because 
the issue is adequately addressed in other Reliability Standards.\198\ 
MidAmerican states that if the Commission proceeds to require Measures 
and Levels of Non-Compliance for large accumulations, it must insure 
that no ``double penalties'' are imposed.
---------------------------------------------------------------------------

    \197\ Xcel, MRO, MidAmerican and MISO-PJM.
    \198\ MidAmerican explains that large interchange imbalances are 
a result of telemetry failures, AGC misoperation or scheduling 
errors and further states that BAL-001 addresses AGC performance and 
the INT standards handle compliance with scheduling requirements.
---------------------------------------------------------------------------

    426. EEI believes that the need to set a Measure for the 
accumulation of large inadvertent imbalances may be premature. EEI 
suggests that inadvertent energy is not a problem in real-time 
operations and is the result of frequency over-bias. EEI further states 
that if the Commission believes the industry should address both 
inadvertent energy and frequency bias, the clear consequence is a 
fundamental reconsideration of the control performance standard. EEI 
strongly recommends that the Commission clarify whether it intends for 
the industry to reconsider this fundamental reliability principle.
    427. Constellation states some concern regarding the ability of 
balancing authorities to make appropriate arrangements to settle 
inadvertent imbalances. In particular, Constellation states that in 
arranging bilateral paybacks, it is difficult to find a counterparty 
with an opposite balance and there are transmission fees that further 
hinder the process of these paybacks. Constellation states that the 
Commission should require the industry to adopt procedures that will 
better facilitate bilateral payback of inadvertent energy, such as 
waiving the

[[Page 16462]]

scheduling requirement for small bilateral paybacks (such as WECC has 
implemented).
    428. TAPS repeats the arguments it made in its comments on the 
Staff Preliminary Assessment that the existing treatment of balancing 
authority inadvertent interchange is not comparable to the treatment of 
energy imbalances. TAPS suggests that the Commission has an obligation 
to do more than what is proposed in the NOPR, which states that the 
issue is being addressed in the OATT reform docket \199\ while 
approving Reliability Standards that perpetuate the preferential 
treatment of balancing authority inadvertent interchange.\200\
---------------------------------------------------------------------------

    \199\ OATT Reform NOPR at P 208.
    \200\ NOPR at P 206.
---------------------------------------------------------------------------

(b) Commission Determination
    429. The Commission directs the ERO to develop a modification to 
BAL-006-1 that adds Measures concerning the accumulation of large 
inadvertent imbalances and Levels of Non-Compliance. While we agree 
that inadvertent imbalances do not normally affect the real-time 
operations of the Bulk-Power System and pose no immediate threat to 
reliability, we are concerned that large imbalances represent 
dependence by some balancing authorities on their neighbors and are an 
indication of less than desirable balancing of generation with load. 
The Commission also notes that the stated purpose of this Reliability 
Standard is to define a process for monitoring balancing authorities to 
ensure that, over the long term, balancing authorities do not 
excessively depend on other balancing authorities in the 
Interconnection for meeting their demand or interchange obligations.
    430. The Commission disagrees with MidAmerican that having Measures 
in this Reliability Standard will result in double penalties. The 
Commission believes that this Reliability Standard has an independent 
reliability goal that ``define[s] a process for monitoring balancing 
authorities to ensure that, over the long term, balancing authorities 
do not excessively depend on other balancing authority areas in the 
Interconnection for meeting their demand or interchange obligations.'' 
\201\
---------------------------------------------------------------------------

    \201\ See BAL-006-1 (Inadvertent Interchange, Purpose 
Statement).
---------------------------------------------------------------------------

    431. The Commission agrees with EEI that one of the root causes of 
inadvertent interchange is the difference between the actual frequency 
response and the existing bias settings. The Commission has directed 
that this cause be addressed in other BAL Reliability Standards. If the 
industry wishes to propose alternative metrics to the control 
performance Reliability Standards, the Commission suggests that it does 
so through the ERO processes and that such changes include an 
explanation of how the revised metrics would better measure the ability 
of an individual balancing authority to match load and generation.
    432. In response to Constellation's comment about the fees 
associated with the settlement of inadvertent imbalances, the 
Commission notes that this issue relates to business practices and 
should be brought before NAESB or otherwise addressed in contexts other 
than section 215 of the FPA.
    433. With respect to TAPS' concerns regarding disparate treatment 
of imbalances for non-control area utilities, the Commission is not 
convinced that this is a reliability issue. As identified in Order No. 
890, inadvertent interchange is not comparable to imbalances.\202\
---------------------------------------------------------------------------

    \202\ See Order No. 890 at P 702-03.
---------------------------------------------------------------------------

    434. Accordingly, the Commission adopts the proposal in the NOPR to 
direct the ERO to develop Measures under this Reliability Standard to 
ensure balancing authorities will not have large inadvertent 
imbalances.
ii. Whether the Accumulation of Large Amounts of Inadvertent Imbalances 
Is a Concern and Potential Options
(a) Comments
    435. LPPC states that its members are concerned that large 
inadvertent imbalances would be an indication of an underlying issue 
related to overall balancing of resources and demand and suggests that 
options to address these large inadvertent imbalances should be 
addressed through the Reliability Standards development process.
    436. NERC states that the performance requirements that relate to 
reliability are addressed in BAL-001-0 and BAL-002-0 and the new 
Reliability Standards which will replace them. Further, NERC states 
that if the Commission wishes to direct consideration of limits on the 
amount of inadvertent imbalances, such directive should be in the form 
of an issue to be resolved or reliability objective to be achieved 
rather than a specific requirement to set a fixed limit on inadvertent 
accumulation.
    437. TVA, MISO and MidAmerican state that the accumulation of large 
inadvertent balances over time does not raise grid reliability issues. 
TVA asserts that this is largely a financial matter. In addition, TVA 
comments that if a balancing authority inappropriately uses the 
interconnection in a way which results in a large inadvertent imbalance 
this behavior should be reflected in the balancing authority's control 
performance standard compliance. MISO states that some large amounts of 
inadvertent imbalance are due to a balancing authority fulfilling its 
bias obligation. MISO states that an arbitrary cap should not be a part 
of this Reliability Standard.
(b) Commission Determination
    438. As stated previously, while the Commission agrees that these 
imbalances do not present an immediate reliability problem, we believe, 
as stated by LPPC, that large interchange imbalances are indicative of 
an underlying problem related to balancing of resources and demand. It 
would be worthwhile for the ERO to examine the WECC time error 
correction procedure.
    439. Since the ERO indicates that the reliability aspects of this 
issue will be addressed in a Reliability Standards filing later this 
year, the Commission asks the ERO, when filing the new Reliability 
Standard, to explain how the new Reliability Standard satisfies the 
Commission's concerns.
iii. Summary of Commission Determinations
    440. Accordingly, the Commission approves Reliability Standard BAL-
006-1 as mandatory and enforceable. In addition, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to BAL-006-1 
through the Reliability Standards development process that includes 
Measures concerning the accumulation of large inadvertent imbalances 
and additional Levels of Non-Compliance.
h. Regional Differences to BAL-006-1: Inadvertent Interchange 
Accounting and Financial Inadvertent Settlement
    441. The NOPR explained that BAL-006-1 provides for two regional 
differences.\203\ First, a regional difference is provided for an RTO 
with multiple balancing authorities. The control area participants of 
MISO requested that MISO be given an inadvertent interchange account so 
that financial settlement of all energy receipts and deliveries using 
locational marginal pricing could be implemented to meet their 
Commission directed market obligations. Subsequently, Southwest Power 
Pool (SPP) requested,

[[Page 16463]]

and NERC approved, the same regional difference for.\204\
---------------------------------------------------------------------------

    \203\ NOPR at P 216.
    \204\ BAL-006-1, filed on August 28, 2006, would extend the 
regional difference to SPP.
---------------------------------------------------------------------------

    442. Second, the NOPR explained that a regional difference would 
apply to the control area participants of MISO and SPP that would allow 
each RTO to financially settle inadvertent energy between control areas 
in the RTO. Each RTO would maintain accumulations of the net 
inadvertent interchange for all the control areas in the RTO after the 
financial settlement, and therefore accumulation of net-interchange 
would not affect the non-participant control areas.
    443. The Commission proposed to approve these regional differences, 
explaining that the two proposed regional differences relate solely to 
facilitating financial settlements of accumulated inadvertent 
interchange due to the physical differences of these areas and have 
minimal, if any, reliability implications.
i. Comments
    444. FirstEnergy notes that the two proposed regional differences 
reference the Version 0 policies instead of the NERC Reliability 
Standards and requests that the Commission direct NERC to revise the 
regional differences accordingly. In addition, FirstEnergy states that 
the Commission should direct NERC to define the function of a waiver. 
FirstEnergy agrees that transferring responsibility for the tasks under 
these waivers to the RTO is appropriate.
ii. Commission Determination
    445. No commenter objected to the regional differences to BAL-006-
1. However, the Commission agrees with FirstEnergy that the regional 
differences incorrectly reference retired policy terminology. 
Therefore, the Commission approves the regional differences as 
mandatory and enforceable under Order No. 672 as necessary due to the 
physical differences between multiple balancing authorities and a 
single market \205\ but the Commission directs the ERO to modify the 
regional differences so that they reference the current Reliability 
Standards and are in the standard form, which includes Requirements, 
Measures and Levels of Non-Compliance. The ERO should explore 
FirstEnergy's request to define the function of a waiver in its 
Reliability Standards development process.
---------------------------------------------------------------------------

    \205\ Order No. 672 at P 291.
---------------------------------------------------------------------------

2. CIP: Critical Infrastructure Protection
    446. The goal of CIP-001-1 is to ensure that operating entities 
recognize sabotage events and inform appropriate authorities and each 
other to properly respond to the sabotage to minimize the impact on the 
Bulk-Power System.\206\ The Reliability Standard requires that each 
reliability coordinator, balancing authority, transmission operator, 
generation operator and LSE have procedures for recognizing and for 
making operating personnel aware of sabotage events, and communicating 
information concerning sabotage events to appropriate ``parties'' in 
the Interconnection.\207\
---------------------------------------------------------------------------

    \206\ The NOPR addressed CIP-001-0. On November 15, 2006, NERC 
submitted for approval proposed Reliability Standard CIP-001-1, 
which revised and replaced the previous version of the Reliability 
Standard to include Measures and Levels of Non-Compliance.
    \207\ On August 28, 2006, NERC submitted for approval proposed 
Reliability Standards CIP-002-1 through CIP-009-1. These proposed 
Reliability Standards, which relate to cybersecurity, are being 
addressed in a separate rulemaking proceeding in Docket No. RM06-22-
000.
---------------------------------------------------------------------------

    447. In the NOPR, the Commission proposed to approve Reliability 
Standard CIP-001-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct that NERC submit a modification to 
CIP-001-0 that: (1) Includes Measures and Levels of Non-Compliance; (2) 
gives guidance for the term ``sabotage;'' (3) requires an applicable 
entity to contact appropriate federal authorities, such as the 
Department of Homeland Security, in the event of sabotage within a 
specified period of time and (4) requires periodic review of sabotage 
response procedures.
    448. In the NOPR, the Commission explained that the Requirements of 
CIP-001-0 refer to a ``sabotage event'' but do not define that term. 
The Commission stated that, while ``sabotage'' is a commonly understood 
term and the common understanding should suffice in most circumstances, 
it was concerned that situations may arise in which it is not clear 
whether action pursuant to CIP-001-0 is required. Thus, the NOPR 
proposed that the ERO provide guidance clarifying the triggering event 
for an entity to take action pursuant to CIP-001-0.
a. Comments
    449. EEI and Entergy comment that they generally agree with the 
Commission's perspective. While APPA and Six Cities support approving 
CIP-001-1 as mandatory and enforceable, they ask that the Commission 
defer the application of monetary penalties until further guidance is 
provided on what events are reportable and what steps an entity must 
take to be certain it is in compliance with the Reliability Standard. 
Claiming that CIP-001-1 is too vague to be enforceable, TAPS opposes 
approval until NERC has further defined ``sabotage'' and the facilities 
to which the Reliability Standard applies.
    450. APPA questions whether CIP-001-1 should apply to LSEs (LSEs) 
contending that, unlike transmission owners and generators, LSEs do not 
own or operate ``hard assets'' that are normally thought of ``at risk'' 
to sabotage. It claims that compliance would be particularly burdensome 
for small LSEs, such as the requirement to provide a preliminary report 
within one hour of an event. APPA states that NERC should therefore 
reconsider whether LSEs should be required to comply with this 
Reliability Standard. Further, while APPA supports the application of 
CIP-001-1 to larger generators and any unit required for reliable 
interconnected operations, it questions whether it is critical to 
extend the Reliability Standard to all generator operators--noting that 
there are 3,564 generating plants in the United States with a total 
capacity of 75 MW or less. APPA contends that the incremental benefits 
of requiring all generators to comply with CIP procedures seem minimal 
since many facilities are unlikely to have a material impact on Bulk-
Power System reliability or be a target for sabotage in the first 
place. APPA suggests that the Commission defer action on CIP-001-1 
while it implements a prioritization plan.
    451. TAPS and California Cogeneration are also concerned about 
applicability and contend that compliance should be limited to those 
that have a significant or material impact on Bulk-Power System 
reliability. Both are concerned that compliance with this Reliability 
Standard would create significant administrative burdens and 
documentation requirements that are not justified where a facility does 
not have a material impact on the Bulk-Power System. California 
Cogeneration suggests that CIP-001-1 be revised to: (1) Exclude 
generator output used on-site and (2) provide a mechanism for 
determining that a facility has no material impact and thus is exempt 
from compliance.
    452. A number of commenters agree with the Commission's concern 
that the term ``sabotage'' needs to be better defined and guidance 
provided on the triggering events that would cause an

[[Page 16464]]

entity to report an event.\208\ FirstEnergy states that this definition 
should differentiate between cyber and physical sabotage and should 
exclude unintentional operator error. It advocates a threshold of 
materiality to exclude acts that do not threaten to reduce the ability 
to provide service or compromise safety and security. SoCal Edison 
states that clarification regarding the meaning of sabotage and the 
triggering event for reporting would be helpful and prevent over-
reporting.
---------------------------------------------------------------------------

    \208\ See, e.g., APPA, FirstEnergy, SoCal Edison, Six Cities and 
TAPS.
---------------------------------------------------------------------------

    453. APPA comments that Requirement R1 of CIP-001-1, which provides 
that an entity must have procedures for recognizing sabotage events and 
making its personnel aware of sabotage events, while a ``good first 
step,'' lacks sufficient detail upon which the ERO can base compliance 
and enforcement efforts. It characterizes CIP-001-1 as an ``entity-
specific `fill-in-the-blank' standard'' that does not provide 
sufficient direction or guidance for an entity to determine whether it 
is in compliance. APPA further states that Measure M1 provides no 
criteria for a Regional Entity, acting in its capacity as a compliance 
monitor, to make an objective determination that an entity's sabotage 
procedure is adequate.
    454. In response to the Commission's concern regarding the need for 
periodic review of sabotage response procedures, FirstEnergy suggests 
that CIP-001-1 should define what time period is sufficient for 
periodic reviews and suggests that a bi-annual review would be 
appropriate. MRO believes that a requirement to annually review the 
sabotage response procedures should be added to the Reliability 
Standard.
    455. NERC objects to the wording of the Commission's proposed 
directive that NERC modify CIP-001-1 to require an applicable entity to 
contact appropriate federal authorities, such as the Department of 
Homeland Security, in the event of sabotage within a specified period 
of time. NERC states the Commission's directive is overly prescriptive 
because it specifies language to be included in the standard and 
thereby circumvents the Reliability Standards development process. 
Further, NERC objects that this directive would require entities in 
other nations such as Canada or Mexico to report to the U.S. Department 
of Homeland Security. Santa Clara suggests that Requirement R4 (and 
corresponding measure M3) should be modified to state that ``* * * 
contacts should be established with the appropriate public safety 
officials or directly with the local Federal Bureau of Investigation 
(FBI) or Royal Canadian Mounted Police (RCMP) such that communication 
channels are established to report incidents to the appropriate 
authority.'' It states that, in the case of a municipal utility that is 
part of a local governmental agency that already has a public safety 
department which is in regular contact with the local FBI, and where 
clear communication channels already exist between the public safety 
department and the utility, it would be redundant for the utility to 
establish a direct link to the FBI for reporting purposes. Xcel also 
suggests that the term ``appropriate federal authorities'' should be 
modified to avoid conflict with established processes now in place, and 
that the term should be specifically identified so the Requirements on 
affected entities are clear.
    456. Process Electricity Committee advocates approval of CIP-001-0 
as initially proposed by NERC without modification, but it objects to 
the revised CIP-001-1 as placing an undue burden on smaller entities. 
It is concerned that the Commission's proposal to require mandatory 
reporting to appropriate federal authorities within a specific time 
frame will impose substantial burdens on end users with little or no 
discernable benefit. It states that there is no evidence that any 
entities--both regulated and unregulated--under-report sabotage events. 
Further, according to Process Electricity Committee, the adoption of 
uniform requirements could require end users to modify existing 
security programs and procedures that are designed to protect 
industrial facilities, whereas the utility generator requirements could 
be conflicting or duplicative.
    457. Entergy and FirstEnergy express concern that there is a 
potential for redundancy between CIP-001-1 and other related federal 
reporting standards. Entergy states that NERC should consider ensuring 
that CIP-001-1 is consistent with, but not duplicative of, these other 
requirements. FirstEnergy states that both the Department of Energy 
(DOE) and the Energy Information Administration (EIA) impose reporting 
requirements that are similar to CIP-001-1 and suggests that to avoid 
conflicts the reporting requirements under this Reliability Standard 
should be conformed to the existing DOE and EIA requirements. It also 
states that nuclear units have their own set of operating requirements, 
including procedures for reporting sabotage, and suggests that a 
company's compliance with NRC procedures should be presumed to meet 
NERC standards. EEI, FirstEnergy and Xcel suggest greater coordination, 
possibly with all events being reported to NERC, which would then 
coordinate with federal authorities. Xcel suggests the development of a 
single sabotage reporting form to streamline the reporting process and 
make it easier for affected entities to provide reports in a timely 
manner.
    458. APPA and FirstEnergy express concern about a requirement to 
report an act of sabotage within a fixed period of time. Xcel states 
that the triggering event for disclosure of an act of sabotage often 
will be unclear and that an investigation will take time especially if 
the event occurs at an unstaffed or remote facility. Thus, Xcel does 
not believe that the standard should contain an express time limit for 
reporting an act of sabotage since the amount of time necessary to make 
that report may vary depending on the circumstances. FirstEnergy 
suggests that CIP-001-1 should define the specified period for 
reporting an incident beginning from when the event is discovered or 
suspected to be sabotage. APPA is also concerned that a specific time 
limit for a report (such as a 60 minute requirement) would be 
burdensome to meet for a small LSE that is not continuously staffed 
when a triggering event occurs outside staffed hours.
b. Commission Determination
i. Applicability to Small Entities
    459. The Commission acknowledges the concerns of the commenters 
about the applicability of CIP-001-1 to small entities and has 
addressed the concerns of small entities generally earlier in this 
Final Rule. Our approval of the ERO Compliance Registry criteria to 
determine which users, owners and operators are responsible for 
compliance addresses the concerns of APPA and others.
    460. However, the Commission believes that there are specific 
reasons for applying this Reliability Standard to such entities, as 
discussed in the NOPR. APPA indicates that some small LSEs do not own 
or operate ``hard assets'' that are normally thought of as ``at risk'' 
to sabotage. The Commission is concerned that, an adversary might 
determine that a small LSE is the appropriate target when the adversary 
aims at a particular population or facility. Or an adversary may target 
a small user, owner or operator because it may have similar equipment 
or protections as a larger facility, that is, the adversary may use an 
attack against a smaller facility as a training ``exercise.'' The 
knowledge of sabotage events that occur at any facility

[[Page 16465]]

(including small facilities) may be helpful to those facilities that 
are traditionally considered to be the primary targets of adversaries 
as well as to all members of the electric sector, the law enforcement 
community and other critical infrastructures.
    461. For these reasons, the Commission remains concerned that a 
wider application of CIP-001-1 may be appropriate for Bulk-Power System 
reliability. Balancing these concerns with our earlier discussion of 
the applicability of Reliability Standards to smaller entities, we will 
not direct the ERO to make any specific modification to CIP-001-1 to 
address applicability. However, we direct the ERO, as part of its Work 
Plan, to consider in the Reliability Standards development process, 
possible revisions to CIP-001-1 that address our concerns regarding the 
need for wider application of the Reliability Standard. Further, when 
addressing such applicability issues, the ERO should consider whether 
separate, less burdensome requirements for smaller entities may be 
appropriate to address these concerns.
ii. Definition of Sabotage
    462. Several commenters agree with the Commission's concern that 
the term ``sabotage'' should be defined. For the reasons stated in the 
NOPR, we direct that the ERO further define the term and provide 
guidance on triggering events that would cause an entity to report an 
event.\209\ However, we disagree with those commenters that suggest the 
term ``sabotage'' is so vague as to justify a delay in approval or the 
application of monetary penalties. As explained in the NOPR, we believe 
that the term sabotage is commonly understood and that common 
understanding should suffice in most instances.\210\ Further, in the 
interim while the matter is being addressed by the Reliability 
Standards development process, we direct the ERO to provide advice to 
entities that have concerns about the reporting of particular 
circumstances as they arise.
---------------------------------------------------------------------------

    \209\ See NOPR at P 224.
    \210\ Id. at P 224, n.140, quoting a dictionary definition of 
``sabotage'' as ``destruction of property or obstruction of normal 
operations, as by civilians or enemy agents. * * *''
---------------------------------------------------------------------------

    463. Further, in defining sabotage, the ERO should consider 
FirstEnergy's suggestions to differentiate between cyber and physical 
sabotage and develop a threshold of materiality. However, regarding the 
latter suggestion, the Commission directs that guidance for a threshold 
of materiality must be designed carefully to mitigate the risk that an 
unsuccessful sabotage event is not correctly reported because it did 
not cause sufficient harm.
iii. Procedures for Recognizing Sabotage Events
    464. Requirement R1 of CIP-001-1 provides that an applicable entity 
must have procedures ``for the recognition of and for making their 
operational personnel aware of sabotage events on its facilities and 
multi-site sabotage affecting larger portions of the Interconnection.'' 
The NOPR expressed concern that the provision does not establish 
baseline requirements regarding what issues should be addressed by the 
developed procedures. APPA goes even further and, characterizing it as 
an entity specific fill-in-the-blank standard, contends that it lacks 
sufficient detail upon which the ERO can base compliance and 
enforcement efforts.
    465. While the Commission believes that this Reliability Standard 
can and should be enhanced by specifying baseline requirements 
regarding what issues should be addressed in the procedures for 
recognizing sabotage events and making personnel aware of such events, 
it disagrees with APPA that Requirement R1 lacks sufficient detail on 
which to base ERO compliance and enforcement efforts. As indicated in 
Measure M1, an applicable entity must have and maintain the procedure 
as defined by Requirement R1. Thus, if an applicable entity cannot 
provide the required procedure to the ERO or a Regional Entity auditor 
upon request, it would likely be subject to an enforcement action. 
While we expect that an applicable entity that has made a good faith 
effort to develop a meaningful procedure to comply with Requirement R1 
(and Measure M1) would not be subject to an enforcement action, an ERO 
or Regional Entity audit team may provide steps to improve the 
individual entity's procedure, which would serve as a baseline for that 
entity for any subsequent audit. Such an approach would be acceptable 
and allow for meaningful compliance in the interim until CIP-001-1 is 
modified pursuant to our directive.
iv. Periodic Review of Sabotage Reporting Plans
    466. The Commission was concerned that CIP-001-1 did not include a 
requirement for the periodic review or updating of sabotage reporting 
plans or procedures, or for the periodic testing of the sabotage 
reporting procedures to verify that they achieve the desired 
result.\211\ In response, FirstEnergy suggests that a bi-annual review 
would be appropriate and MRO believes that an annual review requirement 
should be added to the Reliability Standard. Periodic testing of the 
procedures through an exercise would assist in determining if the 
procedures are adequate for achieving the desired result. Lessons 
learned from these events would help in developing or modifying the 
sabotage reporting procedures.
---------------------------------------------------------------------------

    \211\ NOPR at P 228.
---------------------------------------------------------------------------

    467. The Commission affirms the NOPR directive and directs the ERO 
to incorporate a periodic review or updating of the sabotage reporting 
procedures and for the periodic testing of the sabotage reporting 
procedures. At this time, the Commission does not specify a review 
period as suggested by FirstEnergy and MRO and, rather, believes that 
the appropriate period should be determined through the ERO's 
Reliability Standards development process. However, the Commission 
directs that the ERO begin this process by considering a staggered 
schedule of annual testing of the procedures with modifications made 
when warranted formal review of the procedures every two or three 
years.
v. Mandatory Reporting of a Sabotage Event
    468. CIP-001-1, Requirement R4, requires that each applicable 
entity establish communications contacts, as applicable, with the local 
FBI or Royal Canadian Mounted Police officials and develop reporting 
procedures as appropriate to its circumstances. The Commission in the 
NOPR expressed concern that the Reliability Standard does not require 
an applicable entity to actually contact the appropriate governmental 
or regulatory body in the event of sabotage. Therefore, the Commission 
proposed that NERC modify the Reliability Standard to require an 
applicable entity to ``contact appropriate federal authorities, such as 
the Department of Homeland Security, in the event of sabotage within a 
specified period of time.'' \212\
---------------------------------------------------------------------------

    \212\ Id. at P 231.
---------------------------------------------------------------------------

    469. As mentioned above, NERC and others object to the wording of 
the proposed directive as overly prescriptive and note that the 
reference to ``appropriate federal authorities'' fails to recognize the 
international application of the Reliability Standard. The example of 
the Department of Homeland Security as an ``appropriate federal 
authority'' was not intended to be an exclusive designation. 
Nonetheless, the Commission agrees that a reference to ``federal 
authorities''

[[Page 16466]]

could create confusion. Accordingly, we modify the direction in the 
NOPR and now direct the ERO to address our underlying concern regarding 
mandatory reporting of a sabotage event. The ERO's Reliability 
Standards development process should develop the language to implement 
this directive.
    470. As noted above, FirstEnergy, EEI and others express concern 
regarding the potential for redundant reporting under CIP-001-1 and 
other government reporting standards, and the need for greater 
coordination. The Commission understands the concern about multiple 
reporting channels that may arise and the burden that this may present 
to applicable entities. We direct the ERO to explore ways to address 
these concerns--including central coordination of sabotage reports and 
a uniform reporting format--in developing modifications to the 
Reliability Standard with the appropriate governmental agencies that 
have levied the reporting requirements.
    471. The Commission stated that the reporting of a sabotage event 
should occur within a fixed period of time, and referred to a Homeland 
Security procedure that references a 60-minute period for submitting a 
preliminary report and a follow-up report within four to six 
hours.\213\ While commenters raise a number of concerns about the need 
for fairness in the implementation of such a requirement, they do not 
challenge the NOPR's underlying concern or the appropriateness of such 
a provision. The Commission believes that an applicable entity should 
report a sabotage event in a timely manner to allow government 
authorities and critical infrastructure members the opportunity to 
react in a meaningful manner to such information. Thus, the Commission 
directs the ERO to modify CIP-001-1 to require an applicable entity to 
contact appropriate governmental authorities in the event of sabotage 
within a specified period of time, even if it is a preliminary report. 
The ERO, through its Reliability Standards development process, is 
directed to determine the proper reporting period. In doing so, the ERO 
should consider suggestions raised by commenters such as FirstEnergy 
and Xcel to define the specified period for reporting an incident 
beginning from when an event is discovered or suspected to be sabotage, 
and APPA's concerns regarding events at unstaffed or remote facilities, 
and triggering events occurring outside staffed hours at small 
entities.
---------------------------------------------------------------------------

    \213\ Id. at n.142.
---------------------------------------------------------------------------

c. Summary of Commission Determinations
    472. As explained in the NOPR, while the Commission has identified 
concerns regarding CIP-001-1, we believe that the proposal serves an 
important purpose in ensuring that operating entities properly respond 
to sabotage events to minimize the adverse impact on the Bulk-Power 
System. Accordingly, the Commission approves Reliability Standard CIP-
001-1 as mandatory and enforceable. In addition, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop the following modifications to 
the Reliability Standard through the Reliability Standards development 
process: (1) Further define sabotage and provide guidance as to the 
triggering events that would cause an entity to report a sabotage 
event; (2) specify baseline requirements regarding what issues should 
be addressed in the procedures for recognizing sabotage events and 
making personnel aware of such events; (3) incorporate a periodic 
review or updating of the sabotage reporting procedures and for the 
periodic testing of the sabotage reporting procedures and (4) require 
an applicable entity to contact appropriate governmental authorities in 
the event of sabotage within a specified period of time. In addition, 
we direct the ERO, as part of its Work Plan, to consider revisions to 
CIP-001-1 that address our concerns regarding applicability to smaller 
entities. The ERO should also consider consolidation of the sabotage 
reporting forms and the sabotage reporting channels with the 
appropriate governmental authorities to minimize the impact of these 
reporting requirements on all entities.
3. COM: Communications
    473. The Communications (COM) group contains two Reliability 
Standards. The first requires that transmission operators, balancing 
authorities and other applicable entities have adequate internal and 
external telecommunications facilities for the exchange of 
interconnection and operating information necessary to maintain 
reliability. The second Reliability Standard requires that these 
communication facilities be staffed and available to address real-time 
emergencies and that operating personnel carry out effective 
communications.
    474. The NOPR contained a discussion of how the transmission 
operator and generator operator function would apply to RTO, ISO and 
pooled resource organizations. In this Final Rule, conclusions 
concerning those issues are covered in the Applicability Issues 
section.\214\ In essence, an organization may, but does not have to, 
accept compliance responsibility on behalf of its members. Since 
telecommunication is vital to the Reliable Operation of the Bulk-Power 
System, the Commission finds that it is not permissible to have either 
unnecessary overlaps or gaps in telecommunications.
---------------------------------------------------------------------------

    \214\ See Applicability Issues: Use of the NERC Functional 
Model, supra section II.C.4.
---------------------------------------------------------------------------

a. Telecommunications (COM-001-1)
    475. COM-001-0 \215\ seeks to ensure coordinated telecommunications 
among operating entities, which are fundamental to maintaining grid 
reliability. This proposed Reliability Standard establishes general 
telecommunications requirements for specific operating entities, 
including equipment testing and coordination. It also establishes 
English as the common language between and among operating personnel, 
and sets policy for using the NERCNet telecommunications system. COM-
001-0 applies to transmission operators, balancing authorities, 
reliability coordinators and NERCNet user organizations.
---------------------------------------------------------------------------

    \215\ In its November 15, 2006, filing, NERC submitted COM-001-
1, which supercedes the Version 0 Reliability Standard. COM-001-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, COM-001-1.
---------------------------------------------------------------------------

    476. The Commission proposed to approve Reliability Standard COM-
001-0 as mandatory and enforceable. In addition, the Commission 
proposed to direct that NERC submit a modification to COM-001-0 that: 
(1) Includes Measures and Levels of Non-Compliance; (2) includes 
generator operators and distribution providers as applicable entities 
and (3) includes Requirements for communication facilities for use 
during emergency situations.
    477. In addition, the Commission sought comments on specific 
requirements or performance criteria for telecommunications facilities, 
noting that COM-001-0 might be improved by providing specific 
requirements for adequacy, redundancy, diverse routing, and periodic 
testing. The Commission also sought comments on whether the relative 
roles of applicable entities should be considered when setting down 
requirements for telecommunication facilities, since the needs will 
vary based on role.

[[Page 16467]]

    478. Most comments address the specific modifications and concerns 
raised by the Commission in the NOPR. Below, we address each topic 
separately, followed by a summary of our conclusions.
i. Applicability to Generator Operators and Distribution Providers and 
their Telecommunications Facility Requirements
    479. The Commission stated in the NOPR that communications with 
generator operators and distribution providers are necessary to 
maintain system reliability during normal and emergency situations, 
while recognizing that telecommunication facility needs will vary 
between these two entities and other reliability entities such as 
reliability coordinators, transmission operators and balancing 
authorities. The Requirements for each of these entities will vary 
according to its respective roles.
(a) Comments
    480. EEI supports the goals stated by the Commission with regard to 
COM-001-1, in particular, the need to apply this Reliability Standard 
to distribution providers. TVA agrees with the Commission's reasoning 
that generator operators and distribution providers should be subject 
to this Reliability Standard, but seeks clarification that such 
entities may transfer their responsibility for data sharing with and 
reporting to NERC and Regional Entities by contract to another entity.
    481. In contrast, MRO, APPA, TAPS and SDG&E indicate that applying 
this Reliability Standard to generator operators and distribution 
providers may not be appropriate. APPA argues generator operators and 
distribution providers do not affect the Bulk-Power System in the same 
manner as a reliability coordinator, balancing authority or 
transmission provider does, since generator operators and distribution 
providers only have a secondary or support role with respect to 
reliability of the Bulk-Power System.
    482. Further, APPA and SDG&E are concerned that the Commission's 
proposal would unnecessarily subject generator operators and 
distribution providers to Requirements that were designed for 
transmission operators. For example, APPA indicates that NERCNet was 
designed as part of the NERC Interregional Security Network for 
communications among reliability coordinators, balancing authorities 
and transmission operators, and was not designed to connect generators 
to their balancing authorities and distribution providers to their 
transmission operators. Further, SDG&E submits that, while generator 
operators and distribution providers may logically have some role in 
enabling communications that help ensure reliability, SDG&E sees no 
basis for subjecting such entities to the same, extensive requirements 
incumbent on transmission operators.
    483. APPA argues that, while telecommunications Reliability 
Standards with generator operators and distribution providers as 
applicable entities may be needed, they are already subject to 
telecommunications requirements as part of their bilateral 
interconnection agreements with balancing authorities and transmission 
providers. It contends that if NERC deems it necessary, a separate 
Reliability Standard should be developed to govern telecommunications 
between balancing authorities and generator operators, and between 
transmission operators and distribution providers under their 
respective footprints.
    484. TAPS states that Requirement R1.4 has an ambiguous requirement 
\216\ that, if applied to distribution providers and generator 
operators, would impose redundancy requirements well beyond what is 
reasonably necessary for Bulk-Power System reliability. Further it 
asserts that the NOPR provides no basis for expanding the Reliability 
Standard to small entities, such as a 2-MW distribution provider or 
generator, much less than one that has no connection to the bulk 
transmission system. Finally, TAPS contends that, in making this 
proposal, the Commission is ``over-stepping its bounds'' by not leaving 
it to the ERO's expert judgment whether COM-001-1 has sufficient 
coverage to protect Bulk-Power System reliability and states that, in 
any event, applicability should be limited through NERC's registry 
criteria and definition of bulk electric system.
---------------------------------------------------------------------------

    \216\ COM-001-1 Requirement R1.4 states: ``Where applicable, 
these [telecommunications] facilities shall be redundant and 
diversely routed.''
---------------------------------------------------------------------------

    485. MRO further states that applying this Reliability Standard to 
generator operators and distribution providers and including 
Requirements for communication facilities for use during emergency 
situations may also not be appropriate if the distribution provider 
does not operate its own systems.
    486. California PUC believes that the Commission's assertion of 
authority to impose Reliability Standards applicable to either 
generator operators or distribution providers should be extremely 
limited, and should be based on an essential nexus between the proposed 
Reliability Standard and the operation of the Bulk-Power System. It 
contends that this aspect of the Commission's proposed directive is 
duplicative and unnecessary when applied to entities in California, and 
risks being counterproductive unless applied with considerable 
restraint since California PUC's Operation Standards require power 
plants to maintain the ability to communicate with the balancing 
authority at all times, and to plan for the continuity of 
communications during emergencies.
    487. Process Electricity Committee agrees that the extent and 
maintenance of telecommunication facilities should vary based on the 
operator's potential affect on system reliability. It points out that 
existing regulations and contractual obligations already require end 
users to maintain adequate communications facilities. Further, it 
states that on-site generation interconnected with the electricity grid 
typically is required to maintain sufficient telecommunications 
facilities between the generator owner or operator and the grid 
operator. In the absence of evidence that this arrangement is 
inadequate, Process Electricity Committee recommends that the amended 
COM Reliability Standards be clarified so that they do not impose new 
requirements on end users and other entities that have only minimal 
impact on the reliability of the interconnected transmission network.
(b) Commission Determination
    488. The Commission reaffirms its position that generator operators 
and distribution providers should be included as applicable entities in 
COM-001-1 to ensure there is no reliability gap during normal and 
emergency operations. For example, during a blackstart when normal 
communications may be disrupted, it is essential that the transmission 
operator, balancing authority and reliability coordinator maintain 
communications with their distribution providers and generator 
operators. However, the current version of Reliability Standard COM-
001-1 does not require this because it does not include generator 
operators and distribution providers as applicable entities. We clarify 
that the NOPR did not propose to require redundancy on generator 
operators' or distribution providers' telecommunication facilities or 
that generator operators or distribution providers be trained on 
anything not related to their functions during normal and emergency 
conditions. We expect the telecommunication requirements for all 
applicable entities will vary according to their roles and that these

[[Page 16468]]

requirements will be developed under the Reliability Standards 
development process.
    489. As stated in the Applicability Issues section of this Final 
Rule, entities may share responsibility for complying with Reliability 
Standards and the ERO's registration process takes this into 
account.\217\ We believe that this satisfies TVA's concern about data 
sharing and reporting responsibilities and MRO's concern about applying 
this Reliability Standard to distribution providers only if they 
operate their own systems.
---------------------------------------------------------------------------

    \217\ See Applicability Issues: Applicability to Small Entities, 
supra section II.C.2.
---------------------------------------------------------------------------

    490. The Commission agrees with APPA that the primary purpose of 
Requirement R6 is to provide information to ensure reliable 
interregional operations and therefore should not apply to generator 
operators and distribution providers. However, we disagree that this 
leads to the conclusion that generator operators and distribution 
providers should not be included in COM-001-1. As we have stated, 
telecommunication requirements for all applicable entities will vary 
according to their roles. In modifying COM-001-1 through the 
Reliability Standards development process, the Commission believes that 
the ERO should create appropriate telecommunications requirements for 
generator operators and distribution providers, which may be additional 
and separate Requirements to COM-001-1 or, alternatively, a new 
Reliability Standard as suggested by APPA.
    491. In response to SDG&E, the Commission's intent is not to 
subject generator operators and distribution providers to the same 
requirements placed on transmission operators. As part of the 
modification of this Reliability Standard or development of a new 
Reliability Standard to include the appropriate telecommunications 
facility requirements for generator operators and distribution 
providers, the ERO should take into account what would be required of 
generator operators and distribution providers in terms of 
telecommunications for the Reliable Operation of the Bulk-Power System, 
instead of applying the same requirements as are placed on other 
reliability entities such as reliability coordinators, balancing 
authorities and transmission operators.
    492. With regard to TAPS's comment, the Commission has identified a 
concern and directs that the ERO address the matter through its 
Reliability Standards development process. This comports with section 
215(d)(5) of the FPA which authorizes the Commission, upon its own 
motion, to order the ERO ``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.'' 
We have identified such a matter and have left to the ERO to develop a 
specific proposal by invoking its Reliability Standards development 
process. Further, consistent with our discussion above regarding 
applicability of Reliability Standards, applicability would be limited 
through NERC's registry criteria and definition of bulk electric system 
at this time.
    493. In response to California PUC, in this Final Rule we are 
initially limiting the applicability of these Reliability Standards to 
those users, owners and operators of the Bulk-Power System on the ERO's 
compliance registry. The Commission notes that it has jurisdiction 
under section 215 of the FPA over all users, owners and operators of 
the Bulk-Power System to ensure Reliable Operation of the Bulk-Power 
System. To ensure reliability, it is important to include appropriate 
generator operators and distribution providers as applicable entities 
in Reliability Standard COM-001-1. However, any generator operator or 
distribution provider that is not a user, owner or operator of the 
Bulk-Power System will not be included. Also, at this time, the Bulk-
Power System is defined on the basis of the ERO's definition of the 
``bulk electric system.'' The Commission believes that this should 
satisfy California PUC's concern that this Reliability Standard be 
limited to Bulk-Power System operations. We will not further limit our 
directive as to which entities this Reliability Standard should apply.
    494. As we explained in the NOPR, communication with generator 
operators and distribution providers becomes especially important 
during an emergency when generators with black start capability must be 
placed in service and nearby loads restored as an initial step in 
system restoration. This occurs at a critical time when normal 
communication paths may be disrupted. While many generator operators 
and distribution providers may have telecommunications requirements 
pursuant to a bilateral contract as indicated by APPA, it is important 
that all generator operators and distribution providers identified by 
the ERO through its registration process are subject to uniform 
telecommunications requirements. Therefore, we adopt our proposal to 
require the ERO to modify COM-001-1 to apply to generator operators and 
distribution providers. However, we recognize that some of the existing 
requirements (such as Requirement R6 related to NERCNet) need not apply 
to generator operators and distribution providers. In light of 
commenters' concerns, as an alternative, it would be acceptable for the 
ERO to develop a new Reliability Standard that would specifically 
address an appropriate range of Requirements for telecommunication 
facilities of generator operators and distribution providers that 
reflect their respective roles on Reliable Operation of the Bulk-Power 
System.
ii. Requirements for Telecommunications Facilities
    495. The Commission sought comment on specific requirements or 
performance criteria for telecommunication facilities and whether the 
modified Reliability Standard should provide requirements that also 
consider the relative role of applicable entities.
(a) Comments
    496. A number of commenters agree with the Commission that the 
relative role of an entity should be taken into account when specifying 
the requirements for its telecommunications facilities.\218\ For 
example, ISO-NE states that a single generator operator will not need 
the level of redundancy and diverse routing that a reliability 
coordinator needs.
---------------------------------------------------------------------------

    \218\ See, e.g., EEI, International Transmission, ISO-NE, 
Process Electricity Committee and SoCal Edison.
---------------------------------------------------------------------------

    497. Many commenters recommend that telecommunications facilities 
requirements should be specified in broad terms. EEI, APPA, Alcoa, 
International Transmission, LPPC and SoCal Edison believe that revision 
to COM-001-1 should provide specific or minimum requirements for 
adequacy, redundancy and diverse routing. However, EEI, Alcoa and 
Northern Indiana maintain that entities should have flexibility in 
meeting the requirements and to allow for innovative technological 
advancements. Alcoa and Northern Indiana maintain that without 
flexibility, an applicable entity may choose a less optimal solution 
just to comply with the Reliability Standard. EEI asserts that such 
flexibility will also permit alternative means of implementing the 
requirements that will translate into cost savings. International 
Transmission

[[Page 16469]]

cautions that we should not prejudice the modification of this 
Reliability Standard by indicating the specific requirements or the 
performance criteria.
    498. APPA states that, because the communications requirements for 
an entity that is responsible for serving 3,000 MW of load is 
distinctly different from another entity that serves 30 MW of load, the 
ERO should take the size of the entity into consideration.
    499. NERC believes that the questions posed by the NOPR regarding 
performance criteria should be considered through the Reliability 
Standards development process, in accordance with NERC's Work Plan, 
which will allow a broader industry debate on the requirements for 
telecommunications facilities. This approach will avoid any potential 
conflicts with the requirements already established in the 
telecommunications industry and by the Institute of Electrical and 
Electronics Engineers.
    500. Entergy states that it is unclear what cyber assets are 
covered by COM-001-0. Entergy believes that the Reliability Standard 
should focus on telecommunications that support the operation of 
critical assets. Entergy also believes that COM-001-0 should be 
expanded to include advances in communications technology. It states 
that NERC should consider addressing the following in a way that will 
facilitate an understanding of the Reliability Standards' requirements: 
(1) Voice communications; (2) command and control data communications; 
(3) security coordination data communications; (4) digital messaging 
communications; (5) human linguistic convention and (6) other types of 
communications, including video conferencing and communications with 
remote security cameras. Entergy believes that this could be 
accomplished through an enhancement to the definition of communications 
in the NERC glossary and recasting COM-001-0 to improve the specificity 
of requirements for each form of communication. Finally, Entergy 
believes that Requirement R4 of COM-001-0, which requires reliability 
coordinators, transmission operators and balancing authorities to use 
English in all types of communications, should apply only to verbal and 
written communications.
    501. FirstEnergy asserts that the Requirement R2 is unclear because 
it does not specify whether the phrase ``telecommunication facilities'' 
covers both voice and data facilities in the context of alarms. It 
states that, although the word ``telecommunications facilities'' is 
generally understood to mean both voice and data facilities, the 
current practice is to display alarms only for data facilities. 
Requirement R2 could be misinterpreted to require alarms on voice 
facilities as well, which would be impractical.
    502. Six Cities is concerned that the scope of improper conduct 
under the ``NERCNet security policy'' in Attachment 1 is virtually 
limitless \219\ Six Cities recognizes that it would be difficult to 
provide a comprehensive and detailed list of all conduct that might be 
considered a misuse of NERCNet data, but that difficulty does not 
justify exposing NERCNet users to the risk of monetary penalties based 
on amorphous and unbounded descriptions of potentially violative 
conduct. Six Cities states that one solution would be to limit the 
imposition of monetary penalties for misuse of NERCNet data to 
instances where such misuse is intentional or grossly negligent. 
According to Six Cities, it would be appropriate to exact a monetary 
penalty where a NERCNet user deliberately uses NERCNet data for 
unauthorized or unreasonable purposes. Six Cities asks that it be 
modified to provide for a warning for the improper disclosure of 
NERCNet data where the disclosure was not intentional or grossly 
negligent.
---------------------------------------------------------------------------

    \219\ Attachment 1 provides that Violations of the NERCNet 
Security Policy shall include, but not be limited to any act that:
    Exposes NERC or any user of the NERCNet to actual or potential 
monetary loss through the compromise of data security or damage.
    Involves the disclosure of trade secrets, intellectual property, 
confidential information or the unauthorized use of data.
    Involves the use of data for illicit purposes, which may include 
violation of any law, regulation or reporting requirement of any law 
enforcement or government body.
---------------------------------------------------------------------------

(b) Commission Determination
    503. The Commission adopts its NOPR proposal that 
telecommunications facility requirements must reflect the roles of the 
respective operating or reliability entities that are included in the 
applicability section in this Reliability Standard and how they would 
affect the reliability of the Bulk-Power System. We note that most 
commenters agree with this approach.
    504. The Commission agrees with commenters that flexibility is 
important in setting telecommunications requirements in order to foster 
innovation, allow the adoption of new technologies and provide for 
cost-effective solutions for compliance with the Reliability Standard. 
However, the Commission finds that certain modifications to COM-001-1 
are necessary to ensure system reliability. We believe that the ERO 
must specify requirements for using telecommunications facilities 
during normal and emergency conditions that: (1) Reflect the roles of 
the applicable entities and their impact on Reliable Operation and (2) 
include adequate flexibility. Accordingly, the Commission directs the 
ERO to modify COM-001-1 through the Reliability Standards development 
process to address our concerns. The Commission believes that the 
concerns of Entergy and FirstEnergy are best addressed by the ERO in 
the Reliability Standards development process.
    505. Six Cities suggests specific new improvements to COM-001-1. As 
stated above, such comments should be addressed as the ERO modifies the 
Reliability Standards in the Reliability Standards development process.
iii. Measures and Levels of Non-Compliance
    506. In its November 15, 2006, filing, NERC submitted COM-001-1, 
which supersedes the Version 0 Reliability Standard. COM-001-1 adds 
Measures and Levels of Non-Compliance to the Version 0 Reliability 
Standard.
(a) Comments
    507. ISO-NE notes that Compliance 1.1 of COM-001-0 specifies that 
``Regional Reliability Organizations shall be responsible for 
compliance monitoring * * *.'' ISO-NE suggests that since NERC designed 
and created NERCNet, NERC should be responsible for maintaining and 
ensuring the compliance with the Reliability Standard rather than 
regional reliability organizations. ISO-NE recommends that the 
Commission direct NERC to modify Compliance 1.1 to provide that NERC 
shall be responsible for monitoring compliance of the NERCNet user 
organizations.
(b) Commission Determination
    508. With respect to ISO-NE's comment, we find that a regional 
reliability organization does not have any role with compliance 
matters; that role is reserved for the ERO or the Regional Entities. 
However, we disagree with ISO-NE that the ERO must replace the regional 
reliability organization as the compliance monitor. The fact that NERC 
designed and created NERCNet does not require the ERO to be the 
compliance monitor. Section 215 of the FPA states that the ERO may 
delegate compliance and enforcement authority to a Regional Entity, 
even if the ERO creates the Reliability Standards. Therefore, although 
we direct that the

[[Page 16470]]

regional reliability organization should not be the compliance monitor 
for NERCNet, we leave it to the ERO to determine whether it is the 
appropriate compliance monitor or if compliance should be monitored by 
the Regional Entities for NERCNet User Organizations.
iv. Summary of Commission Determination
    509. While the Commission has identified a number of concerns with 
regard to COM-001-1, this Reliability Standard is independently 
enforceable without the modifications we are directing. Therefore, the 
Commission approves Reliability Standard COM-001-1 as mandatory and 
enforceable. Because of the importance of this Reliability Standard in 
requiring transmission operators and others to have necessary 
telecommunications equipment, we additionally, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, direct the 
ERO to develop a modification to COM-001-1 through the Reliability 
Standards development process that: (1) Expands the applicability to 
include generator operators and distribution providers and includes 
Requirements for their telecommunications facilities; (2) identifies 
specific requirements for telecommunications facilities for use in 
normal and emergency conditions that reflect the roles of the 
applicable entities and their impact on Reliable Operation and (3) 
includes adequate flexibility for compliance with the Reliability 
Standard, adoption of new technologies and cost-effective solutions. As 
an alternative to applying this Reliability Standard to generator 
operators and distribution providers, the ERO may develop a new 
Reliability Standard that will address the Requirements for 
telecommunication facilities applicable to generator operators and 
distribution providers.
b. Communications and Coordination (COM-002-2)
    510. COM-002-2 \220\ seeks to ensure that transmission operators, 
generator operators and balancing authorities have adequate 
communications and that their communications capabilities are staffed 
and available to address real-time emergency conditions. This 
Reliability Standard requires balancing authorities and transmission 
operators to notify others through pre-determined communication paths 
of any condition that could threaten the reliability of their areas or 
when firm load shedding is anticipated.
---------------------------------------------------------------------------

    \220\ In its November 15, 2006, filing, NERC submitted COM-002-
2, which supercedes the Version 1 Reliability Standard. COM-002-2 
adds Measures and Levels of Non-Compliance to the Version 1 
Reliability Standard. In this Final Rule, we review the November 
version, COM-002-2.
---------------------------------------------------------------------------

    511. The Commission proposed in the NOPR to approve Reliability 
Standard COM-002-1 as mandatory and enforceable. In addition, the 
Commission proposed to direct that NERC submit a modification to COM-
002-1 that: (1) Includes Measures and Levels of Non-Compliance; (2) 
includes a Requirement for the reliability coordinator to assess and 
approve actions that have impacts beyond the area views of transmission 
operators or balancing authorities; (3) includes distribution providers 
as applicable entities and (4) requires tightened communications 
protocols, especially for communications during alerts and emergencies. 
With respect to this final issue, the Commission proposed alternatively 
to direct NERC to develop a new Reliability Standard that responds to 
Blackout Report Recommendation No. 26, which deals with the need for 
tightened communications protocols.
i. Applicability to Distribution Providers
(a) Comments
    512. While EEI states that there is a clear need to apply the 
Reliability Standard to distribution providers, APPA finds the proposal 
problematic because it would mean that close to 2,000 public power 
systems would have to be added to the compliance registry. APPA argues 
that the Commission should instruct NERC to consider the applicability 
of COM-002-2 to distribution providers through its Reliability 
Standards development process. MRO requests that the Commission clarify 
whether the distribution providers will continue to operate their own 
systems in the future.
(b) Commission Determination
    513. The Commission finds that, during both normal and emergency 
operations, it is essential that the transmission operator, balancing 
authority and reliability coordinator have communications with 
distribution providers. In response to APPA, as discussed above, any 
distribution provider that is not a user, owner or operator of the 
Bulk-Power System would not be required to comply with COM-002-2, even 
though the Commission is requiring the ERO to modify the Reliability 
Standard to include distribution providers as applicable entities. 
APPA's concern that 2,000 public power systems would have to be added 
to the compliance registry is misplaced, since, as we explain in our 
Applicability discussion above, we are approving NERC's registry 
process, including the registry criteria. Therefore, we adopt our 
proposal to require the ERO to modify COM-002-2 to apply to 
distribution providers through its Reliability Standards development 
process.
    514. The Commission believes that this Reliability Standard does 
not alter who would operate a distribution provider's system. It only 
concerns communications, not the operation of the distribution system.
ii. Measures and Levels of Non-Compliance
(a) Comments
    515. APPA notes that the Levels of Non-Compliance for COM-002-2 are 
inadequate in two respects: (1) reliability coordinators are not 
included in any Level of Non-Compliance and (2) the Levels of Non-
Compliance for transmission operators and balancing authorities in 
Compliance D.2 do not reference Requirements R1 and R2. Therefore, APPA 
would support approval of COM-002-2 as a mandatory Reliability 
Standard, but would not support levying penalties for violating 
incomplete portions of the Reliability Standard.
(b) Commission Determination
    516. As stated in the Common Issues section, a Reliability Standard 
is enforceable even if it does not contain Levels of Non-
Compliance.\221\ However, the Commission agrees with APPA that this 
Reliability Standard could be improved by incorporating the changes 
proposed by APPA. Therefore, when reviewing the Reliability Standard 
through the Reliability Standards development process, the ERO should 
consider APPA's concerns.
---------------------------------------------------------------------------

    \221\ See Common Issues Pertaining to Reliability Standards: 
Measures and Levels of Non-Compliance, supra section II.E.2.
---------------------------------------------------------------------------

iii. Reliability Coordinator Assessment and Approval of Actions that 
have Impacts Beyond the Area Views of Transmission Operators and 
Balancing Authorities
(a) Comments
    517. Alcoa argues that there is a need for communication regarding 
operating actions taken by transmission operators and balancing 
authorities that may have impacts beyond their area views. However, a 
number of commenters oppose the Commission's proposal to modify the 
Reliability Standard to require reliability coordinators to assess and 
approve actions that have impacts

[[Page 16471]]

beyond the area views of transmission operators or balancing 
authorities and seek clarifications.\222\ Alcoa, California PUC, SDG&E 
and Xcel are concerned that obtaining approval from reliability 
coordinators could create delays in completing the operating action in 
emergency situations. Xcel and Alcoa request that the Commission 
clarify that this requirement would not prevent timely performance by a 
transmission operator of actions necessary to maintain the reliability 
of its system under emergency conditions.\223\ Both Alcoa and Xcel are 
concerned that waiting for an assessment and approval by a reliability 
coordinator may not be feasible, especially during emergencies. Xcel 
further asks the Commission to clarify that the entity taking operating 
actions should not be held responsible for delays caused by the 
reliability coordinator's assessment and approval. Alcoa suggests that 
there should be a clear definition of what actions have an impact 
beyond the area views of transmission operators or balancing 
authorities. SDG&E further states that serious damage to transmission 
equipment could occur if the transmission operator is not able to take 
immediate action during an emergency.
---------------------------------------------------------------------------

    \222\ See, e.g., APPA, EEI, California PUC, ISO-NE and SDG&E.
    \223\ Alcoa notes that this is consistent with the Requirements 
in TOP-001-1, which provides transmission operators and balancing 
authorities wide latitude to preserve reliability of their area.
---------------------------------------------------------------------------

    518. ISO-NE is concerned that the Commission proposal goes too far 
and if implemented, will prevent capable transmission operators from 
quickly addressing reliability problems that may arise. It maintains 
that transmission operators usually do not have enough time to inform 
the reliability coordinator, who must then ``assess and approve'' the 
proposed action. If the Commission's proposal is implemented, 
transmission operators will doubt themselves and delay necessary 
action. However, it does not see any problem for the New England 
balancing area and the NPCC region, because ISO-NE serves as the New 
England reliability coordinator, balancing authority and transmission 
operator.
    519. APPA contends that the Commission's proposed directive appears 
to have been covered under Reliability Standard IRO-005-1. EEI agrees, 
stating that IRO-005-1 already requires a reliability coordinator to 
ensure that transmission operators and balancing authorities operate to 
prevent action or non-action that will impact neighboring areas.\224\
---------------------------------------------------------------------------

    \224\ The Requirement R13 of IRO-005-1 provides that ``[e]ach 
reliability coordinator shall ensure that Transmission Operators, 
Balancing Authorities * * * operate to prevent the likelihood that a 
disturbance, action or non-action in its Reliability Coordinator 
Area will result in a SOL or IROL violation in another area of the 
Interconnection.''
---------------------------------------------------------------------------

(b) Commission Determination
    520. The Commission reaffirms its belief that Reliable Operation of 
the Bulk-Power System can only be achieved by coordinated efforts of 
all operating entities, such as reliability coordinators, transmission 
operators and balancing authorities in operating their respective 
systems and performing their respective functions in accordance with 
their responsibilities and authorities. Most operating actions taken by 
transmission operators and balancing authorities in real-time would 
only affect their own areas and equipment and have no adverse impacts 
on the interconnection reliability operating limits, and therefore they 
have unilateral authority to act. However some operating actions that 
would have impacts beyond their own areas must involve the reliability 
coordinator who has the wide-area views and the necessary operating 
tools, including monitoring facilities and real-time analytic tools 
with wide-area representation to enable the reliability coordinator to 
fulfill its responsibility.\225\ In response to Alcoa, the Commission 
believes that actions that have an impact beyond an area will, in 
general, vary based on the conditions at the time of the action.
---------------------------------------------------------------------------

    \225\ The NERC glossary states that A reliability coordinator is 
the ``entity that is the highest level of authority who is 
responsible for the reliable operation of the bulk electric system, 
has the wide-area view of the bulk electric system, and has the 
operating tools, processes and procedures, including the authority 
to prevent or mitigate emergency operating situations in both next-
day analysis and real-time operations. The reliability coordinator 
has the purview that is broad enough to enable the calculation of 
IROLs, which may be based on the operating parameters of 
transmission systems beyond any transmission operator's vision.'' 
NERC Glossary at 15.
---------------------------------------------------------------------------

    521. Further, we clarify that we did not propose to require an 
entity to inform its reliability coordinator of every action it takes. 
Instead, the proposed directive included a Requirement for the 
reliability coordinator to assess and approve only those actions that 
have impacts beyond the area views of transmission operators and 
balancing authorities. We remain convinced that it is the reliability 
coordinator's responsibility to ensure Reliable Operation of its 
reliability coordinator area. The reliability coordinator must also 
ensure that actions taken by operating entities under its authority 
will not have wide-area impacts that would adversely impact Reliable 
Operation of the Bulk-Power System. Therefore, we adopt the proposed 
directive as stated in the NOPR.
    522. In response to commenters, the Commission clarifies that the 
proposed directive does not conflict with the transmission operators' 
and balancing authorities' rights to take actions necessary to preserve 
reliability of their areas and alleviate operating emergencies, 
consistent with Requirement R1 and R2 in TOP-001-1.\226\ Further, the 
proposed directive does not in any way diminish their operating 
authority regarding local area reliability for normal and emergency 
situations, a responsibility that is under the responsibility of a 
transmission operator or a balancing authority. However, the majority 
of their operating actions are not emergency actions and would only 
affect a transmission operator's or balancing authority's area of 
responsibilities. Since these actions are expected to have little 
impact outside of the transmission operator's or balancing authority's 
area, the authority to take unilateral actions remains with the 
transmission operator or balancing authority. Other non-emergency 
actions should be coordinated with the reliability coordinator prior to 
taking action.
---------------------------------------------------------------------------

    \226\ TOP-001-1, R1 states in part ``Each transmission operator 
shall have the responsibility and clear decision-making authority to 
take whatever actions are needed to ensure the reliability of its 
area * * * '' and R2 states in part ``Each transmission operator 
shall take immediate actions to alleviate operating emergencies * * 
*.''
---------------------------------------------------------------------------

    523. Regarding SDG&E's concern that serious damage to transmission 
equipment could occur if the transmission operator is not able to take 
immediate action during an emergency, we believe this is adequately 
addressed under Requirement R3 of TOP-001-0 which provides that 
operating entities need not comply with directives from reliability 
coordinators when such actions would violate safety, equipment, 
regulatory or statutory requirements.
    524. NERC should consider Xcel's suggestion that the entity taking 
operating actions should not be held responsible for delays caused by 
the reliability coordinator's assessment and approval in the 
Reliability Standards development process. We note that the operating 
entity has the authority to take emergency actions to protect its 
system that may circumvent or preempt the reliability coordinator's 
approval process under TOP-001-1 Requirement R3 in cases of personnel 
safety, potential equipment failure or environmental needs.
    525. We disagree with commenters that the Commission's proposed

[[Page 16472]]

directive is already covered under Requirement R13 of IRO-005-1, which 
requires each reliability coordinator to ensure that all transmission 
operators, balancing authorities and others operate to prevent the 
likelihood that a disturbance, action, or non-action in its reliability 
coordinator area will result in a SOL and IROL violation in another 
area of the Interconnection. In order for the reliability coordinator 
to carry out its function under IRO-005-1, it must have information 
from the transmission operators and balancing authorities. However, 
IRO-005-1 does not require transmission operators and balancing 
authorities to provide the reliability coordinator with the information 
it would need to prevent the likelihood that an action from these two 
entities will result in a SOL or IROL violation in another area of the 
Interconnection. The Commission's directive ensures that the 
reliability coordinator has such information. Therefore, we do not 
believe that COM-002-2 is duplicative of IRO-005-1.
    526. Accordingly, we direct the ERO to include a Requirement for 
the reliability coordinator to assess and approve actions that have 
impacts beyond the area views of transmission operators or balancing 
authorities, including how to determine whether an action needs to be 
assessed by the reliability coordinator. This Requirement is best 
developed under the Reliability Standards development process including 
the consideration whether this Requirement should be included in this 
communications Reliability Standard or an operating Reliability 
Standard.
iv. Tightened Communications Protocols
    527. The Blackout Report cited ineffective communications as a 
factor common to the August 14, 2003 blackout and other previous major 
outages in North America.\227\ In addition, Recommendation No. 26 of 
the Blackout Report instructed NERC, working with reliability 
coordinators and control area operators, to ``[t]ighten communications 
protocols, especially for communications during alerts and emergencies 
* * * ''.\228\ In the NOPR, the Commission endorsed Blackout 
Recommendation No. 26 and proposed to direct the ERO to require 
tightened communications protocols, especially for communications 
during alerts and emergencies. Alternatively, we proposed to direct the 
ERO to develop a new Reliability Standard that responds to the Blackout 
Report Recommendation.
---------------------------------------------------------------------------

    \227\ Blackout Report at 107.
    \228\ Id. at 141.
---------------------------------------------------------------------------

(a) Comments
    528. In its response to the Staff Preliminary Assessment, NERC 
agreed with the need to develop additional Reliability Standards 
addressing consistent communications protocols among personnel 
responsible for the reliability of the Bulk-Power System.\229\
---------------------------------------------------------------------------

    \229\ NOPR at P 255.
---------------------------------------------------------------------------

    529. EEI supports the Commission in its concerns regarding Blackout 
Recommendation No. 26 on emergency communications. However, EEI states 
that Requirement R4 of EOP-001-0, Emergency Operations Planning, 
addresses the Commission's concerns about communication protocols 
during emergency conditions.\230\ EEI recommends that, instead of 
duplicating the same requirement in COM-002-2, the Commission should 
consider directing NERC to provide an interpretation on the elements of 
such protocols.
---------------------------------------------------------------------------

    \230\ EOP-001-0, Requirement R4 provides, in relevant part, 
that: ``[e]ach Transmission Operator and Balancing Authority shall 
have emergency plans that will enable it to mitigate operating 
emergencies. At a minimum, Transmission Operator and Balancing 
Authority emergency plan shall include [c]ommunication protocols to 
be used during emergencies.''
---------------------------------------------------------------------------

    530. APPA believes that the communications protocols to be used 
during emergencies should be included in the relevant Reliability 
Standard that governs each type of emergency, rather than in COM-002-2. 
For example, Requirement R3 of Reliability Standard VAR-002-1 
establishes the protocol for communication with the transmission 
operator if a generator loses its ability to provide voltage control. 
By keeping the necessary communication protocols clustered with the 
events to which they apply, NERC would make the Reliability Standards 
more user-friendly.
    531. MISO claims that Blackout Report Recommendation No. 26 on 
tightened communications protocols dealt primarily with NERC 
infrastructure and has been fully implemented. It is concerned that 
developing measures that require ongoing administration will impede 
rather than improve timely communications in an emergency.
(b) Commission Determination
    532. We adopt our proposal to require the ERO to establish 
tightened communication protocols, especially for communications during 
alerts and emergencies, either as part of COM-002-2 or as a new 
Reliability Standard. We note that the ERO's response to the Staff 
Preliminary Assessment supports the need to develop additional 
Reliability Standards addressing consistent communications protocols 
among personnel responsible for the reliability of the Bulk-Power 
System.
    533. While we agree with EEI that EOP-001-0, Requirement R4.1 
requires communications protocols to be used during emergencies, we 
believe, and the ERO agrees, that the communications protocols need to 
be tightened to ensure Reliable Operation of the Bulk-Power System. We 
also believe an integral component in tightening the protocols is to 
establish communication uniformity as much as practical on a continent-
wide basis. This will eliminate possible ambiguities in communications 
during normal, alert and emergency conditions. This is important 
because the Bulk-Power System is so tightly interconnected that system 
impacts often cross several operating entities' areas.
    534. Regarding APPA's suggestion that it may be beneficial to 
include communication protocols in the relevant Reliability Standard 
that governs those types of emergencies, we direct that it be addressed 
in the Reliability Standards development process.
    535. In response to MISO's contention that Blackout Report 
Recommendation No. 26 has been fully implemented, we note that 
Recommendation No. 26 addressed two matters. We believe MISO is 
referring to the second part of the recommendation requiring NERC to 
``[u]pgrade communication system hardware where appropriate'' instead 
of tightening communications protocols. While we commend the ERO for 
taking appropriate action in upgrading its NERCNet, we remind the 
industry to continue their efforts in addressing the first part of 
Blackout Recommendation No. 26.
    536. Accordingly, we direct the ERO to either modify COM-002-2 or 
develop a new Reliability Standard that requires tightened 
communications protocols, especially for communications during alerts 
and emergencies.
v. Other Issues
(a) Comments
    537. Santa Clara requests clarification whether the phrase ``Such 
communications shall be staffed and available'' in Requirement R1 
applies only to operating staff available on site at all times or 
includes repair personnel who are available only on an on-call basis.
    538. FirstEnergy asks that the Reliability Standard specify what is

[[Page 16473]]

meant by ``staffed'' and states that the term should not require a 
physical presence at all facilities at all times because some units, 
such as peaking units, are not staffed 24 hours a day. In addition, 
FirstEnergy suggests that, because nuclear units are already subject to 
communications requirements in their operating procedures, their 
compliance with NRC operating procedures should be deemed in compliance 
with the NERC Reliability Standards.
    539. Similarly, Six Cities states that, to avoid unnecessary 
staffing burdens, particularly for smaller entities, the Commission 
should direct NERC to clarify COM-002-2 by providing that 
identification of an emergency contact person on call to respond to 
real-time emergency conditions will constitute adequate compliance.
(b) Commission Determination
    540. Santa Clara, FirstEnergy and Six Cities suggest specific new 
improvements to the Reliability Standards. As stated above, such 
comments should be considered as the ERO modifies the Reliability 
Standards in the Reliability Standards development process.
vi. Summary of Commission Determination
    541. While the Commission identified concerns regarding COM-002-2, 
the proposed Reliability Standard serves an important purpose by 
requiring users, owners and operators to implement the necessary 
communications and coordination among entities. Accordingly, the 
Commission approves Reliability Standard COM-002-2 as mandatory and 
enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to COM-002-2 through the Reliability Standards 
development process that: (1) Expands the applicability to include 
distribution providers as applicable entities; (2) includes a new 
Requirement for the reliability coordinator to assess and approve 
actions that have impacts beyond the area view of a transmission 
operator or balancing authority \231\ and (3) requires tightened 
communications protocols, especially for communications during alerts 
and emergencies. Alternatively, with respect to this final issue, the 
ERO may develop a new Reliability Standard that responds to Blackout 
Report Recommendation No. 26 in the manner described above. Finally, we 
direct the ERO to include APPA's suggestions to complete the Measures 
and Levels of Non-Compliance in its modification of COM-002-2 through 
the Reliability Standards development process.
---------------------------------------------------------------------------

    \231\ This Requirement could, for example, be included in COM-
002-2 or in an operating Reliability Standard.
---------------------------------------------------------------------------

4. EOP: Emergency Preparedness and Operations
    542. The Emergency Preparedness and Operations (EOP) group of 
proposed Reliability Standards consists of nine Reliability Standards 
that address preparation for emergencies, necessary actions during 
emergencies and system restoration and reporting following 
disturbances.
a. Emergency Operations Planning (EOP-001-0)
    543. NERC's proposed Reliability Standard EOP-001-0 requires each 
transmission operator and balancing authority to develop, maintain and 
implement a set of plans to mitigate operating emergencies. These plans 
must be coordinated with other transmission operators and balancing 
authorities and the reliability coordinator.
    544. In the NOPR, the Commission proposed to approve Reliability 
Standard EOP-001-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct that NERC submit a modification to 
EOP-001-0 that: (1) Includes the reliability coordinator as an 
applicable entity with responsibilities as described above; (2) 
clarifies the 30-minute requirement in Requirement R2 of the 
Reliability Standard to state that load shedding should be capable of 
being implemented as soon as possible and much less than 30 minutes and 
(3) includes definitions of system states to be used by the operators, 
such as transmission-related ``normal,'' ``alert,'' and ``emergency'' 
states, provides criteria for entering into these states and identifies 
the authority that will declare these states.
    545. Most of the comments address the specific modifications and 
concerns raised by the Commission in the NOPR. Below, we address each 
topic separately, followed by an over-all conclusion and summary.
i. Applicability to reliability coordinators
(a) Comments
    546. MRO states that it is necessary to include reliability 
coordinators as applicable entities because reliability coordinators 
have a wide-area view. FirstEnergy also supports making the proposed 
Reliability Standard applicable to the reliability coordinator. 
FirstEnergy states the reliability coordinator should take an active 
role and should have clearly defined, specific responsibilities for 
coordinating and implementing emergency operations plans. In addition, 
FirstEnergy states that inclusion of the reliability coordinator as an 
applicable entity removes ambiguity that may exist concerning the 
reliability coordinator's role and its responsibilities during 
restoration activities.
    547. SoCal Edison agrees that certain aspects of EOP-001-0 should 
be applicable to reliability coordinators; however, it proposes that 
NERC, through the stakeholder process, should receive input from 
stakeholders on which requirements should be exclusive to the 
transmission operator or balancing authority with the reliability 
coordinator responsible only for collecting and incorporating this 
information into its overarching plan. MISO, on the other hand, 
questions the need for the proposed modification, contending that the 
reliability coordinators have parallel responsibilities laid out in 
other EOP Reliability Standards.
(b) Commission Determination
    548. In the NOPR, we stated that the proposed Reliability Standard 
applies to transmission operators and balancing authorities, that the 
applicability portion of the Reliability Standard is sufficiently clear 
as to who must comply with the filed version of the Reliability 
Standard and that the Reliability Standard can be enforced against 
these entities.\232\ However, we recognized commenters' concerns that 
the Reliability Standard does not assign a role to the reliability 
coordinator, which is the highest level of authority responsible for 
reliable operation of the Bulk-Power System and which has a wide-area 
view. MISO contends that EOP-001-0 need not apply to reliability 
coordinators because they have parallel responsibilities in other EOP 
Reliability Standards. We disagree. Given the importance NERC 
attributes to the reliability coordinator in connection with matters 
covered by EOP-001-0, the Commission is persuaded that specific 
responsibilities for the reliability coordinator in the development and 
coordination of emergency plans must be included as part of this 
Reliability Standard. While balancing authorities and transmission 
operators are capable of developing, maintaining and implementing plans 
to mitigate

[[Page 16474]]

operating emergencies for their specific areas of responsibility, 
unlike reliability coordinators, they do not have wide-area views.
---------------------------------------------------------------------------

    \232\ NOPR at P 272.
---------------------------------------------------------------------------

    549. Further we agree with SoCal Edison that clear direction is 
needed on which requirements should be exclusive to transmission 
operators and balancing authorities with the reliability coordinator 
being responsible for incorporating this information into its 
overarching plan. Accordingly, the Commission finds the reliability 
coordinator is a necessary entity under EOP-001-0 and directs the ERO 
to modify the Reliability Standard to include the reliability 
coordinator as an applicable entity. In addition, the ERO should 
consider SoCal Edison's suggestion in the ERO's Reliability Standards 
development process.
ii. Clarification of the 30-minute Load Shedding Requirement
(a) Comments
    550. NERC comments that the proposed directive to clarify the 30-
minute requirement in Requirement R2 presumes that all manual load 
shedding can be performed by supervisory control. It states that, in 
many systems, shedding load requires actions by field personnel who 
must be dispatched to a site. NERC recognizes the reliability benefit 
of being able to shed greater amounts of load in seconds or minutes but 
contends that the amount of load shedding under remote supervisory 
control and the timing requirements should be vetted through industry 
experts based on good utility practice. While acknowledging that the 
proposed modification is appropriate because it corresponds to current 
good utility practice and widely held interpretations of the 
requirement to shed load, FirstEnergy, like NERC, notes that loads that 
does not have SCADA cannot be shed within 30 minutes because field 
staff must be dispatched. It proposes that the Reliability Standard 
should specify that, for loads that do not have SCADA, the 
implementation plan must be initiated, but not necessarily completed, 
within 30 minutes. Similarly, MidAmerican is concerned that if load 
shedding is to be performed in much less than 30 minutes it will 
require automatic load shedding which may trigger when not required 
leading to less reliability under certain conditions. MidAmerican 
proposes a modification to specifically permit load shedding with non-
automatic schemes.
    551. Xcel states that the proposed modification is unnecessary 
because there are many different options besides load shedding that 
could be implemented to alleviate IROL violations within 30 minutes. It 
adds that load shedding is the option of last resort and that the 
timing for implementation of load shedding would be better addressed in 
proposed Reliability Standard EOP-003-1. EEI and California PUC state 
that not all load reduction schemes should be required to be operable 
within 30 minutes; only those used for emergency operations. APPA 
states that the 30-minute interval was selected based on industry 
consensus and, rather than dismiss this consensus, the Commission 
should instruct NERC to reconsider the 30-minute requirement and either 
modify it or better explain why it is the appropriate time period for 
the requirement. MISO questions what would be achieved by the proposed 
modification and states that operators do not intentionally delay 
taking action when required.
    552. International Transmission and PG&E state that shedding load 
``as soon as possible and much less than 30 minutes'' is vague and 
unenforceable. International Transmission proposes shedding of load 
``as soon as possible when required to mitigate an IROL violation, but 
in no case in more than 30 minutes.''
(b) Commission Determination
    553. The proposed Reliability Standard states that the transmission 
operator shall have an emergency load reduction plan for all identified 
IROLs and that the load reduction plan must be capable of being 
implemented within 30 minutes. In the NOPR, we proposed to direct NERC 
to modify EOP-001-0 to clarify the 30-minute requirement in Requirement 
R2 to state that load shedding should be capable of being implemented 
as soon as possible and in much less than 30 minutes.\233\ The intent 
was to have a requirement that precludes waiting until the 29th minute 
to begin implementation.
---------------------------------------------------------------------------

    \233\ Id. at P 273.
---------------------------------------------------------------------------

    554. In response to the concerns of commenters, the Commission 
clarifies that the proposed modification does not require that SCADA or 
its equivalent be installed for all loads. Rather, SCADA would be 
required only for those loads necessary to mitigate IROL violations and 
to maintain reliable operations. As we stated in the NOPR, the 
Commission understands that it is not the intent of the Reliability 
Standard to require the shedding of all available load within 30 
minutes, but rather only the amount necessary to correct system 
emergencies.\234\ Thus the Commission agrees with EEI and California 
PUC that not all load reduction schemes should be required to be 
operable within 30 minutes but only those used for emergency 
operations.
---------------------------------------------------------------------------

    \234\ Id.
---------------------------------------------------------------------------

    555. Further, as Xcel recognizes, load shedding is the option of 
last resort and there may be other options available to alleviate IROL 
violations within 30 minutes. The ERO should consider these other 
options as it works through the Reliability Standards development 
process to modify EOP-001-0.
    556. With regard to the wording of the proposed modification 
stating that load shedding should be capable of being implemented ``as 
soon as possible and in much less than 30 minutes,'' the Commission 
agrees with PG&E and International Transmission that this language may 
be unclear and unduly subjective. In the NOPR, we stated that the 
reference to 30 minutes could suggest that anything up to that limit 
was acceptable and proposed the modification to emphasize our concern 
that implementation was expected much sooner than in 30 minutes. 
International Transmission's suggested rewording addresses our concern. 
Accordingly, we direct the ERO to develop a modification through the 
Reliability Standards development process clarifying that when the load 
reduction plan of Requirement R2 involves load shedding, such load 
shedding be capable of being implemented as soon as possible when 
required to mitigate an IROL violation but in no case in more than 30 
minutes.
    557. Finally, in response to APPA's comments, as stated in the 
NOPR,\235\ the Commission accepts the 30-minute requirement as a 
reasonable period within which operators should return the system to a 
reliable operating state. However, in order to satisfy this 
Requirement, when load shedding is the only viable option, the 
Commission believes that operators must have the capability through 
SCADA or other equivalent means to shed appropriate amounts of load in 
the desired locations as soon as possible to mitigate IROL violations 
but in no case in more than 30 minutes.\236\
---------------------------------------------------------------------------

    \235\ Id. at P 995.
    \236\ Id.
---------------------------------------------------------------------------

iii. Definitions of System States
(a) Comments
    558. FirstEnergy states that it may be difficult to define system 
states that cover all operating conditions, but nonetheless recognizes 
that the standardization of these states is a first step to bringing 
clarity to operators concerning system conditions and the

[[Page 16475]]

resulting actions they are expected to take. California PUC, on the 
other hand, states that imposing uniform definitions for ``normal,'' 
``alert'' and ``emergency'' states is impractical and 
counterproductive. California PUC claims that trying to define in 
advance all contingencies that the system may face is probably 
infeasible and argues that improved real-time monitoring of the grid is 
the preferred approach for quick identification and correction of 
problems.
    559. ISO-NE states that it is important to define system states but 
that such definitions should not be implemented until a ``pilot 
program'' is field tested. ISO-NE explains that after such a pilot 
program is conducted operators would need to make changes to their 
policies and procedures, including operator training, to make sure that 
their practices are administered in a secure and well-understood 
fashion.
(b) Commission Determination
    560. In the NOPR, the Commission stated that clearly defined system 
states incorporated into real-time operation can significantly improve 
operator recognition of emergency conditions, rapid and accurate 
response and recovery to normal system conditions.\237\
---------------------------------------------------------------------------

    \237\ Id. at P 275.
---------------------------------------------------------------------------

    561. The Commission recognizes that the triggering events and the 
nature of the emergency states may be different for different systems; 
however, we find that a clearly defined set of system states will help 
operators proactively avert escalations of system disturbances and 
cascading outages. Further, operators, the ERO and regulators will 
better understand how reliably the system is operating and how it 
performed historically if statistics can be collected based on well-
defined system states. We find it reasonable for the ERO, through the 
stakeholder process, to develop a well-defined set of uniform, 
continent-wide system states that can be understood by transmission 
operators, balancing authorities, reliability coordinators and the ERO 
to correspond to specific, predetermined levels of urgency.
    562. As we noted in the NOPR, some control areas define and 
effectively use more than the ``normal,'' ``alert'' and ``emergency'' 
system states included in the Blackout Report recommendation.\238\ We 
proposed that the ERO determine the optimum number of system states to 
be employed continent-wide and to consider the addition of the 
restoration state.\239\ Accordingly, we direct the ERO to determine the 
optimum number of continent-wide system states and their attributes and 
to modify the Reliability Standard through the Reliability Standards 
development process to accomplish this objective.
---------------------------------------------------------------------------

    \238\ Id. at P 276.
    \239\ Id.
---------------------------------------------------------------------------

    563. Further, we agree with ISO-NE that the proposed modification 
should be field-tested and that policies and procedure be put in place, 
including operator training, before any processes for continent-wide 
system states are implemented. Such testing will help assure that all 
applicable entities and their personnel understand how the terms will 
be used and will allow operators to train staff to make any necessary 
changes to their policies and procedures. We direct the ERO to consider 
such a pilot program as it modifies EOP-001-0 through the Reliability 
Standards development process.
iv. Other issues
(a) Comments
    564. ISO-NE raises two additional concerns with the proposed 
Reliability Standard. First, it states that activities outlined in 
Requirement R7.4, including coordinating fuel conservation and 
arranging for fuel deliveries, are not functions that independent 
transmission operators and balancing authorities typically perform. 
Second, ISO-NE notes that Requirement R5 provides that each 
transmission operator and balancing authority must include applicable 
elements of Attachment 1 of EOP-001-0 in an emergency plan. However, 
according to ISO-NE, the elements identified in Attachment 1 are 
characterized as ``for consideration'' and are not mandatory. ISO-NE 
argues that the proposed Reliability Standard should be clarified to 
indicate that the actual emergency plan elements, and not the ``for 
consideration'' elements of Attachment 1, should be the basis for 
compliance.
(b) Commission Determination
    565. With regard to ISO-NE's concern that certain activities 
outlined in Requirement R7.4 are not functions normally performed by 
independent transmission operators and balancing authorities, the 
Commission understands that this Requirement covers either delivery of 
fuel or delivery of electrical energy from remote systems. While 
arranging for fuel deliveries may be outside of the functions that ISOs 
and RTOs perform, the requirement to arrange deliveries of electrical 
energy from remote systems is a function they normally perform. Because 
an ISO or RTO may choose to either deliver fuel or electrical energy 
from remote systems, Requirement R7.4 will not burden ISOs and RTOs 
with functions they do not normally perform.
    566. The Commission agrees with ISO-NE that the Reliability 
Standard should be clarified to indicate that the actual emergency plan 
elements, and not the ``for consideration'' elements of Attachment 1, 
should be the basis for compliance. However, all of the elements should 
be considered when the emergency plan is put together.
v. Summary of Commission Determination
    567. Accordingly, the Commission concludes that Reliability 
Standard EOP-001-0 is just, reasonable, not unduly discriminatory or 
preferential and in the public interest and approves it as mandatory 
and enforceable. In addition, pursuant to section 215(d)(5) of the FPA 
and Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to EOP-001-0 through the Reliability Standards 
development process that: (1) Includes the reliability coordinator as 
an applicable entity with responsibilities as described above; (2) 
clarifies the 30-minute requirement in Requirement R2 of the 
Reliability Standard to state that load shedding should be capable of 
being implemented as soon as possible but in no more than 30 minutes; 
(3) includes definitions of system states to be used by the operators, 
such as transmission-related ``normal,'' ``alert'' and ``emergency'' 
states, provides criteria for entering into these states, and 
identifies the authority that will declare these states and (4) 
clarifies that the actual emergency plan elements, and not the ``for 
consideration'' elements of Attachment 1, should be the basis for 
compliance. Further, the Commission directs the ERO to consider a pilot 
program for system states, as discussed above.
b. Capacity and Energy Emergencies (EOP-002-2)
    568. EOP-002-2 applies to balancing authorities and reliability 
coordinators and is intended to ensure that they are prepared for 
capacity and energy emergencies.\240\ The Reliability Standard requires 
that balancing authorities have the authority to bring

[[Page 16476]]

all necessary generation on line, communicate about the energy and 
capacity emergency with the reliability coordinator and coordinate with 
other balancing authorities. EOP-002-2 includes an attachment that 
describes an emergency procedure to be initiated by a reliability 
coordinator that declares one of four energy emergency alert levels to 
provide assistance to the LSE.
---------------------------------------------------------------------------

    \240\ In its November 15, 2006, filing, NERC submitted EOP-002-
2, which supercedes the Version 1 Reliability Standard. EOP-002-2 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, EOP-002-2.
---------------------------------------------------------------------------

    569. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct that NERC submit a 
modification to the Reliability Standard that: (1) Addresses 
emergencies resulting not only from insufficient generation but also 
from insufficient transmission capability, including situations where 
insufficient transmission impacts the implementation of the capacity 
and energy emergency plan; (2) identifies DSM in Requirement R6 as one 
possible remedy that a balancing authority may use to bring it in 
compliance with control performance and disturbance control Reliability 
Standards and (3) includes a clear warning that the TLR procedure is an 
inappropriate and ineffective tool to mitigate IROL violations or for 
use in emergency situations.
    570. Most of the comments address the specific modifications and 
concerns raised by the Commission in the NOPR. Below, we address each 
topic separately, followed by an over-all conclusion and summary.
i. Insufficient Transmission Capability
(a) Comments
    571. MRO believes that the definition for the term ``insufficient 
transmission capability'' should be clarified because insufficient 
transmission capability could be due to a thin spot in the 
interconnection, prior outages or storm damage.
(b) Commission Determination
    572. As we stated in the NOPR, neither EOP-002-2 nor any other 
Reliability Standard addresses the impact of inadequate transmission 
during generation emergencies.\241\ The Commission agrees with MRO that 
``insufficient transmission capability'' could be due to various 
causes. The ERO should examine whether to clarify this term in the 
Reliability Standards development process.
---------------------------------------------------------------------------

    \241\ NOPR at P 284.
---------------------------------------------------------------------------

ii. Demand-Side Management
(a) Comments
    573. FirstEnergy states that it is appropriate to include demand-
side resources as another tool for balancing authorities to use in 
meeting control performance and disturbance control Reliability 
Standards. It states, however, that in order to qualify, the demand-
side resource options must meet similar technical requirements as 
generation resource options. Comverge recommends that the terms 
``demand response'' and ``curtailable loads'' be specifically added to 
R3, R4 and R6.3 and Alert Level 1 to ensure that they are included in 
the list of resources that will be controlled during capacity and 
energy emergencies. APPA contends that Requirement R6.6 adequately 
accounts for the use of demand-side remedies to address emergencies. As 
such, APPA opposes the Commission's proposal as being unduly 
prescriptive. Also ISO-NE contends that the proposed modifications 
effectively dictate a specific means to solve the underlying problems 
instead of leaving it to the responsible entities to determine how to 
achieve the reliability objective. A proper recommendation would be to 
make the requirement resource-neutral.
(b) Commission Determination
    574. The Commission agrees with FirstEnergy that for demand-side 
resources to qualify as another tool for balancing authorities to use 
in meeting control performance and disturbance control Reliabilty 
Standards, they must meet comparable technical performance requirements 
as generation resource options. In response to comments from Comverge 
and APPA, the Commission believes that curtailable loads are adequately 
addressed in Requirement R6 of the Reliability Standard but that demand 
response is not covered.\242\ Demand response covers considerably more 
resources than interruptible load. Accordingly, the Commission directs 
the ERO to modify the Reliability Standard to include all technically 
feasible resource options in the management of emergencies. These 
options should include generation resources, demand response resources 
and other technologies that meet comparable technical performance 
requirements.
iii. Warning regarding TLR procedure
---------------------------------------------------------------------------

    \242\ Requirement R6 provides, in pertinent part: ``R6. If the 
Balancing Authority cannot comply with the Control Performance and 
Disturbance Control Standards, then it shall immediately implement 
remedies to do so. These remedies include, but are not limited to: 
R6.3. Interrupting interruptible load and exports.''
---------------------------------------------------------------------------

(a) Comments
    575. MRO states that it is very important that all concerned 
parties realize that TLR is not a first line of defense to mitigate 
IROL violations. Entergy and MidAmerican agree that TLR procedures are 
not effective to mitigate IROL violations or for use in emergency 
situations. EEI supports the Commission's proposed modifications to the 
Reliability Standard; however, EEI along with Entergy, MidAmerican and 
APPA, believes that the TLR process is effective in avoiding and 
mitigating potential IROL violations. These commenters request that the 
Commission clarify the proposed modification so that it does not 
foreclose such use of the TLR process.
    576. International Transmission states that TLR can be an effective 
and appropriate means to mitigate IROL violations or for use in 
emergency situations and therefore EOP-002-2 should not preclude the 
use of TLR when its use is warranted. MISO states that, while TLR is 
not the preferred method of responding to emergencies, an operator 
should not be precluded from implementing TLR during emergencies. It 
argues that TLR may be appropriate when events develop slowly or when 
an entity is affected by external transactions and has exhausted all 
control actions or needs to reserve some control actions for 
contingencies.
    577. APPA contends that the specific direction provided in this 
proposed modification intrudes on NERC's role as a standard setting 
agency and would be better framed as a direction to NERC to investigate 
the concern and revise the Reliability Standard accordingly. Similarly, 
while ISO-NE supports the Commission's conclusion that reliance on TLR 
procedures can be inappropriate, it recommends that the proposed 
Reliability Standard would be improved if it did not specify the 
operating method required to achieve compliance. ISO-NE also believes 
that the Commission should direct NERC to allow the responsible 
entities flexibility in the means by which they achieve compliance with 
the Reliability Standard.\243\
---------------------------------------------------------------------------

    \243\ ISO-NE also notes that in the first line of Requirement R7 
the reference to ``R7'' should be to ``R6.''
---------------------------------------------------------------------------

(b) Commission Determination
    578. A number of commenters agree that the TLR procedure is an 
inappropriate and ineffective tool for mitigating actual IROL 
violations or for

[[Page 16477]]

use in emergency situations.\244\ On the other hand, International 
Transmission believes the TLR procedure can be an appropriate and 
effective tool to mitigate IROL violations or for use in emergency 
situations and MISO argues that operators should not be precluded from 
implementing the TLR procedure during emergencies. The Commission 
disagrees. As explained in the NOPR and in the Blackout Report, actions 
undertaken under the TLR procedure are not fast and predictable enough 
for use in situations in which an operating security limit is close to 
being, or actually is being, violated. As such the Commission cannot 
agree with International Transmission and MISO. However, the Commission 
agrees with APPA, EEI, Entergy and MidAmerican that the TLR procedure 
may be appropriate and effective for use in managing potential IROL 
violations. Accordingly, the Commission will maintain its direction 
that the ERO modify the Reliability Standard to ensure that the TLR 
procedure is not used to mitigate actual IROL violations.
---------------------------------------------------------------------------

    \244\ See, e.g., APPA, EEI, Entergy and MidAmerican.
---------------------------------------------------------------------------

    579. As to APPA's comment that we are intruding on NERC's role as a 
standard-setting agency, we have authority to direct the ERO to submit 
a modification and, in this instance, requiring the ERO to 
``investigate the concern'' first is unnecessary. The issue is 
narrowly-framed and the comments identify no points requiring the 
approach suggested by APPA. In response to ISO-NE, we are precluding 
use of TLR procedures at times of actual IROL violations, but are not 
otherwise specifying permissible responses.
iv. Other issues
    580. ISO-NE states that Requirement R2 essentially requires the 
same actions covered by ISO-NE Operating Procedure No. 4. ISO-NE is 
concerned that a strict approach to auditing compliance with the 
Reliability Standard could result in a finding that ISO-NE was in 
violation of the Reliability Standard if it skipped a particular action 
under its emergency plan even though that action was not called for 
under ISO-NE procedures. ISO-NE requests that the Commission direct 
NERC to clarify that a system operator has discretion not to implement 
every action specified in its capacity and energy emergency plans when 
other appropriate actions are possible.
    581. FirstEnergy claims that Requirement R1 may impose overlapping 
obligations and authority on reliability coordinators and balancing 
authorities who may have the same, partial or whole footprint and who 
are both likely to respond to the same emergency.
    582. APPA notes that revised Reliability Standard EOP-002-2, filed 
by NERC on November 15, 2006, includes new Measures for some of the 
requirements but not all the requirements. APPA states that NERC should 
be directed to include Measures related to Requirements R4, R5, R6, R7 
and R9.1.
(a) Commission Determination
    583. The Commission finds that the issues raised by ISO[dash]NE 
should be addressed through the Reliability Standards development 
process. As to FirstEnergy's concern with Requirement R1, the 
reliability coordinator has the highest level of authority. 
Accordingly, the Commission directs that the ERO, through the 
Reliability Standards development process, address ISO[dash]NE's 
concern. Further, we direct the ERO to consider adding Measures and 
Levels of Non-Compliance in the Reliability Standard.
v. Summary of Commission Determination
    584. Accordingly, the Commission approves Reliability Standard EOP-
002-2 as mandatory and enforceable. In addition, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to EOP-002-2 
through the Reliability Standards development process that: (1) 
Addresses emergencies resulting not only from insufficient generation 
but also from insufficient transmission capability particularly where 
this affects the implementation of the capacity and energy emergency 
plan; (2) includes all technically feasible resource options, including 
demand response and generation resources, in the management of 
emergencies and (3) ensures that the TLR procedure is not used to 
mitigate actual IROL violations.
c. Load Shedding Plans (EOP-003-1)
    585. EOP-003-1 deals with load shedding plans and requires that 
balancing authorities and transmission operators operating with 
insufficient transmission and generation capacity have the capability 
and authority to shed load rather than risk a failure of the 
Interconnection.\245\ It includes requirements to establish plans for 
automatic load shedding for underfrequency or undervoltage, manual load 
shedding to respond to real-time emergencies and communication with 
other balancing authorities and transmission operators.
---------------------------------------------------------------------------

    \245\ In its November 15, 2006, filing, NERC submitted EOP-003-
1, which supercedes the Version 0 Reliability Standard. EOP-003-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, EOP-003-1.
---------------------------------------------------------------------------

    586. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct that NERC submit a 
modification to EOP-003-0 that: (1) Specifies the minimum load shedding 
capability that should be provided and the maximum amount of delay 
before load shedding can be implemented; (2) requires periodic drills 
of simulated load shedding and (3) contains Measures and Levels of Non-
Compliance.
    587. Most of the comments address the specific modifications and 
concerns raised by the Commission in the NOPR. Below, we address each 
topic separately, followed by an over-all conclusion and summary.
i. Minimum load shedding and maximum delay
(a) Comments
    588. FirstEnergy and APPA agree that NERC should modify EOP-003-1 
to specify the minimum load shedding capability and the maximum amount 
of delay. However, FirstEnergy adds that Requirement R8, which states 
that load shedding actions must be taken in a ``time frame adequate for 
responding to the emergency,'' is ambiguous and difficult to 
substantiate. NERC acknowledges that significant improvements can be 
made to the EOP Reliability Standards to establish criteria for the 
provision of load shedding capability, but it states that requiring a 
specific minimum amount of load (MW) or percentage of load that must be 
capable of being shed and the maximum amount of time delay is as likely 
to reduce reliability as it is to increase it. NERC contends that the 
electric characteristics of local systems and loads must be considered 
in designing manual and automatic load shedding capabilities. 
Accordingly, it proposes that the Commission direct NERC to review 
industry best practices and propose requirements in the Reliability 
Standards to ensure that adequate load shedding capabilities are 
provided to protect the Bulk-Power System without causing adverse 
impacts associated with unnecessary shedding of firm load.

[[Page 16478]]

    589. SoCal Edison states that in certain circumstances, but not in 
all cases, it would be valuable to have a minimum limit established for 
the amount of load shedding an entity is to accomplish. It suggests 
that the specific requirements should be derived based on studied 
conditions.
    590. Xcel, ISO-NE, TVA and International Transmission do not 
support a nationwide Reliability Standard for minimum load shedding and 
maximum delay for implementing load shedding because there are large 
variations in load, resources and system configuration and 
characteristics across the continent. TVA states that these parameters 
should be determined based on studies of the specific transmission 
systems and applicable contingency events. MISO states that it is not 
clear what is intended or achieved by this requirement because 
balancing authorities and transmission operators should already have 
the ability to shed, by some means, all load within their area and the 
timing requirements are specified in the IROL-related Reliability 
Standards.
    591. California PUC is concerned that the proposed modification 
assumes that load shedding at the transmission level is the only or the 
primary way to address system emergencies. SDG&E recommends that the 
maximum delay for shedding load should begin when the transmission 
operator or balancing authority has actual knowledge of the 
circumstances that would precipitate load shedding.
(b) Commission Determination
    592. Shedding of firm load is an operating measure of last resort 
to contain system emergencies and prevent cascading. System operators 
must have the capability to shed load in a timely manner to return the 
system to a stable condition. The Commission disagrees with NERC's 
contention that requiring a specific minimum amount of load that must 
be capable of being shed and the maximum amount of delay is as likely 
to reduce reliability as it is to increase it. As stated in the NOPR, 
the actual amount of load to be shed, the location and the time frame 
will be at the discretion of the system operator based on the nature of 
the system problem and the operator's assessment of corrective actions 
required.\246\ However, if the capability to shed sufficient load in 
locations where it is required and in a timely manner is not available 
to the system operator, then the risk of uncontrolled failure of system 
elements or cascading outages is increased.
---------------------------------------------------------------------------

    \246\ NOPR at P 294.
---------------------------------------------------------------------------

    593. While the Reliability Standard requires transmission operators 
and balancing authorities to be capable of load shedding in a time 
frame adequate for responding to emergencies, this could be clearer, as 
noted by FirstEnergy. As mentioned by NERC, significant improvements 
can be made to the Reliability Standard to establish criteria for the 
provision of load shedding capability. We agree.
    594. Several commenters state that they do not support a nationwide 
Reliability Standard for minimum load shedding capability and maximum 
delay in implementing load shedding because these parameters are 
dependent on system configurations and load and resource 
characteristics across the continent, and as such, must be determined 
based on system studies.\247\ The Commission agrees that the minimum 
load shedding capability must take into account system characteristics 
and topology, however the maximum time delay before load shedding can 
be implemented is independent of system characteristics and is governed 
by what is considered to be feasible.
---------------------------------------------------------------------------

    \247\ See Xcel, ISO-NE, TVA, International Transmission and 
MISO.
---------------------------------------------------------------------------

    595. California PUC is concerned that the proposed modification on 
load shedding assumes that load shedding at the transmission level is 
the only or preferred way to address system emergencies. The Commission 
clarifies that this assumption is incorrect and agrees with California 
PUC that load shedding at the distribution level has the minimum 
societal and economic impact.
    596. The Commission concludes that the Reliability Standard needs 
to be modified to ensure that adequate load shedding capabilities are 
provided so that system operators have an effective operating measure 
of last resort to contain system emergencies and prevent cascading. The 
Commission recognizes that the amount of load shedding capability 
required is dependent on system characteristics and therefore it may 
not be feasible to have a uniform nationwide load shedding capability. 
This, however, does not preclude a uniform nationwide criterion on the 
methodology for establishing load shedding capability that would 
specify the minimum amount of load shedding capability that should be 
provided based on system characteristics and conditions and the maximum 
amount of delay before load shedding can be implemented. The Commission 
directs the ERO to address the minimum load and maximum time concerns 
of the Commission through the Reliability Standards development 
process. We suggest that a review of industry best practices would be 
useful in developing nationwide critera.
ii. Periodic drills of simulated load shedding
(a) Comments
    597. California PUC states that, since load shedding at the 
distribution level has the minimum societal and economic impact, the 
Reliability Standard should require all neighboring distribution or 
transmission utilities to participate in annual drills when requested 
by an ISO or other bulk power authority. Northern Indiana and 
FirstEnergy support mandating periodic drills of simulated load 
shedding; however, FirstEnergy states that the drill requirements 
should include simulated load shed via a simulator or table-top 
exercise, not an actual deployment of manpower, and that these drill 
requirements should be included in the PER-005-0 Reliability Standard 
instead of EOP-003-1. PER-005-0 only involves training of control room 
personnel, whereas these drills should also include testing the 
readiness and functionality of procedures and personnel outside of the 
control room.
(b) Commission Determination
    598. As suggested by California PUC, periodic drills of simulated 
load shedding should involve all participants required to ensure 
successful implementation of load shedding plans. As such, the drills 
should extend beyond system operators to distribution operators and 
LSEs. The Reliability Standard should require periodic drills by 
entities subject to section 215, and require those entities to seek 
participation by other entities. The drills should test the readiness 
and functionality of the load shedding plans, including, at times, the 
actual deployment of personnel. Therefore the Commission disagrees with 
FirstEnergy that the requirement for periodic drills of simulated load 
shedding should be incorporated into the new PER-005-0 Reliability 
Standard that is currently being drafted to address operator training.
iii. Other issues
(a) Comments
    599. Santa Clara states that since automatic load shedding for 
undervoltage conditions is not required in most parts of the West and 
possibly in other areas of the country,

[[Page 16479]]

Requirement R2 should be modified to include the words ``as applicable 
per the Regional Reliability Organization.'' In addition, APPA states 
that NERC should consider requiring balancing authorities and 
transmission operators to expand coordination and planning of their 
automatic and manual load shedding plans to include their respective 
Regional Entities, reliability coordinators and generation owners. 
ISO[dash]NE proposes that NERC establish coordinated trip settings 
within and among balancing authorities for each interconnection.
    600. While EEI generally supports the proposed modifications, it 
believes that the proposal for senior management to post letters to 
safeguard operators who shed load in accordance with approved 
guidelines does not respond to or meet the needs reflected in the 
Blackout Recommendation No. 8. EEI points out that, under other 
provisions of the FPA, the Commission has approved liability limiting 
provisions for some operators that appears to be consistent with the 
Blackout Report Recommendation No. 8, but has rejected other similar 
protections. EEI requests that the Commission explicitly state that 
transmission operators taking action in compliance with the load 
shedding provisions of Commission approved Reliability Standards will 
be protected from retaliatory actions, including legal actions.
(b) Commission Determination
    601. Regarding Santa Clara's concern that undervoltage load 
shedding is not required in most parts of WECC and that Requirement R2 
should be modified to reflect this, the Commission notes that 
Requirement R2 states that each transmission operator and balancing 
authority shall establish plans for automatic load shedding for 
underfrequency or undervolatge conditions. The Commission clarifies 
that the Reliability Standard does not mandate undervoltage load 
shedding unless needed for Reliable Operation.
    602. We also note that APPA and ISO[dash]NE raise issues regarding 
coordination of trip settings and automatic and manual load shedding 
plans. The Commission directs the ERO to consider these comments in 
future modification to the Reliability Standard through the Reliability 
Standards development process.
    603. EEI seeks adoption of a provision to shield transmission 
operators from liability when they take action in compliance with the 
load shedding provisions of the Reliability Standards. Consistent with 
our discussion of Blackout Report Recommendation No. 8 in the Common 
Issues section of this Final Rule, the Commission will not adopt new 
liability protections.\248\ According to the Task Force, no further 
action is needed to implement that recommendation because some states 
already have appropriate protection against liability suits.\249\ 
Further, in Order No. 890, we have already declined to provide a 
uniform federal liability standard.
---------------------------------------------------------------------------

    \248\ See Common Issues Pertaining to Reliability Standards: 
Blackout Report Recommendation on Liability Limitations, supra 
section II.E.1.
    \249\ U.S.-Canada Power System Outage Task Force, Final Report 
on Implementation of Task Force Recommendations at 22 (Oct. 3, 
2006), available at http://www.oe.energy.gov/news/blackout.htm (``In 
the United States, some state regulators have informally expressed 
the view that there is appropriate protection against liability 
suits for parties who shed load according to approved guidelines.'')
---------------------------------------------------------------------------

iv. Summary of Commission Determination
    604. The Commission approves proposed Reliability Standard EOP-003-
1 as mandatory and enforceable. In addition, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to EOP-003-1 
through the Reliability Standards development process that: (1) 
Includes a requirement to develop specific minimum load shedding 
capability that should be provided and the maximum amount of delay 
before load shedding can be implemented based on an overarching 
criteria that take into account system characteristics and (2) requires 
periodic drills of simulated load shedding.
d. Disturbance Reporting (EOP-004-1)
    605. EOP-004-1 establishes requirements for reporting system 
disturbances to the regional reliability organization and the ERO.\250\ 
It also establishes requirements for the analysis of these 
disturbances.
---------------------------------------------------------------------------

    \250\ In its November 15, 2006, filing, NERC submitted EOP-004-
1, which supercedes the Version 0 Reliability Standard. EOP-004-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, EOP-004-1.
---------------------------------------------------------------------------

    606. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct that NERC submit a 
modification to the Reliability Standard that: (1) Includes any 
requirements necessary for users, owners and operators of the Bulk-
Power System to provide data that will assist NERC in the investigation 
of a blackout or disturbance and (2) includes Measures and Levels of 
Non-Compliance.
i. Comments
    607. EEI and FirstEnergy support the Commission's proposed 
modifications to the Reliability Standard. EEI states that data 
reporting requirements and other process requirements should be 
contained in enforceable Reliability Standards. FirstEnergy states that 
the proposed modification corresponds to good utility practice and that 
explicitly stating the requirement to provide data to NERC brings 
clarity to the expectations of NERC and the Commission.
    608. APPA is concerned about the scope of Requirement R2 because, 
in its opinion, Requirement R2 appears to impose an open-ended 
obligation on entities such as generation operators and LSEs that may 
have neither the data nor the tools to promptly analyze disturbances 
that could have originated elsewhere. APPA proposes that Requirement R2 
be modified to require affected entities to promptly begin analyses to 
ensure timely reporting to NERC and DOE.
    609. Xcel expresses concern regarding what constitutes a reportable 
event for each applicable entity and recommends that the Reliability 
Standard be revised to define what a reportable event is for each 
entity that has reporting obligations. Further, Xcel states that the 
requirement in Requirement R3.4 for a final report within 60 days may 
not be feasible given the current WECC process, which among other 
things, requires the creation of a group to prepare the report and a 
30-day posting of a draft report before it becomes final. Xcel also 
states that if the ultimate purpose of the report is to provide 
information to avoid a recurrence of a system disturbance, then the 
Reliability Standard should be revised to require the distribution of 
the report to similarly situated entities.
    610. FirstEnergy states that, since nuclear units have their own 
NRC reporting procedures covering the Requirements under EOP-004-1, the 
Reliability Standard should specify that compliance with such operating 
procedures is sufficient to satisfy the requirements of EOP-004-1. 
FirstEnergy also states that the title of this Reliability Standard 
should be changed to ``Disturbance Event Reporting'' to indicate that 
the events covered under this Reliability Standard include a broad 
range of events that go beyond the events for which reports may be 
required under Reliability Standard BAL-002-0.

[[Page 16480]]

    611. APPA states that NERC's November 15, 2006 revision partially 
fulfills the proposed modification to include Measures and Levels of 
Non-Compliance. APPA notes that EOP-004-1 did not provide Measures for 
R2, R3.2, R3.4, R4 and R5.
ii. Commission Determination
    612. Complete and timely data is essential for analyzing system 
disturbances. In the NOPR, the Commission proposed modifying this 
disturbance Reporting Standard to include requirements necessary for 
users, owners and operators of the Bulk-Power System to provide 
disturbance data, voice recordings and other information collected 
during the disturbance to assist NERC in the investigation of the 
blackout or disturbance.\251\ While some commenters agree with this 
proposal, APPA and Xcel express concerns regarding the scope and 
applicability of some of the Requirements of the Reliability Standard.
---------------------------------------------------------------------------

    \251\ NOPR at P 304.
---------------------------------------------------------------------------

    613. Requirement R2 of the Reliability Standard requires 
reliability coordinators, balancing authorities, transmission 
operators, generator operators and LSEs to promptly analyze 
disturbances on their system or facilities. APPA is concerned that 
generator operators and LSEs may be unable to promptly analyze 
disturbances, particularly those disturbances that may have originated 
outside of their systems, as they may have neither the data nor the 
tools required for such analysis. The Commission understands APPA's 
concern and believes that, at a minimum, generator operators and LSEs 
should analyze the performance of their equipment and provide the data 
and information on their equipment to assist others with their 
analyses. The Commission directs the ERO to consider this concern in 
future revisions to the Reliability Standard through the Reliability 
Standards development process.
    614. The Commission disagrees with Xcel that the Reliability 
Standard is unclear about what constitutes a reportable event. 
Attachment 1 of the Reliability Standard details the various events 
that would trigger the reporting requirement under this Reliability 
Standard.
    615. FirstEnergy states that since nuclear units have their own NRC 
reporting requirements the Reliability Standard should specify that 
compliance with NRC procedures is sufficient to satisfy the obligations 
of this Reliability Standard. The Commission disagrees with FirstEnergy 
because there are situations where the ERO Reliability Standards are 
more stringent than the NRC procedures. In such cases, the ERO 
Reliability Standards must apply in addition to the NRC requirements. 
Also, the Commission disagrees with FirstEnergy's comment on changing 
this Reliability Standard's name to avoid confusion with BAL-002-0. The 
purpose of the Reliability Standard is clear as to the extent of the 
disturbances to be reported.
    616. The Commission declines to address Xcel's concerns about the 
current WECC process. These issues should be addressed in the 
Reliability Standards development process or submitted as a regional 
difference. The Commission directs the ERO to consider all comments in 
future modifications of the Reliability Standard through the 
Reliability Standards development process.
    617. In response to APPA's concern that NERC did not provide a 
Measure for each Requirement, we reiterate that it is in the ERO's 
discretion whether each Requirement requires a corresponding Measure. 
The ERO should consider this issue through the Reliability Standards 
development process.
    618. While the Commission has identified concerns with regard to 
EOP-004-1, we believe that the proposal serves an important purpose in 
establishing requirements for reporting and analysis of system 
disturbances. Accordingly, the Commission approves Reliability Standard 
EOP-004-1 as mandatory and enforceable. In addition, pursuant to 
section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to EOP-004-1 
through the Reliability Standards development process that includes any 
Requirements necessary for users, owners and operators of the Bulk-
Power System to provide data that will assist NERC in the investigation 
of a blackout or disturbance.
    619. Requirement R3 addresses the reporting of disturbances to the 
regional reliability organizations and NERC. The Commission directs the 
ERO to change its Rules of Procedure to assure that the Commission also 
receives these reports within the same time frames as DOE.
e. System Restoration Plans (EOP-005-1)
    620. EOP-005-1 deals with system restoration plans and requires 
that plans, procedures, and resources be available to restore the 
electric system to a normal condition in the event of a partial or 
total system shut down. The Reliability Standard requires transmission 
operators, balancing authorities, and reliability coordinators to have 
effective restoration plans, to test those plans, and to be able to 
restore the interconnection using them following a blackout. It also 
requires operating personnel to be trained in these plans.
    621. In the NOPR, the Commission proposed to approve Reliability 
Standard EOP-005-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct that NERC submit a modification to 
EOP-005-1 that: (1) Includes Measures and (2) identifies time frames 
for training and review of restoration plan requirements to simulate 
contingencies and prepare operators for anticipated and unforeseen 
events.
i. Comments
    622. APPA and EEI state that Reliability Standard EOP-005-1 is 
sufficient for approval as a mandatory Reliability Standard and 
requests that the Commission direct NERC to address missing Measures 
and training requirements. In addition, APPA notes that the Reliability 
Standard is applicable to both balancing authorities and transmission 
operators but the Measures and Levels of Non-Compliance elements refer 
only to transmission operators.
    623. ISO[dash]NE does not support adoption of the proposed 
Reliability Standard because, while Requirement R1 requires 
transmission operators to include applicable elements from Attachment 1 
of EOP-005-1 in their restoration plans, Requirement R1 appears to 
indicate that the elements in Attachment 1 are to be included in the 
emergency plan only ``as applicable.'' ISO[dash]NE states that the 
Reliability Standard should be clarified to indicate that the actual 
emergency plan elements should be the basis for compliance.
    624. EEI and FirstEnergy note that the proposed modification to 
identify time frames for training and review of restoration plan 
requirements is being addressed in the proposed Reliability Standard 
PER-005-1 and that including this requirement in EOP-005-1 would be 
redundant. MISO also believes that the proposed modification is 
unnecessary. It states that there are already requirements for 
simulation-based training on emergencies and restoration and it is 
unclear what is meant by conducting training to prepare operators for 
unforeseen events.

[[Page 16481]]

    625. FirstEnergy states that Requirement R1 calls for a plan for a 
partial shutdown of the system and that there is an infinite set of 
events that can cause a partial shutdown. According to FirstEnergy, 
because the borders of a partial shutdown are difficult, if not 
impossible, to foresee, the Reliability Standard should specify some 
boundaries for analysis of partial shutdowns including an appropriate 
definition of the term ``partial shutdown.'' In addition, FirstEnergy 
states that one uniform plan for all systems is not feasible; rather 
the Reliability Standard should recognize that some companies already 
have existing plans that could be used for analyzing events. 
FirstEnergy also states that the Reliability Standard should provide a 
uniform checklist of factors to analyze, developed on a company-
specific basis.
    626. NRC suggests that this Reliability Standard include: (1) A 
requirement to record the time it takes to restore power to the 
auxiliary power systems of nuclear power plants; (2) a provision 
stating that the affected transmission operators shall give high 
priority to restoration of off-site power to nuclear power plants 
whether or not a nuclear power plant is being powered from the nuclear 
power plant's onsite power supply and (3) a provision stating that 
restoration shall not violate nuclear power plant minimum voltage and 
frequency requirements.
    627. While not commenting on the substance of Reliability Standard 
EOP-005-1, MRO states that EOP-005-1, EOP-006-1 and EOP-007-0 are 
ordered in a confusing manner and should be renumbered. MRO reasons 
that since the regional coordinator has oversight responsibility for 
system restoration, EOP-006-1 should be first in the system restoration 
sequence of Reliability Standards (i.e., EOP-006-1 should precede EOP-
005-1). Further, MRO recommends that EOP-005-1 follow EOP-006-1 because 
transmission owners and balancing authorities are responsible for 
submitting restoration plans to the regional coordinator. MRO requests 
that if a reason exists for the current order, NERC should provide that 
reason to the Commission.
ii. Commission Determination
    628. With regard to comments that the Commission's concerns are 
being addressed in NERC's drafting of proposed PER-005-1 Reliability 
Standard on operator training, we note PER-005-1 only includes 
Requirements on the control room personnel and not those outside of the 
control room. System restoration requires the participation of not only 
control room personnel but also those outside of the control room. 
These include blackstart unit operators and field switching operators 
in situations where SCADA capability is unavailable. As such, the 
Commission believes that inclusion of periodic system restoration 
drills and training and review of restoration plans in a system 
restoration Reliability Standard is the most effective way of achieving 
the desired goal of ensuring that all participants are trained in 
system restoration and that the restoration plans are up to date to 
deal with system changes.
    629. Several commenters raise issues that should be addressed by 
the ERO through the Reliability Standards development process.\252\ For 
example: whether the Measures and Levels of Non-Compliance should refer 
to balancing authorities; clarification of the elements that form the 
basis for compliance with the requirements of Attachment 1; what 
constitutes a partial shutdown for which restoration plans must be 
developed and recognition that some companies already have existing 
plans that could be used for analyzing events; and that the Reliability 
Standard should provide a uniform checklist of factors to analyze, 
developed on a company-specific basis. We find that consideration of 
these issues could be helpful in meeting the objectives of the 
Reliability Standard. Accordingly, the ERO should consider these 
concerns in future revisions of the Reliability Standard through the 
Reliability Standards development process.
---------------------------------------------------------------------------

    \252\ See APPA, ISO-NE, FirstEnergy and MRO.
---------------------------------------------------------------------------

    630. NRC raises several issues concerning the role and priority 
that nuclear power plants should have in system restorations. The 
Commission shares these concerns and directs the ERO to consider the 
issues raised by NRC in future revisions of the Reliability Standard 
through the Reliability Standards development process. In addition the 
Commission directs the ERO to gather data, pursuant to Sec.  39.5(f) of 
the Commission's regulations, from simulations and drills of system 
restoration on the time it takes to restore power to the auxiliary 
power systems of nuclear power plants under its data gathering 
authority and report that information to the Commission on a quarterly 
basis.
    631. We find that the Reliability Standard adequately addresses 
operating personnel training and system restoration plans to ensure 
that transmission operators, balancing authorities and reliability 
coordinators are prepared to restore the Interconnection following a 
blackout. Accordingly, the Commission approves Reliability Standard 
EOP-005-1 as mandatory and enforceable. In addition, pursuant to 
section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to EOP-005-1 
through the Reliability Standards development process that identifies 
time frames for training and review of restoration plan requirements to 
simulate contingencies and prepare operators for anticipated and 
unforeseen events and gathers the data from simulations and drills of 
system restoration on the time it takes to restore power to the 
auxiliary power systems of nuclear power plants under its data 
gathering authority and report that information to the Commission on a 
quarterly basis.
f. Reliability Coordination-System Restoration (EOP-006-1)
    632. Proposed Reliability Standard EOP-006-1 addresses reliability 
coordination and system restoration.\253\ It establishes specific 
requirements for reliability coordinators during system restoration, 
and it states that reliability coordinators must have a coordinating 
role in system restoration to ensure that reliability is maintained 
during restoration and that priority is placed on restoring the 
Interconnection.
---------------------------------------------------------------------------

    \253\ In its November 15, 2006, filing, NERC submitted EOP-006-
1, which supercedes the Version 0 Reliability Standard. EOP-006-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, EOP-006-1.
---------------------------------------------------------------------------

    633. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct that NERC submit a 
modification to the Reliability Standard that: (1) requires that the 
reliability coordinator be involved in the development of and approves 
restoration plans and (2) includes Measures and Levels of Non-
Compliance.
i. Comments
    634. APPA states that Reliability Standard EOP-006-1, which NERC 
filed on November 15, 2006, includes the required Measures and Levels 
of Non-Compliance and as such APPA agrees that EOP-006-1 should be 
approved as mandatory and enforceable. In addition, APPA does not 
oppose industry consideration of a requirement that reliability 
coordinators be involved in the development and approval of restoration 
plans.

[[Page 16482]]

    635. EEI states that Requirements R4 and R11 of EOP-005-1 already 
address reliability coordinator involvement in the development and 
approval of transmission operator system restoration plans. Further, 
while EEI agrees that the reliability coordinator's role is 
appropriate, it believes that the asset owner, as the entity that 
ultimately bears responsibility for restoration capabilities, should 
also have authority to develop and maintain the plans. MISO believes 
that it is unnecessary to modify the Reliability Standard to involve 
the reliability coordinator because there is already a requirement in 
EOP-005-1 for balancing authorities and transmission operators to 
coordinate their plans with the reliability coordinator.
    636. Xcel disagrees that the reliability coordinator should be 
involved with the development of restoration plans because the 
reliability coordinator typically does not have the knowledge of the 
details necessary to develop the plans in contrast to the balancing 
authorities and the transmission operators. Instead it proposes that 
the reliability coordinator develop its own plans and coordinate that 
with the balancing authority and transmission operator's plans.
ii. Commission Determination
    637. The reliability coordinator is the highest level of authority 
that is responsible for the reliable operation of the Bulk-Power 
System. Given the importance of this role in connection with matters 
covered by EOP-006-1, the Commission believes that the reliability 
coordinator must be involved in the development and approval of the 
restoration plans. The current Reliability Standard only requires that 
the reliability coordinator be aware of the restoration plan of each 
transmission operator in its area. The Commission disagrees with EEI 
and MISO, who contend that the reliability coordinator's role in the 
transmission operator's restoration plan is covered in EOP-005-1. EOP-
005-1 only requires coordination with the reliability coordinator, and 
during actual system restoration, EOP-005-1 requires approval from the 
reliability coordinator to resynchronize isolated areas with other 
isolated areas.
    638. In response to comments by Xcel, the Commission believes that 
while the reliability coordinator may not have the level of detailed 
knowledge that the balancing authorities and transmission operators may 
have for setting-up the stable islands required under restoration 
plans, the reliability coordinator is in the best position to determine 
how those stable islands should be resynchronized with each other and 
the rest of the interconnected system.
    639. The Commission finds that the Reliability Standard adequately 
addresses the goals of effective and efficient reliability coordination 
and system restoration. Accordingly, the Commission approves 
Reliability Standard EOP-006-1 as mandatory and enforceable. In 
addition, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of 
our regulations, the Commission directs the ERO to develop a 
modification to EOP-006-1 through the Reliability Standards development 
process that ensures that the reliability coordinator, which is the 
highest level of authority responsible for reliability of the Bulk-
Power System, is involved in the development and approval of system 
restoration plans.
g. Establish, Maintain, and Document a Regional Blackstart Capability 
Plan (EOP-007-0)
    640. EOP-007-0, which deals with establishing, maintaining and 
documenting regional blackstart capability plans, ensures that the 
quantity and location of system blackstart generators are sufficient 
and that they can perform their expected functions as specified in the 
overall coordinated regional system restoration plans.
    641. The NOPR did not propose to approve or remand EOP-007-0, 
because it applies only to regional reliability organizations.
i. Comments
    642. APPA agrees that EOP-007-0 should not be approved as a 
mandatory Reliability Standard and states that in the interim the 
regional reliability organizations and Regional Entities should 
continue to perform this function. In addition, APPA proposes that, in 
the interim, an umbrella organization composed of representatives from 
each regional reliability organization and Regional Entity should be 
formed to establish operation planning rules, including blackstart 
requirements, across the Eastern Interconnection. APPA suggests that 
such an effort would go a long way in identifying critical facilities, 
using consistent and transparent study assumptions and minimizing seams 
during system emergencies throughout the Interconnection.
    643. TANC states that the number of blackstart units and their 
locations depend heavily on regional characteristics and cannot be 
prescribed in a uniform, continent-wide manner. It proposes that 
regional flexibility be afforded to provide an appropriate mix of 
facilities to achieve the reliability objectives. EEI suggests that 
EOP-007-0 be rewritten so that compliance obligations are assigned 
directly to those entities that provide the data and other information.
    644. FirstEnergy and MRO state that the reliability coordinator, 
not the Regional Entity, should be responsible for the regional 
blackstart plan for its area of responsibility. Further, FirstEnergy 
states that the blackstart plan developed for a region should be 
consistent with NRC requirements, should recognize that nuclear units 
have no blackstart capability and should recognize that nuclear units 
must have priority access to off-site power for safety reasons. 
FirstEnergy requests that the Commission direct NERC to revise the 
definition of a blackstart unit to mean a ``diesel, hydro, pump 
storage, or the combustion turbine generating unit that is used to 
provide cranking power to a larger steam generating unit designed to 
restore load'' or to mean a ``larger steam generating unit designed to 
restore load.'' \254\ MRO states that arrangements for coordination of 
blackstart capability should be addressed in a contract between 
appropriate entities.
---------------------------------------------------------------------------

    \254\ See FirstEnergy at 35.
---------------------------------------------------------------------------

ii. Commission Determination
    645. The Commission will not approve or remand EOP-007-0, because 
it applies only to regional reliability organizations. However, the 
Commission provides guidance for the ERO's future consideration.
    646. The Commission disagrees with APPA that an umbrella 
organization is needed for the Eastern Interconnection while the 
Reliability Standard is pending final approval. The Commission is 
persuaded that FirstEnergy's and MRO's comments concerning the 
reliability coordinator being responsible for regional blackstart plans 
have merit. The Commission has directed that the reliability 
coordinator approve the system restoration plans and this is a logical 
extension of that direction. However, until such time as the 
Reliability Standard has been revised and approved by the ERO and the 
Commission, the regional reliability organization (or Regional Entity, 
depending on the organization of a particular region) should continue 
to perform this role as it has in the past.\255\
---------------------------------------------------------------------------

    \255\ See NOPR at P 328.
---------------------------------------------------------------------------

    647. With regard to TANC's request for regional flexibility in 
determining the appropriate mix of facilities needed to achieve the 
reliability objectives, it is

[[Page 16483]]

our understanding that the Reliability Standard provides for the number 
and location of blackstart units to vary depending on the specific 
requirements of each system. We believe that uniformity will be 
required, however, in the criteria used to determine the number and 
location of blackstart units and testing requirements.
    648. EEI, FirstEnergy and MRO offer suggestions for improving the 
Reliability Standard. The Commission directs the ERO to consider these 
suggestions in future revisions to improve EOP-007-0, through the 
Reliability Standards development process.
    649. Accordingly, the Commission will not approve or remand EOP-
007-0 at this time.
h. Plans for Loss of Control Center Functionality (EOP-008-0)
    650. EOP-008-0 addresses plans for loss of control center 
functionality. It requires each reliability coordinator, transmission 
operator and balancing authority to have a plan to continue reliable 
operations and to maintain situational awareness in the event its 
control center is no longer operable.
    651. The Commission proposed five modifications to the Reliability 
Standard and requested additional comments on other issues. We have 
grouped the comments into two general categories: (1) Capabilities of 
backup control centers and (2) which entities should have full backup 
centers. Below, we address each topic separately, followed by an 
overall conclusion and summary.
i. Capabilities of Backup Control Centers
    652. In the NOPR, the Commission proposed to approve Reliability 
Standard EOP-008-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct that NERC submit a modification to 
EOP-008-0 that includes a Requirement that provides for backup 
capabilities that, at a minimum, must: (1) Be independent of the 
primary control center; (2) be capable of operating for a prolonged 
period of time and (3) provide for a minimum set of tools and 
facilities to replicate the critical reliability functions of the 
primary control center.\256\ In addition to these three capabilities 
requirements, the Commission solicited comments concerning other 
specific capabilities.
---------------------------------------------------------------------------

    \256\ The term ``facility'' in this context includes, but is not 
limited to, telecommunications, backup power supplies, computer 
systems and security systems. NOPR at P 335 & n.159.
---------------------------------------------------------------------------

(a) Comments
    653. EEI, Entergy, FirstEnergy and Northern Indiana support the 
proposed modifications to EOP-008-0. Entergy agrees with the 
Commission's proposed modifications to include more Requirements 
regarding backup capabilities.
    654. APPA, Nevada Companies and TAPS caution that costs must be 
considered and compared to possible benefits. APPA states that it would 
take some time to implement the proposed modifications and therefore 
specific requirements for backup control facilities and capabilities 
should be left to the Reliability Standard development process. Nevada 
Companies cautions that utilities that have invested millions of 
dollars in back-up capabilities may find these facilities to be non-
compliant with the proposed Reliability Standard. It suggests that 
cost/benefits analyses be conducted and that a grandfathering provision 
be adopted to protect investments in backup systems that were made in a 
good faith effort to comply with rules in place in the past, but which 
may not comply with the Reliability Standard.
    655. MRO requests clarification of the term ``capability'' because 
it is unsure if the term is intended to refer to a facility, what such 
a facility should consist of and what operators should be capable of 
doing from that facility.
    656. In response to the request for comments on backup 
capabilities, NERC states that these are best addressed through the 
Reliability Standards development process.
    657. SoCal Edison suggests that a risk-based assessment be 
considered to determine the requirements for backup. MISO, TAPS and 
International Transmission note that work is underway by NERC to 
address the provisions for redundancy and backup control capabilities 
via the Operating Committee Backup Control Task Force and that the 
focus is on functionality rather than physical requirements. TAPS 
states that, rather than directing NERC to adopt specific modifications 
to the Reliability Standard that would inappropriately burden small 
systems with the cost of dual facilities, the Commission should 
identify objectives to the Task Force. TAPS also states that a small 
balancing authority might be able to meet the functional requirements 
for a backup control center with a contract with another entity while 
larger entities might need a physical backup center.
    658. Northern Indiana states that the Commission's proposal appears 
to eliminate an entity's opportunity to contract for backup 
capabilities from others who already have full backup control centers. 
FirstEnergy and Northern Indiana advocate for flexibility in the means 
used to meet the backup requirements and request that the Commission 
clarify that a ``full backup center'' can include providing full 
redundancy by contract rather than physical backup center facilities. 
SoCal Edison states that when entities utilize the services of another 
entity for backup, they should be required to test the backup 
capability a minimum number of times during the year and that all 
system operators should be required to participate in such testing over 
a specified time period.
    659. NRC suggests that this Reliability Standard require: (1) A 
list of the nuclear power plants and their voltage, thermal, and/or 
frequency limits and (2) provisions to notify nuclear power plants of 
the loss of control center functionality.
(b) Commission Determination
    660. As we stated in the NOPR, the goal of the Reliability Standard 
is the continuation of reliable operations and the maintenance of 
situational awareness in the event that the primary control center is 
no longer operational.\257\ Some commenters support the proposal to 
require backup capabilities while others including APPA, Nevada 
Companies and TAPS caution that the cost of the proposal may not be 
justified. In addition, some commenters, including FirstEnergy and 
Northern Indiana, advocate for flexibility in meeting the backup 
requirements and suggest that entities should be able to contract for 
full redundancy. MRO seeks clarification regarding the use of the term 
``capability.''
---------------------------------------------------------------------------

    \257\ NOPR at P 329.
---------------------------------------------------------------------------

    661. In the NOPR, we found that the provision of backup 
capabilities should be an explicit Requirement to meet the objectives 
of the Reliability Standard. We chose to use the word ``capabilities'' 
to avoid defining particular facilities or preclude other options, 
including arranging for backup capabilities by contracting with others. 
We stated that the mechanism to provide these capabilities may include 
building fully redundant physical backup control centers, contracting 
for backup control services or using backup equipment within a separate 
existing facility.\258\ In addition, regardless of the means used to 
provide the backup capabilities, as we stated in the NOPR, the time 
period for which backup capability is required

[[Page 16484]]

should correspond to the time it would take to replace the primary 
control center.
---------------------------------------------------------------------------

    \258\ See Id. at P 336.
---------------------------------------------------------------------------

    662. On the issue of additional backup capabilities, NERC, MISO, 
TAPS and International Transmission propose that the functional 
requirements for backup capabilities be determined by the NERC Backup 
Control Task Force. NRC offers requirements it believes should be added 
to the Reliability Standard.
    663. The Commission disagrees with the Nevada Companies' proposal 
for grandfathering. The Reliability Standards must define the minimum 
functions that are necessary for the Reliable Operation of the Bulk-
Power System. The flexibility described above on how capabilities are 
provided should mitigate any costs incurred to upgrade older centers.
    664. Given the importance to reliability of maintaining situational 
awareness in the event of loss of the primary control center 
operations, the Commission believes that, at a minimum, the three 
requirements--independence from the primary control center, capability 
to operate for a prolonged period corresponding to the time it would 
take to replace the primary control center, and the provision of a 
minimum set of tools and facilities to replicate the critical 
reliability functions of the primary control center--must be included 
as explicit requirements in the Reliability Standard. Other additional 
Requirements may be developed by the Backup Control Task Force for 
inclusion in the Reliability Standard. The Commission directs the ERO 
to develop modifications to the requirements in future revisions to the 
Reliability Standard through the Reliability Standards development 
process.
ii. Which entities should have full backup centers
    665. In the NOPR , the Commission proposed to direct that NERC 
submit a modification to EOP-008-0 that: (1) Provides that the extent 
of the backup capability be consistent with the impact of the loss of 
the entity's primary control center on the reliability of the Bulk-
Power System and (2) includes a Requirement that all reliability 
coordinators have full backup control centers. The Commission also 
requested comments on what other entities, such as balancing 
authorities and large transmission operators, should have full backup 
centers.
(a) Comments
    666. International Transmission, MISO and FirstEnergy state that in 
addition to reliability coordinators, large balancing authorities and 
transmission operators need full backup control centers. MISO states 
that there are certain situations where large generation fleets that 
are controlled centrally would also warrant full backup systems and 
that small entities can operate reliably with less robust systems. 
Further, it argues that the ERO needs latitude to decide from a 
reliability standpoint how much redundancy is needed. FirstEnergy 
states that in place of full backup control facilities it should be 
acceptable to have standing contracts in place to provide backup 
services in the event of a loss of a control center.
    667. NERC states that the proposed directive presumes that the only 
way to achieve highly reliable and independent backup capability to 
perform reliability coordinator functions in an emergency is to have a 
redundant control center. NERC contends that while this may be an 
option, it may not be the only one for achieving the necessary 
reliability objective. NERC proposes that the Reliability Standard be 
modified to define the performance results expected rather than how an 
entity should meet the requirements.
    668. NERC, SoCal Edison and Otter Tail state that the question of 
what other entities should have full backup centers is best addressed 
through the Reliability Standards development process. Otter Tail 
requests that the Commission not require all balancing authorities to 
have full backup centers since the loss of a small balancing 
authority's control center would not have a substantial impact on the 
reliability of the Bulk-Power System. Northern Indiana states that 
requiring transmission operators and balancing authorities to have full 
backup centers would result in significant unnecessary facility 
duplication, at great cost to consumers, and without a material 
increase in reliability.
    669. FirstEnergy comments that the Reliability Standard should not 
require a fully redundant SCADA system for the backup control center 
for balancing authorities or transmission operators because the cost 
would be prohibitive. It states that balancing authorities, 
transmission operators and centrally-located generation owners should 
be permitted to have a single distributed computer system in place to 
diminish the probability of a complete system shutdown due to a natural 
disaster or a single man-made physical act of sabotage.
    670. Nevada Companies also questions whether the significant cost 
of full replication could ever be cost-effective, especially 
considering the very high level of control center reliability achieved 
now with the existing solution of a single control center plus backup 
of critical systems.
(b) Commission Determination
    671. Several commenters agree with the Commission that reliability 
coordinators at a minimum should have full backup control centers. They 
also propose that this requirement be extended to large balancing 
authorities, transmission operators and centrally dispatched generation 
facilities. Others caution on the cost implications of requiring full 
duplication given the very high level of control center reliability 
achieved with the existing technology and backup of critical systems. 
Having carefully considered all the issues raised by commenters and 
taking into account the reliability impacts of loss of primary control 
centers and the role of reliability coordinators as the highest level 
of authority responsible for reliability of the Bulk-Power System, the 
Commission is persuaded that all reliability coordinators must have 
fully redundant independent backup control centers. In response to 
NERC, any proposed modification that is independent from the primary 
center, provides for continuous monitoring and has the full 
functionality of the primary center would satisfy our concerns. Other 
entities, including balancing authorities, transmission operators and 
centrally dispatched generation control centers, must provide for the 
minimum backup capabilities discussed above but may do so through other 
means, such as contracting for these services instead of through 
dedicated backup control centers.
    672. In addition, in response to FirstEnergy's concern regarding 
balancing authorities and transmission operators having fully redundant 
SCADA systems and distributed computer systems, the Commission requires 
the primary and backup capabilities to replicate critical reliability 
functionalities and be independent from the primary control center, 
including telemetered data and control from remote terminal units. This 
can be achieved through a variety of design alternatives, e.g., 
developing a SCADA management platform that will allow telemetered data 
and control to be shared among SCADA systems so that data and control 
is not lost during a SCADA or communications failure. The Commission's 
focus is on function, not design.

[[Page 16485]]

iii. Summary of Commission Determination
    673. Accordingly, the Commission approves Reliability Standard EOP-
0081-0 as mandatory and enforceable. In addition, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to EOP-008-0 
through the Reliability Standards development process that includes a 
Requirement that provides for backup capabilities that, at a minimum, 
must: (1) Be independent of the primary control center; (2) be capable 
of operating for a prolonged period of time, generally defined by the 
time it takes to restore the primary control center; (3) provide for a 
minimum functionality to replicate the critical reliability functions 
of the primary control center; (4) provides that the extent of the 
backup capability be consistent with the impact of the loss of the 
entity's primary control center on the reliability of the Bulk-Power 
System; (5) includes a Requirement that all reliability coordinators 
have full backup control centers and (6) requires transmission 
operators and balancing authorities that have operational control over 
significant portions of generation and load to have minimum backup 
capabilities discussed above but may do so through contracting for 
these services instead of through dedicated backup control centers.
i. Documentation of Blackstart Generating Unit Tests Results (EOP-009-
0)
    674. Proposed Reliability Standard EOP-009-0 deals with 
documentation of blackstart generating unit test results. In the NOPR, 
the Commission proposed to approve EOP-009-0 as mandatory and 
enforceable without modifications.
i. Comments
    675. APPA agrees that EOP-009-0 is sufficient for approval as a 
mandatory and enforceable Reliability Standard. Xcel states that the 
Reliability Standard should provide details on what constitutes a 
blackstart test and FirstEnergy states that EOP-009-0 should be 
consolidated with EOP-007-0 because the Requirements of EOP-009-0 
already exist in EOP-007-0.
ii. Commission Determination
    676. The Commission believes that this Reliability Standard 
sufficiently addresses documentation of blackstart generating unit test 
results. Accordingly, the Commission approves Reliability Standard EOP-
009-0 as mandatory and enforceable.
    677. Two commenters made suggestions for improving the Reliability 
Standard. The Commission directs the ERO to take these suggestions into 
consideration when revising the Reliability Standard through the 
Reliability Standards development process.
5. FAC: Facilities Design, Connections, Maintenance, and Transfer 
Capabilities
    678. The nine Facility (FAC) Reliability Standards address topics 
such as facility connection requirements, facility ratings, system 
operating limits and transfer capabilities. The FAC Reliability 
Standards also establish requirements for maintaining equipment and 
rights-of-way, including vegetation management. The NOPR provided 
direction for seven of the nine FAC Reliability Standards; NERC 
withdrew two others, Reliability Standards FAC-004-0 and FAC-005-0. 
NERC, in its November 15, 2006 filing requests approval of three 
additional FAC Reliability Standards: FAC-010-0, FAC-011-0 and FAC-014-
0. These Reliability Standards are being addressed in a separate 
docket.
a. Facility Connection Requirements (FAC-001-0)
    679. Proposed Reliability Standard FAC-001-0 is intended to ensure 
that transmission owners establish facility connection and performance 
requirements to avoid adverse impacts to the Bulk-Power System. In the 
NOPR, the Commission proposed to approve FAC-001-0 as mandatory and 
enforceable.
i. Comments
    680. APPA agrees with the Commission's proposal to approve FAC-001-
0 as mandatory and enforceable.
ii. Commission Determination
    681. As discussed in the NOPR, the Commission believes that 
Reliability Standard FAC-001-0 is just, reasonable, not unduly 
discriminatory or preferential and in the public interest and approves 
it as mandatory and enforceable.
b. Coordination of Plans for New Generation, Transmission, and End-User 
Facilities (FAC-002-0)
    682. Proposed Reliability Standard FAC-002-0 requires that each 
generation owner, transmission owner, distribution provider, LSE, 
transmission planner and planning authority assess the impact of 
integrating generation, transmission and end-user facilities into the 
interconnected transmission system.
    683. In the NOPR, the Commission proposed to approve Reliability 
Standard FAC-002-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct that NERC submit a modification to 
FAC-002-0 that amends Requirement R1.4 to require evaluation of system 
performance under both normal and contingency conditions by referencing 
TPL-001 through TPL-003.
i. Applicability and Assessment Responsibility
(a) Comments
    684. APPA, Xcel and FirstEnergy state that this Reliability 
Standard is not clear about who will perform the required assessment 
and how many assessments are required under this Reliability Standard. 
APPA requests that the Reliability Standard be clarified to state that 
the required assessment must be performed only by the transmission 
planner and the planning authority. Xcel requests that the Commission 
clarify that only one required assessment needs to be done when new 
facilities are added, and that all the listed entities should 
participate in that single assessment.
    685. FirstEnergy requests that NERC clarify what is considered a 
new facility and asks if, for example, up-rates should be included as 
new facilities. MRO is concerned that the impact of the Commission's 
directive is too broad and may have a substantial affect on those 
individual entities that are responsible for performing the studies; 
MRO asks the Commission to clarify FAC-002-0 to the extent necessary, 
but does not propose a specific change.
    686. Six Cities requests that this Reliability Standard clarify 
that all applicable entities must make available data necessary for all 
other responsible entities to perform the required assessment. Six 
Cities also suggests that the transmission operator be added as an 
entity to which this Reliability Standard is applicable, at least from 
the perspective that it make necessary data available to all other 
entities responsible for assessment. TAPS believes that this 
Reliability Standard seems to assume that the LSE and distribution 
provider actively participate in planning of new facilities in the 
Bulk-Power System. TAPS states that very few LSEs or distribution 
providers have the expertise to perform the tasks outlined in this 
Reliability Standard and that these two entities provide only certain

[[Page 16486]]

data regarding certain new facilities to some or all of the other 
entities identified in this Reliability Standard. TAPS therefore 
believes that it would be unreasonable to require LSEs to provide the 
transmission planning evaluations and assessments called for by R1. 
California Cogeneration believes that the Reliability Standard implies 
that generator owners will perform an independent assessment and if so, 
it believes that such task is impossible, since generators do not have 
the relevant information about the power system to perform such 
evaluations. California Cogeneration believes that the Reliability 
Standard should be clarified so that generator owners cooperate with 
and provide input to the assessment performed by the transmission 
operator and the balancing authority.
    687. FirstEnergy states that both MISO and PJM already have Large 
Generator Interconnection Procedures (LGIP) in place that provide a 
formal process that meets the requirements listed under R1, and asks 
that the Commission state that complying with the interconnection 
agreement and/or OATT satisfies this requirement. MISO states that 
their procedures for coordinating plans for new generation, 
transmission and end-user facilities includes modeling of normal system 
and contingency conditions.
(b) Commission Determination
    688. All of the above commenters request clarification of 
Requirement R1 in the Reliability Standard that states that various 
functional entities ``shall each coordinate and cooperate on its 
assessments with its transmission planner and planning authority.'' 
\259\ The Commission believes that all entities listed in the 
Applicability section have a stake in the performance of the system and 
should have the opportunity to provide input in the assessment under 
R1. The Commission believes that commenters have raised valid concerns 
that, if addressed, would make the Reliability Standard better. The 
wording would allow a number of organizational approaches to achieving 
the goal of performing an analysis. The Commission does not intend to 
limit which organizational approach is used by the entities, only to 
assure that a single competent and collaborative analysis is performed. 
Therefore, the Commission directs the ERO to address these concerns in 
the Reliability Standards development process.
---------------------------------------------------------------------------

    \259\ FAC-002-0.
---------------------------------------------------------------------------

    689. FirstEnergy asks the Commission to state that complying with 
MISO's and PJM's interconnection agreements and/or OATT satisfies 
requirement R1 under this Reliability Standard. We will not make that 
determination here. If FirstEnergy believes that complying with the 
MISO and PJM interconnection procedures meets the applicable 
Reliability Standards, then it should follow those procedures, it 
should not be concerned about violating the Reliability Standard.
ii. Standards of Conduct
(a) Comments
    690. Xcel and MidAmerican believe that the assessment required 
under this Reliability Standard may conflict with the Commission's 
Standards of Conduct \260\ since the assessment requires coordination 
among several different functional groups within a vertically 
integrated public utility. MidAmerican asserts that, since direct 
communication between the generation and transmission entities would 
result in more efficient overall planning, the Commission should 
clarify its intended application of Standards of Conduct restrictions 
on joint planning activities. Xcel asks the Commission to clarify that 
actions taken to comply with this Reliability Standard will not result 
in a transmission provider being in violation of the Standards of 
Conduct.
---------------------------------------------------------------------------

    \260\ Standards of Conduct for Transmission Providers, Order No. 
2004, FERC Stats. & Regs., Regulations Preambles ] 31,155 (2003), 
order on reh'g, Order No. 2004-A, III FERC Stats. & Regs. ] 31,161 
(2004), order on reh'g, Order No. 2004-B, III FERC Stats & Regs. ] 
31,166 (2004).
---------------------------------------------------------------------------

(b) Commission Determination
    691. The Commission disagrees with MidAmerican and Xcel that this 
Reliability Standard may conflict with the Standards of Conduct. This 
type of system assessment is being performed today with the cooperation 
of the entities listed in the Applicability section. Further, we note 
that the Standards of Conduct were designed to address such 
interactions. The entities participating in the assessment effort can 
continue to contribute to this assessment and observe the Standards of 
Conduct at the same time. If any entity finds an area where it believes 
the Standards of Conduct prevent it from cooperating with the 
assessment process, it may seek clarification from the Commission as to 
whether that area of involvement is in conflict with the Standards of 
Conduct.
iii. Reference to TPL Reliability Standards
(a) Comments
    692. While APPA and EEI agree with the Commission's proposal to 
direct NERC to submit a modification to FAC-002-0 that amends 
Requirement R1.4 to require evaluation of system performance under both 
normal and contingency conditions by referencing TPL-001-0 through TPL-
003-0, Entergy disagrees and proposes that evaluation of system 
performance under Reliability Standards TPL-001-0 and TPL-002-0 should 
be sufficient. Entergy states that given the large number of small end-
user requests that transmission operators may receive, expanding the 
scope of Requirement R1.4 may lead to additional work and documentation 
that ultimately will not benefit reliability. First Entergy states that 
the proposed reference to TPL Reliability Standards should be expanded 
to include TPL-001-0 through TPL-004-0.
(b) Commission Determination
    693. The Commission notes that APPA and EEI agree with the 
Commission's proposed directive to NERC to modify FAC-002-0 to require 
evaluation of system performance under both normal and contingency 
conditions by referencing TPL-001-0 through TPL-003-0. The Commission 
also notes that NERC, in response to the Staff Preliminary Assessment, 
has also agreed with the same proposal.\261\ These three TPL 
Reliability Standards cover normal operation, first contingency 
operation and multiple contingency operations respectively. The 
Commission disagrees with Entergy that TPL-001-0 and TPL-002-0 are 
sufficient because it is important to plan for new facilities taking 
into account not only normal circumstances but also contingencies. In 
addition, we note that including TPL-001-0 through TPL-003-0 will 
result in the FAC-002 Reliability Standard being consistent with Order 
No. 2003, which requires interconnecting entities to take into account 
multiple contingencies in interconnection studies. With respect to 
FirstEnergy's suggestion to also include a reference to Reliability 
Standard TPL-004-0, we direct the ERO to consider it through the 
Reliability Standards development process.
---------------------------------------------------------------------------

    \261\ NOPR at P 352.
---------------------------------------------------------------------------

    694. Accordingly, the Commission approves Reliability Standard FAC-
002-0 as mandatory and enforceable. In addition, pursuant to section 
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to FAC-002-0 
through the Reliability Standards development process that amends 
Requirement R1.4 to require evaluation of system performance under both 
normal and contingency conditions by referencing TPL-001 through TPL-
003.

[[Page 16487]]

Further, the Commission also directs the ERO to consider the above 
commenters' concerns through the Reliability Standards development 
process.
c. Transmission Vegetation Management Program (FAC-003-1)
    695. According to NERC, FAC-003-1 is designed to minimize 
transmission outages from vegetation located on or near transmission 
rights-of-way by maintaining safe clearances between transmission lines 
and vegetation, and establishing a system for uniform reporting of 
vegetation-related transmission outages. FAC-003-1 would apply to 
transmission lines operated at 200 kV or higher voltage (and lower-
voltage transmission lines which have been deemed critical to 
reliability by a regional reliability organization). It would require 
each transmission owner to have a documented vegetation management 
program in place, including records of its implementation. Each program 
must be designed for the geographical area and specific design 
configurations of the transmission owner's system.
    696. This Reliability Standard requires a transmission owner to 
define a schedule for and the type (aerial or ground) of right-of-way 
vegetation inspections. In addition, it requires a transmission owner 
to determine and document the minimum allowable clearance between 
energized conductors and vegetation before the next trimming, and it 
specifically provides that ``Transmission-Owner-specific minimum 
clearance distances shall be no less than those set forth in the IEEE 
Standard 516-2003 (IEEE Guide for Maintenance Methods on Energized 
Power Lines).'' \262\
---------------------------------------------------------------------------

    \262\ FAC-003-1 (Requirement R1.2.2).
---------------------------------------------------------------------------

    697. In the NOPR, the Commission proposed to approve Reliability 
Standard FAC-003-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to submit a modification to FAC-
003-1 that: (1) Requires the ERO develop a minimum vegetation 
inspection cycle that allows variation for physical differences and (2) 
removes the general limitation on applicability to transmission lines 
operated at 200 kV and above so that the Reliability Standard applies 
to Bulk-Power System transmission lines that have an impact on 
reliability as determined by the ERO.
i. Applicability
(a) Comments
    698. Entergy agrees with the Commission's proposal and supports 
applying the Reliability Standard to only those lines that have an 
impact on reliability as determined by the ERO, as supported by 
reliability studies using consistent reliability contingency criteria.
    699. LPPC supports using an impact-based definition of the Bulk-
Power System to determine applicability and suggests that the 
definition of significant adverse impact should be determined through 
the NERC process. Further, LPPC asserts that actual facilities meeting 
that criteria should be determined by Regional Entities, which best 
understand the impacts of facilities on the regional system. LPPC notes 
that Regional Entities can continue to use such tools as modeling and 
power flow analyses to determine which facilities are critical to the 
reliability of the Bulk-Power System.
    700. APPA and Avista believe that Regional Entities should 
determine what transmission facilities this standard applies to, since 
Regional Entities have detailed knowledge regarding the transmission 
facilities within their regions. APPA would have the Regional Entities 
create a regional Reliability Standard to do so, subject to ERO review 
for reasonableness and consistency. Avista points out that WECC and the 
other Regional Entities have already reviewed and designated critical 
lower voltage transmission facilities, and the Reliability Standards 
currently apply to such facilities.
    701. MISO asks for clarification with respect to the intent of 
adding transmission lines below 200 kV ``that impact reliability'' and 
whether the included lines are IROL-related facilities \263\ or some 
other facilities. Progress and SERC suggest that it may be appropriate 
to limit the applicability of the Reliability Standard to all lines 
that are operated at 200 kV and above and to operationally significant 
circuits between 100 kV and 200 kV that are elements of IROLs.
---------------------------------------------------------------------------

    \263\ An IROL-related facility is a facility whose outage would 
result in an Interconnection Reliability Operating Limit (IROL) 
violation.
---------------------------------------------------------------------------

    702. California PUC believes that discretion about determining 
which lines are critical to the Bulk-Power System should be left to the 
individual state (working in concert with RTOs and ISOs), which has 
much greater knowledge of what is needed on the local level, rather 
than to NERC or the Regional Reliability Organization.
    703. Progress, SERC, FirstEnergy and Avista argue that 
automatically subjecting lines below 200 kV to Reliability Standard 
FAC-003-1 would increase maintenance, documentation and reporting costs 
and impacts to land owners, but would not necessarily increase the 
reliability of the grid. LPPC does not object to eliminating the 200 kV 
bright line threshold, but believes that extending vegetation 
management practices to all facilities of 100 kV and above would 
unnecessarily extend the scope of the vegetation management 
requirements, creating large cost increases for many utilities without 
creating a material increase in the reliability of the Bulk-Power 
System. FirstEnergy recommends that if the voltage level is lowered, 
implementation, especially for reporting requirements, should be spread 
over at least one year. Similarly, Xcel asks the Commission to allow 
flexibility in complying with this Reliability Standard for lower-
voltage facilities that previously were not subject to this Reliability 
Standard.
    704. EEI maintains that not changing this Reliability Standard 
would best maintain reliability, since removing the existing 200 kV 
threshold requirement could inadvertently expose the Bulk-Power System 
to a new set of risks. SoCal Edison argues that the Reliability 
Standard already covers transmission lines rated less than 200 kV, 
because Requirement 4.3 of FAC-003-1 states that this Reliability 
Standard ``shall apply to all transmission lines operated at 200 kV and 
above and to any lower voltage lines designated by the regional 
reliability organization as critical to the reliability of the electric 
system in the region.''
    705. APPA opposes the Commission's proposal to direct NERC to 
change the applicability of this Reliability Standard. APPA argues that 
the Commission should deal with this concern by having NERC reevaluate 
the Reliability Standard. National Grid argues that expanding the 
applicability of Reliability Standards would not be appropriate because 
it could dramatically change the meaning of the Reliability Standards 
and would undermine the Reliability Standard development process which 
yielded the careful balances struck in developing the standards.
    706. NERC argues that the Commission's proposed modification should 
be vetted through the Reliability Standards development process to 
better understand what will be gained in terms of impacts to the 
reliability of the Bulk-Power System. NERC notes that the current 
applicability of the Reliability

[[Page 16488]]

Standard to 200 kV and above transmission lines was debated extensively 
by the industry, and any change to this requirement should be vetted 
again.
(b) Commission Determination
    707. We will not direct NERC to submit a modification to the 
general limitation on applicability as proposed in the NOPR. However, 
we will require the ERO to address the proposed modification through 
its Reliability Standards development process. As explained in the 
NOPR, the Commission is concerned that the bright-line applicability 
threshold of 200 kV will exclude a significant number of transmission 
lines that could impact Bulk-Power System reliability. Although the 
regional reliability organizations are given discretion to designate 
lower voltage lines under the proposed Reliability Standard, none have 
designated any operationally significant lines even though there are 
lower voltage lines involving IROL as suggested by Progress and SERC. 
We continue to be concerned that this approach will not prospectively 
result in the inclusion of all transmission lines that could impact 
Bulk-Power System reliability. In proposing to require the ERO to 
modify the Reliability Standard to apply to Bulk-Power System 
transmission lines that have an impact on reliability as determined by 
the ERO, we did not intend to make this Reliability Standard applicable 
to fewer facilities than it currently is with the 200 kV bright line 
applicability, but to extend the applicability to lower-voltage 
facilities that have an impact on reliability. We support the 
suggestions by Progress Energy, SERC and MISO to limit applicability to 
lower voltage lines associated with IROL and these suggestions should 
be part of the input to the Reliability Standards development process. 
Similarly, the ERO should evaluate the suggestions proposed by LPPC, 
APPA and Avista.
    708. California PUC suggests that states should have discretion 
over what lines are critical to Bulk-Power System reliability. The 
Commission has been given the responsibility to approve Reliability 
Standards that assure the Reliable Operation of the Bulk-Power System, 
including which facilities are covered by the Reliability Standards. We 
cannot delegate that responsibility as proposed by California PUC. 
Further, since many transmission facilities traverse multiple states, 
we are concerned that this proposal could result in the Reliability 
Standard applying to a section of a line in one state but not applying 
to the same line in a neighboring state. Since a vegetation-related 
outage affects all customers connected to that transmission line, 
customers in both states could potentially have lower reliability as a 
result of one state having a less stringent standard than another.
    709. Avista, LPPC, Progress and SERC raise concerns about the cost 
of implementing this Reliability Standard if the applicability is 
expanded to lower-voltage facilities. We recognize these concerns, and 
this was one of the reasons we proposed to apply this Reliability 
Standard to Bulk-Power System transmission lines that have an impact on 
reliability as determined by the ERO. We recognize that many commenters 
would like a more precise definition for the applicability of this 
Reliability Standard, and we direct the ERO to develop an acceptable 
definition that covers facilities that impact reliability but balances 
extending the applicability of this standard against unreasonably 
increasing the burden on transmission owners.
    710. FirstEnergy and Xcel suggest that if the applicability of this 
Reliability Standard is expanded, the Commission should allow 
flexibility in complying with this Reliability Standard for lower-
voltage facilities, or allow lower-voltage facilities one year before 
the Reliability Standard is implemented. The ERO should consider these 
comments when determining when it would request that the modification 
of this Reliability Standard to go into effect.
    711. In response to EEI's concerns that removing the existing 200 
kV threshold could expose the Bulk-Power System to a new set of risks, 
we clarify that we are not immediately modifying this Reliability 
Standard. Instead, it will go into effect as written and the ERO will 
revise it through the Reliability Standards development process, with 
the expectation that the applicability of this Reliability Standard 
will expand to include additional facilities that impact reliability 
that currently are not covered by this Reliability Standard. A 
modification that reduces the applicability of this Reliability 
Standard would not meet the Commission's directives. In response to 
SoCal Edison's argument that the Reliability Standard already addresses 
the Commission's concerns, the Commission agrees that while there 
appears to be a mechanism for inclusion of additional lines, none have 
been included. This lack of inclusion is in spite of the evidence that 
some lower voltage lines can have significant impacts on the Bulk-Power 
System, including IROLs and SOLs.
    712. In response to APPA, NRECA and NERC we agree that the proposed 
modifications should be vetted through the Reliability Standards 
development process. The Commission's goal is to promote the Reliable 
Operation of the Bulk-Power System by including all of those entities 
necessary to comply with this Reliability Standard. We believe that 
requiring the Reliability Standard to include a greater number of 
entities and exclude those that will not affect reliability will more 
effectively sustain reliability than an overly exclusive list of 
applicable entities.
ii. Inspection Cycles
    713. In the NOPR, the Commission proposed to direct NERC to submit 
a modification to FAC-003-1 that requires the ERO to develop a minimum 
vegetation inspection cycle that allows variation for physical 
differences.
(a) Comments
    714. FirstEnergy states that a designation of a minimum annual 
inspection cycle is appropriate and the method of inspection (aerial or 
by ground) should be left to the transmission owner. Dominion cautions 
that if there is a requirement for annual inspections, it should be 
flexible and allow for different approaches to transmission line 
inspections.
    715. APPA, Entergy, EEI, LPPC, Progress Energy, SERC and SoCal 
Edison disagree with the Commission's proposal to require the ERO to 
set minimum vegetation inspection cycles that allow for physical 
differences. APPA, Entergy and LPPC say that, instead of proposing the 
development of a Reliability Standard for minimum vegetation inspection 
cycles, the Commission should permit the transmission system owner or 
local utility to determine the inspection cycle best suited for its 
system and adhere to that cycle, with compliance enforcement performed 
by the Regional Entities and the ERO.
    716. Progress Energy and SERC believe that the Reliability Standard 
as written provides flexibility regarding vegetation inspection cycles 
and that the Commission should not impose requirements on the ERO to 
develop minimum inspection intervals on a continent with such regional 
diversity in climate and vegetation. In addition, Progress Energy 
argues that, where a particular region is heavily forested and has 
heavy rainfall along with extended or year round growing seasons, a 
``back stop'' minimum inspection frequency could lead transmission 
owners to conduct inspections less frequently than what the local 
conditions require, which would lead to a lowest common denominator 
Reliability Standard. This

[[Page 16489]]

could result in a transmission owner complying with the Reliability 
Standard while not adequately protecting the reliability of that 
region's transmission system.
    717. Progress Energy and SERC argue that, since the performance 
metrics in FAC-003-1 require reporting of applicable transmission 
interruptions caused by vegetation, the compliance process associated 
with this Reliability Standard should appropriately identify 
transmission owners' inspection cycles that are not adequate, and the 
ERO can use its authority to remedy any vegetation-related outage that 
is attributed to the transmission owner's inspection frequency.
    718. SoCal Edison states that transmission owners are already 
obligated by Requirement R1.1 to establish a minimum vegetation 
inspection schedule that allows adjustment for changing conditions. 
SoCal Edison believes that the best measure of an effective 
transmission vegetation management program is whether or not tree-to-
line contacts are occurring. SoCal Edison recommends the Commission 
rescind the two proposed directives and order no further revisions to 
FAC-003-1 until such time as Reliability Standard is deemed 
unenforceable by the ERO or is not otherwise achieving its stated 
goals.
    719. APPA and Progress Energy state that a minimum vegetation 
inspection cycle could result in an undue financial burden for some 
regions of the country, because they would be forced into a minimum 
cycle that might be inappropriate for their own region. For example, 
Progress Energy states that, where a particular region is arid, 
sparsely forested or has a minimum growing season, a ``back stop'' 
minimum could require a more frequent interval than is realistically 
needed. This would result in increased and unnecessary costs to the 
transmission owner and its customers without providing a comparable 
increase in reliability. EEI believes that a minimum inspection cycle 
will add nothing to the strength of the existing practices and could 
add a requirement that is not merited by actual circumstances in many 
locations.
(b) Commission Determination
    720. The Commission is concerned about minimizing outages and 
supports a realistic inspection cycle. In the NOPR, the Commission 
proposed a minimum inspection cycle that takes account of physical 
differences as one way to address this concern. However, we recognize 
that there may be other options to achieve the same reliability goal. 
For example, the ERO could determine whether a prepared company-
tailored inspection cycle is appropriate given the physical and 
geographic factors and, through audits, inspect individual vegetation 
management programs for compliance.
    721. While the Commission disagrees that incorporating a backstop 
would lead to a lowest common denominator Reliability Standard, the 
Commission is dissuaded from requiring the ERO to create a backstop 
inspection cycle at this time. Instead, the Commission agrees that an 
entity's vegetation management program should be tailored to 
anticipated growth in the region and take into account other 
environmental factors. The goal is to assure that transmission owners 
conduct inspections at reasonable intervals. In the Commission's 
Vegetation Management Report, we found that many entities performed 
aerial or ground inspections less than every three years or even ``as 
needed.'' \264\
---------------------------------------------------------------------------

    \264\ Utility Vegetation Management and Bulk Electric 
Reliability Report at 10-11, available at http://www.ferc.gov/industries/electric/indus-act/reliability/2004.asp (Vegetation 
Management Report).
---------------------------------------------------------------------------

    722. The Commission continues to be concerned with leaving complete 
discretion to the transmission owners in determining inspection cycles, 
which limits the effectiveness of the Reliability Standard. 
Accordingly, the Commission directs the ERO to develop compliance audit 
procedures, using relevant industry experts, which would identify 
appropriate inspection cycles based on local factors. These inspection 
cycles are to be used in compliance auditing of FAC-003-1 by the ERO or 
Regional Entity to ensure such inspection cycles and vegetation 
management requirements are properly met by the responsible entities.
iii. Minimum Clearances on National Forest Service Lands
    723. In the NOPR, the Commission did not propose to modify the 
ERO's general approach with respect to clearances. However, the 
Commission expressed its belief that any potential issues regarding 
minimum clearances on National Forest Service (Forest Service) lands 
should be dealt with on a case-by-case basis. The Commission requested 
comments on whether another approach would be more appropriate to 
address this issue.
(a) Comments
    724. APPA believes that a case-by-case approach may have to be 
employed, since Forest Service lands are located all across the country 
and have different regional characteristics. APPA notes that U.S. Fish 
and Wildlife Service personnel have begun to take action regarding 
vegetation management on non-federal lands, and reports that APPA 
members have been told by U.S. Fish and Wildlife personnel to refrain 
from cutting vegetation at certain times of the year in the absence of 
an imminent reliability threat. APPA concludes that this information 
conflicts with specifying minimum nationwide vegetation inspection/
cutting cycles and clearances. In addition, APPA requests clarification 
of the Commission interpretation ``we interpret the FAC-003-1 to 
require trimming that is sufficient to prevent outages due to 
vegetation management practices under all applicable conditions.''
    725. Several commenters express concern about the Commission's 
position that any potential issues regarding minimum clearances on 
National Forest Service lands should be dealt with on a case-by-case 
basis.\265\ EEI, Progress Energy and SERC believe that this approach is 
inconsistent with the Reliability Standard's intent to use consistent 
approaches in setting minimum vegetation clearance distances on both 
private and public lands and the Commission's statement that this 
Reliability Standard requires minimum clearances that are ``sufficient 
to prevent outages due to vegetation management practices under all 
applicable conditions.'' \266\ Therefore, International Transmission, 
EEI, LPPC, Progress Energy and SERC assert that Reliability Standard 
FAC-003-1 should be applicable to all responsible entities including 
those with transmission on both private and public lands because 
consistency is the only way to provide a uniform and reliable 
electrical system. Dominion suggests the Commission defer to NERC and 
the stakeholder process to develop specifications for clearances.
---------------------------------------------------------------------------

    \265\ See, e.g., EEI, Energy, International Transmission, 
Progress Energy, SERC, LPPC and MISO.
    \266\ The NOPR states that ``Accordingly, we interpret the FAC-
003-1 to require trimming that is sufficient to prevent outages due 
to vegetation management practices under all applicable conditions* 
* *'' NOPR at P 380.
---------------------------------------------------------------------------

    726. Progress Energy and SERC note that EEI and certain federal 
agencies \267\ have jointly addressed the issue of consistency in 
vegetation management work on federal lands, and developed a memorandum 
of understanding (Vegetation MOU) which sets the framework for managing 
vegetation on transmission line rights-of-way under

[[Page 16490]]

Federal agency jurisdiction.\268\ Progress Energy and SERC recommend 
using the EEI's Vegetation MOU framework for managing vegetation on 
transmission line rights-of-way under federal agency jurisdiction 
rather than the case-by-case approach proposed in the NOPR. LPPC 
recommends creating a bright-line when it comes to utilities' 
obligations (and rights) for trimming vegetation located on Forest 
Service lands. Avista and Portland General ask that the Vegetation MOU 
be affirmed by the Commission and permitted to govern transmission line 
rights-of-ways located on lands managed by federal land management 
agencies.
---------------------------------------------------------------------------

    \267\ Forest Service, Bureau of Land Management, Fish & Wildlife 
Service, National Park Service, and U.S. Environmental Protection 
Agency.
    \268\ The Vegetation MOU is available at http://www.eei.org/industry_issues/environment/land/vegetation_management/EEI_MOU_FINAL_5-25-06.pdf.
---------------------------------------------------------------------------

    727. SoCal Edison believes that transmission owners should be 
allowed the latitude to establish measures/procedures for less rigid 
tree-to-line clearances in response to state and federal agency demands 
or requests but is concerned that these measures/procedures will prove 
to be of little or no value in the event of an ERO investigation into a 
tree-to-line contact occurring within national/state forestry 
boundaries or on private property.
    728. California PUC points out that California already has 
requirements applicable to minimum vegetation clearance, and that the 
Commission must take care to assure that any mandatory Reliability 
Standard does not preempt the ability of California (and other states 
with similar state standards) to impose stricter requirements that have 
no adverse impacts on reliability.
    729. FirstEnergy states that the standard should define rights-of-
way to encompass the required clearance area instead of the 
corresponding legal land rights. Some rights-of-way may be larger to 
accommodate future needs and therefore may exceed clearances needed for 
existing lines. FirstEnergy believes that Reliability Standards should 
not require clearing entire rights-of-way when the required clearance 
for existing lines does not take up the entire right-of-way.
(b) Commission Determination
    730. As proposed in the NOPR, the Commission approves Reliability 
Standard FAC-003-1 with no proposed modification on the issue of 
clearances. The Commission reaffirms its interpretation that FAC-003-1 
requires sufficient clearances to prevent outages due to vegetation 
management practices under all applicable conditions. As to APPA's 
requests for clarification concerning the term ``under all applicable 
conditions,'' the Reliability Standard already addresses this issue in 
Requirement R3.2 by allowing for exceptions for natural disasters 
(including wind shears and major storms) that cause vegetation to fall 
into the transmission lines from outside the ROW. The Commission 
therefore finds that no clarification is required in response to APPA.
    731. The Commission agrees that ownership of the land does not 
change the impact of a vegetation-related outage on the Bulk-Power 
System. However, the present Reliability Standard leaves the 
determination and documentation of ``clearance 1'' to transmission 
owners. As such, there are no specific clearances, or criteria/
procedures to develop clearances, before the Commission for approval. 
What is in front of the Commission relative to ``locations on the 
right-of-way where the Transmission Owner is restricted from attaining 
the clearances specified in Requirement R1.2.1'' is addressed in 
Requirement R1.4. Requirement R1.4 states that ``Each Transmission 
Owner shall develop mitigation measures to achieve sufficient 
clearances for the protection of the transmission facilities when it 
identifies locations on the right-of-way where the Transmission Owner 
is restricted from attaining the clearances specified in Requirement 
R1.2.1.'' This Requirement addresses the instances when an entity 
cannot attain the clearances that it needs on land that it controls. 
Since there are multiple mitigation measures that the entity can employ 
to achieve the goal of preventing outages due to vegetation management 
practices, the Commission has stated that any potential issues 
regarding minimum clearances on Forest Service lands should be dealt 
with on a case-by-case basis.
    732. Avista and Portland General ask the Commission to endorse the 
Vegetation MOU. The Commission reiterates its direction that the 
minimum clearances must be sufficient to avoid any sustained 
vegetation-related outages for all applicable conditions. The 
Vegetation MOU references IEEE 516 as the only way to determine 
applicable minimum clearances. The Commission declines to endorse the 
use of IEEE 516 as the only minimum clearance because it is intended 
for use as a guide by highly-trained maintenance personnel to carry out 
live-line work using specialized tools under controlled environments 
and operating conditions, not for those conditions necessary to safely 
carry out vegetation management practices.\269\ Further, the allowable 
clearances in the IEEE standard are significantly lower than those 
specified by the relevant U.S. safety codes. As such, use of IEEE 
clearance provision as a basis for minimum clearance prior to the next 
tree trimming as a Requirement in vegetation management is not 
appropriate for safety and reliability reasons. For example, the IEEE 
Standard 516-2003 specifies a 2.45-foot clearance from a live conductor 
for the 120 kV voltage class,\270\ whereas the ANSI Z-133 standard 
specifies 12 feet, 4 inches as the approach distance for the 115 kV 
voltage class.\271\
---------------------------------------------------------------------------

    \269\ Controlled environments and operating conditions include 
clear days without precipitation, high winds or lightning.
    \270\ Institute of Electrical and Electronics Engineers, Inc. 
(IEEE) Standard 516-2003, IEEE Guide for Maintenance Methods at 20.
    \271\ ANSI Z133, American National Standards Institute Standard 
for Tree Care Operations--Pruning, Trimming, Repairing, Maintaining 
and Removing Trees, and Cutting Brush--Safety Requirements.
---------------------------------------------------------------------------

    733. Accordingly, the Commission directs the ERO to develop a 
Reliability Standard that defines the minimum clearance needed to avoid 
sustained vegetation-related outages that would apply to transmission 
lines crossing both federal land and non-federal land. While this 
consensus is developed, the Commission directs the ERO to address any 
potential issues regarding mitigation measures needed to assure these 
minimum clearances on Forest Service lands are appropriate on a case-
by-case basis. The Commission also directs the ERO to collect outage 
data for transmission outages of lines that cross both federal and non-
federal lands, analyze it, and use the results of this analysis and 
information to develop a Reliability Standard that would apply to 
transmission lines crossing both federal and non-federal land.
    734. In regard to California PUC's concern about its ability to 
impose stricter requirements on vegetation clearances, the Commission 
notes that section 215(i)(3) of the FPA states that nothing in section 
215 shall be construed to preempt the authority of a state to take 
action to ensure the reliability of electric service within that state, 
as long as the action is not inconsistent with any Reliability 
Standard. Therefore, the State of California may set its own vegetation 
management requirements that are stricter than those set by the 
Commission as long as they do not conflict with those set by the 
Commission. Further, the Commission notes that once a Reliability 
Standard is established, California PUC can develop stricter rules to 
be applied within the

[[Page 16491]]

state of California, and if it wants them to be enforceable under 
section 215 of the FPA, could submit those Reliability Standards to the 
ERO and the Commission for approval as a regional difference.
    735. FirstEnergy suggests that rights-of-way be defined to 
encompass the required clearance areas instead of the corresponding 
legal rights, and that the standards should not require clearing the 
entire right-of-way when the required clearance for an existing line 
does not take up the entire right-of-way. The Commission believes this 
suggestion is reasonable and should be addressed by the ERO. 
Accordingly, the Commission directs the ERO to address this suggestion 
in the Reliability Standards development process.
iv. Summary of Commission Determinations
    736. The Commission approves FAC-003-1 as mandatory as enforceable. 
In addition, while we do not direct the ERO to submit a modification to 
the general limitation on applicability as proposed in the NOPR, we 
require the ERO to address the proposed modification through its 
Reliability Standards development process as discussed above. Further, 
while the Commission is dissuaded from requiring the ERO to create a 
backstop inspection cycle at this time, it directs the ERO to develop 
compliance audit procedures to identify appropriate inspection cycles 
based on local factors. These inspection cycles are to be used in 
compliance auditing of FAC-003-1 by the ERO or Regional Entity to 
ensure such inspection cycles and vegetation management requirements 
are properly met by the responsible entities. Finally, the Commission 
directs the ERO to develop a Reliability Standard through the 
Reliability Standard development process that defines the minimum 
clearance needed to avoid sustained vegetation-related outages that 
would apply to transmission lines crossing both federal land and non-
federal land. While this consensus is developed, the Commission directs 
the ERO to address any potential issues regarding mitigation measures 
needed to assure these minimum clearances on Forest Service lands are 
appropriate on a case-by-case basis. The Commission also directs the 
ERO to collect outage data for transmission outages of lines that cross 
both federal and non-federal lands, analyze it, and use the results of 
this analysis and information to develop a Reliability Standard that 
would apply to transmission lines crossing both federal and non-federal 
land.
d. Facility Ratings Methodology (FAC-008-1)
    737. FAC-008-1 requires each transmission owner and generation 
owner to develop a facility rating methodology for its facilities, 
which should consider manufacturing data, design criteria (such as 
IEEE, ANSI or other industry methods), ambient conditions, operating 
limitations and other assumptions. This methodology is to be made 
available to reliability coordinators, transmission operators, 
transmission planners and planning authorities who have responsibility 
in the same areas where the facilities are located for inspection and 
technical reviews.
    738. In the NOPR, the Commission proposed to approve Reliability 
Standard FAC-008-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to develop a modification to 
FAC-008-1 through the Reliability Standards development process that 
requires transmission and generation facility owners to: (1) Document 
underlying assumptions and methods used to determine normal and 
emergency facility ratings; (2) develop facility ratings consistent 
with industry standards developed through an open process such as IEEE 
or CIGRE and (3) identify the limiting component(s) and define the 
increase in rating based on the next limiting component(s) for all 
critical facilities.
i. Methodology Used To Determine Facility Ratings and Documentation of 
Underlying Assumptions
(a) Comments
    739. EEI, Valley Group, MidAmerican and TANC support the 
Commission's proposal to require additional documentation as a 
reasonable means to provide more transparency and consistency. EEI 
suggests that this requirement could be accommodated with a provision 
for the disclosure of such information upon request by a registered 
user, owner or operator. TANC supports the Commission's proposal to not 
require a uniform facility rating methodology and recommends that the 
Commission adopt a policy that provides for each transmission owner and 
generation owner to develop and document a facility rating methodology, 
which is consistent with industry methodologies, for their facilities. 
TANC also states that the methodology used for developing facility 
ratings should include a description of and justification for all of 
the assumptions. Valley Group states that it is extremely important 
that the underlying assumptions and methods are documented and known to 
all parties. Valley Group maintains that this will also ensure that the 
rating assumptions used by operating and planning functions are 
consistent with each other. Valley Group emphasizes that making these 
assumptions open is important, especially regarding paths between 
different transmission owners, to ensure that transmission owners 
cannot exercise market power. It argues that open assumptions will also 
provide rational grounds for dispute resolution.
(b) Commission Determination
    740. As EEI, TANC, Valley Group and MidAmerican discuss in their 
comments, the Commission's proposal to modify FAC-008-1 to require 
additional documentation supports the Commission's goals of improving 
uniformity and transparency in the facility ratings process. EEI's 
suggestion that having this information available for review upon 
request of a registered user, owner or operator should be considered by 
the ERO in its Reliability Standards development process. As proposed 
in the NOPR, the Commission directs the ERO to submit a modification to 
FAC-008-1 that requires transmission and generation facility owners to 
document underlying assumptions and methods used to determine normal 
and emergency facility ratings. As stated in the NOPR, the Commission 
believes that this added transparency will allow customers, regulators 
and other affected users, owners and operators of the Bulk-Power System 
to understand how facility owners set facility ratings through 
differing methods that provide equivalent results.
ii. Rating Facilities Consistent with Industry Standards Developed 
Through an Open Process such as IEEE and CIGRE
(a) Comments
    741. The Valley Group states that the Commission correctly 
identifies IEEE and CIGRE as examples of open process methodologies 
suitable for overhead transmission line ratings calculations. It claims 
that IEEE and CIGRE are the only methodologies which make their 
algorithms available to everybody, and clearly document their 
assumptions. Valley Group notes that both of these methodologies will 
undergo a revision for accuracy regarding calculations for high 
temperatures and high current densities in the next two years, which 
may lead in some cases to slightly lower

[[Page 16492]]

line ratings, although the changes are not expected to be substantial.
    742. APPA suggests that the proposal to rate facilities consistent 
with industry methodologies developed through an open process such as 
IEEE and CIGRE should be considered in the ERO's Reliability Standards 
development process rather than ordered by the Commission. LPPC asks 
the Commission to require only that facility ratings be consistent with 
good utility practice. According to LPPC, to the extent facility rating 
methodologies need to be more prescriptive than good utility practice, 
the details must be spelled out in the ERO Reliability Standards 
themselves, not by reference to other unspecified industry 
methodologies. LPPC believes that it would be poor policy for the 
Commission to endorse these methodologies since it would be impossible 
to police the processes by which such organizations develop their 
methodologies. MidAmerican states that the Commission should recognize 
that the proposal to require facility ratings be consistent with 
industry methodologies developed through an open process is potentially 
problematic, noting that certain aspects of the development of facility 
ratings are based on industry standards that are not developed through 
an open process, such as information provided by engineering textbooks 
or manufacturer information that is not specifically referenced in any 
current standard. MidAmerican recommends that the Commission delete the 
requirement that facility ratings be ``developed through an open 
process such as IEEE or CIGRE'' or add other sources that the 
Commission would find appropriate, such as the results of accepted 
scientific and engineering investigations and common sense. MRO 
requests that the Commission clarify whether its directive to modify 
FAC-008-1 to develop facility ratings consistent with industry 
standards developed through an open process such as IEEE or CIGRE would 
allow for legitimate regional differences such as climate, terrain or 
population density.
(b) Commission Determination
    743. In the NOPR, the Commission stated, ``While not proposing to 
mandate a particular methodology, we do propose that the methodology 
chosen by a facility owner be consistent with industry standards 
developed through an open process such as IEEE or CIGRE.'' \272\ These 
processes have been validated through actual testing and have been 
shown to provide appropriate results. Information from engineering 
textbooks, common sense or manufacturer information would be part of 
the underlying assumptions. The Commission's intent in the NOPR was to 
require that FAC-008-1 be modified to require that facility ratings be 
developed consistent with industry standards developed through an open, 
transparent and validated process. The Commission agrees with Valley 
Group that IEEE and CIGRE are two examples of such processes and 
disagrees with LPPC that reference to industry standards is poor 
policy. Industry standards that have been verified by actual testing 
are appropriate. However, the Commission agrees with MidAmerican that 
IEEE and CIGRE are just two examples of such bodies; any other open 
process that has been technically validated for its provision of 
accurate, consistent ratings is also acceptable. The ERO should 
consider the concerns raised by LPPC and MRO in its Reliability 
Standards development process, and is hereby directed to do so. The 
Commission does not expect there to be any regional differences because 
the only differences should be from different underlying assumptions 
that are not defined by the Reliability Standard.
---------------------------------------------------------------------------

    \272\ NOPR at P 404.
---------------------------------------------------------------------------

iii. Identify the Limiting Component(s) and Define for All Critical 
Facilities the Rating Based on the Next Limiting Component Within the 
Same Facility
(a) Comments
    744. TANC maintains that the rating information provided by the 
transmission owners and generator owners should include additional 
information about all of the limiting components of the elements (e.g., 
transmission lines, transformers, etc.) for all critical facilities. 
Access to such information will enable neighboring systems to 
accurately study the effects of other facilities on their own systems 
and determine the critical elements for increasing facility ratings.
    745. Valley Group states that identifying the limiting elements is 
an excellent objective for reliability enhancement, but notes that its 
granularity must be limited to major elements of the circuits, such as 
transformers and breakers, while treating the transmission lines as 
single elements. Valley Group also notes that, of the two examples 
discussed in the NOPR, the example regarding relay settings is 
technically well justified, whereas rating the line based on a single 
limiting span is generally impractical because line design engineers 
add to the National Electric Safety Code minimum requirements ``safety 
buffers,'' which vary depending on their confidence in the accuracy of 
design calculations.
    746. APPA is concerned about the possible ``unintended 
consequences'' of this modification and questions whether this proposed 
Requirement can be done as a practical matter; how many critical 
facilities and limiting components would have to be modeled to meet 
such a Requirement; and whether the cost of such modeling is justified 
by the reliability benefits. Dynegy, MISO and Wisconsin Electric also 
oppose this requirement because it is ambiguous, the additional work 
required to identify the increase in rating based on the next limiting 
component(s) is unwarranted and potentially costly, and the need for 
any such specific information is questionable. Dynegy and Wisconsin 
Electric do not believe there is a widespread need for this type of 
information and recommend that the need for it be explored on a case-
by-case basis rather than including a global requirement in the 
standards.
    747. Dynegy, FirstEnergy and MISO state that it is not clear what 
specific criteria would be used to define ``critical facilities'' and 
``limits.'' EEI also states that developing a practical definition of 
``critical facilities'' presents a challenge, and that compliance would 
require the analysis of possibly hundreds of thousands of ``limiting'' 
transmission elements to determine whether a limit is of primary 
concern or is contingent on the status of other nearby elements or 
system conditions at a particular time. EEI suggests that, rather than 
requesting that the industry develop a definition, it may be more 
useful for the Commission to recommend that the industry develop a set 
of high-level criteria that could be used to identify those 
transmission elements that create significant potential limits that are 
independent of other factors and considerations.
    748. EEI and TVA assert this recommendation does not seem to be 
intended to enhance reliability but to provide additional commercial 
information to the market, and may not be appropriate to include in a 
Reliability Standard. Portland General further points out that this 
information can be obtained from a transmission provider by submitting 
a transmission or interconnection request when ATC is not posted or not 
available. TVA comments that, since the focus of this proceeding is the 
Reliable Operation of the Bulk-Power System, changes to a proposed 
Reliability Standard, such as FAC-008-1, that appear designed to 
promote maximum commercial use of the grid are unwarranted in this

[[Page 16493]]

proceeding and could jeopardize, rather than further, reliable 
transmission system operations.
    749. MRO seeks clarification about whether the proposed 
modification will require that all limiting facilities elements be 
published. MRO believes that serious confidentiality issues are raised 
due to the security-sensitive nature of the information and urges the 
Commission not to require the publication of such information.
    750. Dominion states that the Commission should exclude from this 
requirement facilities that are covered under an open, regional 
transmission expansion planning process, such as the Regional 
Transmission Expansion Plan process in PJM, where any interested party 
can be involved in the studies and determine what the limitations are 
and what could be done to increase transmission capacity.
    751. International Transmission states that, if the Commission were 
to require defining the increase in facility rating based on the next 
limiting element, it should restrict such application to transmission 
elements where the conductor itself is not the limiting element. 
International Transmission explains that in cases where the line must 
be completely rebuilt, it would not be feasible to estimate the 
increase in facility rating, since the new line could be specified to 
carry virtually any amount of power.
    752. MISO questions how a generator operator or generation owner 
would identify the increase in rating based on the next most limiting 
component(s) associated with generator output. FirstEnergy believes 
that this modification should recognize that generators may need to 
rely on transmission owners to point out facilities that are more 
limiting than the generator facilities.
    753. Manitoba's technical experts disagree with the Preliminary 
Staff Assessment regarding FAC-008-1. The Reliability Standard properly 
places the responsibility of determining facility ratings with the 
facility owners. Manitoba also states that, since this Reliability 
Standard requires that the ``Facility Rating shall be equal to the most 
limiting applicable Equipment Rating of the individual equipment that 
comprises that Facility,'' information on the next limiting component 
is already identified. Contrary to the Commission's view, Manitoba does 
not believe it would be appropriate in this Reliability Standard to 
identify the increase in rating for all critical facilities based on 
the next limiting component. In a networked system, there may be other 
limitations that set the current carrying capability of the critical 
facility.
    754. Manitoba further notes that the Commission proposal may lead 
to international conflicts in Reliability Standards. Manitoba states 
that a mandated change to FAC-008-1, which forces an entity to accept 
facility ratings beyond its risk tolerance, would be grounds for 
Manitoba to recommend that the provincial government of Manitoba not 
approve this Reliability Standard because it would degrade reliability.
    755. APPA suggests that the proposal to identify the limiting 
component and define for all critical facilities the rating based on 
the next limiting component be considered in the ERO's Reliability 
Standards development process rather than ordered by the Commission.
(b) Commission Determination
    756. The Commission agrees with TANC that this modification would 
provide useful information to neighboring systems and users, owners and 
operators of the Bulk-Power System. The Commission also agrees with 
Valley Group that identifying the limiting elements of facilities 
enhances reliability by providing operators specific information about 
the limiting elements and therefore allowing them to assess the risks 
associated with circuit loadings.
    757. In response to the comments of APPA, Dynegy, EEI, MISO and 
Wisconsin Electric, the Commission clarifies that this Reliability 
Standard and the Commission's proposed modification apply to 
facilities. As defined in the NERC glossary, a facility is ``a set of 
electrical equipment that operates as a single Bulk Electric System 
Element \273\ (e.g., a line, a generator, a shunt compensator, 
transformer, etc.).'' The most limiting component in a facility 
determines its rating, just like the rating of a chain is determined by 
the weakest link. The Commission's proposed modification would require 
identifying and documenting the limiting component for all facilities 
and the increase in rating if that component were no longer the most 
limiting component; in other words, the rating based on the second-most 
limiting component. The Commission further clarifies that this 
Reliability Standard will require this additional thermal rating 
information only for those facilities for which thermal ratings cause 
the following: (1) An IROL; (2) a limitation of TTC; (3) an impediment 
to generation deliverability or (4) an impediment to service to major 
cities or load pockets.
---------------------------------------------------------------------------

    \273\ An element is made up of one or more components.
---------------------------------------------------------------------------

    758. EEI and TVA raise concerns that this modification promotes 
commercial use of the grid rather than ensuring Reliable Operation of 
the Bulk-Power System, and relates more to transmission access than 
reliable operations. The Commission disagrees that this modification 
relates primarily to transmission access. When the transmission 
operators know which component within the transmission element is 
limiting they have more information to inform their decisions about how 
to provide for the Reliable Operation of the Bulk-Power System. Our 
proposed modification does not require any entity to invest in 
equipment to increase ratings of any facility; it simply requires the 
next limiting component of each facility to be identified in order to 
understand what components are causing the limits that are to be used 
in reliability mitigation assessments. The identification of the first 
limiting component is already an inherent requirement in the existing 
rating process. As clarified above, the modification to identify an 
increase in rating of the transmission element that would result from 
removing the first limitating component applies only to critical 
facilities whose thermal ratings have been reached causing an SOL or 
IROL condition. As Dominion highlights in its comments, this 
information is already identified in the planning processes of some 
RTOs and ISOs.
    759. In response to the concerns raised by EEI and MRO about 
sharing confidential, market-sensitive information, the Commission 
disagrees that ratings information is confidential or market-sensitive. 
All users, owners and operators should have access to the facility 
ratings in order to operate the system reliably. Section 215(a)(4) of 
the FPA defines Reliable Operation, in part, as operating the elements 
of the Bulk-Power System within equipment and electric system thermal 
stability limits.\274\ Without knowing the ratings, it is not possible 
to know whether this requirement is being met. As to the argument that 
this information is confidential, the Commission clarifies that, as 
with the other information required by this Reliability Standard, the 
additional information required by this modification would be shared 
only with users, owners and operators of the Bulk-Power System.
---------------------------------------------------------------------------

    \274\ 16 U.S.C. 824o(a)(4).
---------------------------------------------------------------------------

    760. In response to Dominion's comments, if the PJM Regional 
Transmission Expansion Planning process meets the criteria, there is no

[[Page 16494]]

need to exclude facilities covered by that process from this 
requirement.
    761. The Commission directs the ERO to consider International 
Transmission's comments regarding requiring information about the 
increase in facility rating based on the next limiting element only for 
lines where the conductor itself is not the limiting element in its 
Reliability Standards development process. Similarly, the ERO should 
also consider the comments from MISO and FirstEnergy that generators 
will have difficulty determining the increase in ratings due to the 
next limiting element, since in most cases the generator itself would 
be the most limiting element.
    762. We agree with Manitoba that this Reliability Standard properly 
places the responsibility to determine facility ratings on the facility 
owner. The Commission is not proposing to change this. We also agree 
with Manitoba that the most limiting component is already identified 
when facility ratings are determined. The Commission is only directing 
transmission and generation owners to provide additional information on 
the next limiting component within the facility so that facility 
ratings are more transparent.
    763. In response to Manitoba's and APPA's concerns, we recognize 
that this is an additional requirement with some complexities, and this 
modification will go through the ERO Reliability Standards development 
process. We do not intend to usurp the Reliability Standards 
development process, where Manitoba may raise its concerns for the ERO 
to consider.
iv. Applicability to Generator Owners
(a) Comments
    764. Xcel states that this Reliability Standard should not apply to 
generator owners because capability testing, rather than using 
mathematical calculations, is the preferred method of determining 
generating unit capability. Capability testing clearly includes the 
capability of all the supporting components behind the generator that 
are required to produce a MW of capability. Xcel also states that this 
proposed Reliability Standard, if applied to generating units, would 
not improve system reliability and could result in conflicting and 
confusing unit capability ratings. Xcel notes that generating units 
already are required to be capability-tested on a periodic and seasonal 
basis to demonstrate unit gross and net capability in accordance with 
proposed standards MOD-024-1 and MOD-025-1.
    765. FirstEnergy also points out that facility ratings for nuclear 
units are part of NRC license agreements and that the ratings 
methodologies included in NRC license agreements are approved by NRC. 
FirstEnergy proposes that compliance with NRC ratings methodology 
requirements should be assumed to comply with this Reliability 
Standard.
(b) Commission Determination
    766. The Commission agrees with Xcel that an actual test could be 
used as a substitute for a mathematical calculation of capability, and 
we ask the ERO to consider these comments in its Reliability Standards 
development process. The Commission understands that NRC provides 
ratings methodologies for nuclear power plants and not for the 
transmission system. Capacity ratings of nuclear generators determined 
using this methodology are acceptable for reliability purposes. We also 
direct the ERO to consider FirstEnergy's comments in its Reliability 
Standards development process.
 v. Compliance With Blackout Report Recommendation No. 27
(a) Comments
    767. Manitoba believes this Reliability Standard meets the 
requirement of Blackout Report Recommendation No. 27 because the 
recommendation does not require a uniform set of methodologies for 
rating facilities, but instead only recommends that there be a clear, 
unambiguous requirement to rate transmission lines.
    768. Valley Group notes that, while the Commission's proposal would 
direct the ERO to respond to a part of Blackout Report Recommendation 
No. 27, it does not address the important second part of the 
Recommendation, namely dynamic ratings. Valley Group notes that dynamic 
ratings offer a very powerful tool both for maximizing the capabilities 
of transmission paths and for avoiding unnecessary transmission line 
loading relief. Valley Group also notes that dynamic ratings, based 
either on ambient-adjusted ratings or ratings generated by real-time 
monitoring systems, are widely used in the PJM system, while broader 
real-time ratings are applied on certain lines in SPP and ERCOT and at 
several individual utilities. Valley Group states that controlling 
unnecessary operator interventions with dynamic ratings both increases 
the reliability of Bulk-Power System and improves its economy. Valley 
Group concludes that it would be highly desirable for the ERO to 
establish policies and procedures regarding dynamic ratings--as 
recommended by the Blackout Report, and recommends that the Commission 
include such guidance in its Final Rule.
(b) Commission Determination
    769. The Commission believes that implementation of the 
modifications discussed earlier to Reliability Standard FAC-008-1 meets 
our goal of implementing Blackout Report Recommendation No. 27, which 
is to ``develop enforceable standards for transmission line ratings.'' 
\275\ To achieve a clear and unambiguous Requirement to rate 
transmission lines, it is important to understand the underlying 
assumptions and the methodologies that will be used to develop those 
ratings. The Commission recognizes that dynamic line ratings are an 
innovative application, and directs the ERO to consider the comments 
from Valley Group in future revisions of this Reliability Standard.
---------------------------------------------------------------------------

    \275\ Blackout Report at 162.
---------------------------------------------------------------------------

vi. General Comments
    770. APPA notes that FAC-008-1 should be revised to replace Levels 
of Non-Compliance with Violation Security Levels, and to include 
Violation Risk Factors on all FAC-008-1 requirements.
(a) Commission Determination
    771. The Commission acknowledges that the Reliability Standards are 
changing. In this Final Rule, we are ruling on the Reliability 
Standards as they were filed, and these documents use the term Levels 
of Non-Compliance. The ERO should address APPA's comments in its 
Reliability Standards development process.
vii. Summary of Commission Determination
    772. Accordingly, as discussed in the responses to comments above, 
the Commission approves FAC-008-1 as mandatory and enforceable. In 
addition, we direct the ERO to develop modifications to FAC-008-1 
through its Reliability Standards development process requiring 
transmission and generation facility owners to: (1) Document underlying 
assumptions and methods used to determine normal and emergency facility 
ratings; (2) develop facility ratings consistent with industry 
standards developed through an open, transparent and validated process 
and (3) for each facility, identify the limiting component and, for 
critical facilities, the resulting increase in rating if that component 
is no longer limiting.

[[Page 16495]]

e. Establish and Communicate Facility Ratings (FAC-009-1)
    773. FAC-009-1 requires each transmission owner and generation 
owner to establish facility ratings consistent with its associated 
facility ratings methodology and provide those ratings to its 
reliability coordinator, transmission operator, transmission planner 
and planning authority. In the NOPR, the Commission proposed to approve 
FAC-009-1 as mandatory and enforceable.
i. Comments
    774. APPA supports approval of FAC-009-1 as a mandatory and 
enforceable Reliability Standard.
ii. Commission Determination
    775. FAC-009-1 serves an important reliability purpose of ensuring 
that facility ratings are determined based on an established 
methodology. Further, the proposed Requirements set forth in FAC-009-1 
are sufficiently clear and objective to provide guidance for 
compliance. Accordingly, the Commission approves Reliability Standard 
FAC-009-1 as mandatory and enforceable.
f. Transfer Capability Methodology (FAC-012-1)
    776. Proposed Reliability Standard FAC-012-1 requires each 
reliability coordinator and planning authority to document the 
methodology used to develop its inter-regional and intra-regional 
transfer capabilities. This methodology must describe how it addresses 
transmission topology, system demand, generation dispatch and use of 
projected and existing commitment of transmission.
    777. In the NOPR, the Commission explained that, because the 
methodology to calculate transfer capability used by a reliability 
coordinator or planning authority has not been submitted to the 
Commission, it is not possible to determine at this time whether FAC-
012-1 satisfies the statutory requirement that a proposed Reliability 
Standard be just, reasonable, not unduly discriminatory or 
preferential, and in the public interest. Thus, the NOPR did not 
propose to approve or remand this Reliability Standard until the 
regional procedures are submitted.
    778. The NOPR explained that FAC-012-1 only requires that the 
regional reliability organization provide documentation on transfer 
capability methodology and provide it to entities such as the relevant 
transmission planner, planning authority, reliability coordinator and 
transmission operator. The Reliability Standard does not contain clear 
requirements on how transfer capability should be calculated, which has 
resulted in diverse interpretations of transfer capability and the 
development of various calculation methodologies. The NOPR suggested 
that FAC-012-1 should, as a minimum, provide a framework for the 
transfer capability calculation methodology including data inputs and 
modeling assumptions. In addition, the NOPR asked for comments on the 
most efficient way to make the above information transparent for all 
participants.
i. Methodology
(a) Comments
    779. APPA, International Transmission and MidAmerican agree that 
the proposed FAC-012-1 is not sufficient and should not be accepted for 
approval as a mandatory Reliability Standard. They suggest that, at a 
minimum, this Reliability Standard should provide a framework for the 
transfer capability calculation methodology, including data inputs and 
modeling assumptions. APPA notes that, in the Western Interconnection 
and ERCOT, the sets of rules for long-range and operational planning 
studies are transparent to all users, owners and operators and suggests 
that in the Eastern Interconnection, where multiple regions exist, the 
Regional Entities should consider developing an umbrella organization 
or process comprised of representatives from each of the Eastern 
Interconnection's Regional Entities to establish the planning and 
operational rules for the Interconnection. APPA suggests that this 
approach would work well to identify critical facilities, by using 
consistent and transparent study assumptions, and it would also 
minimize seams issues when establishing facility rating and transfer 
capabilities throughout the entire Interconnection. International 
Transmission states that this Reliability Standard should identify the 
performance that is required, that specifics of how transfer capability 
should be calculated do not belong in this Reliability Standard, and 
that a reference document could be developed for this purpose.
(b) Commission Determination
    780. Although we are not proposing to approve or remand this 
Reliability Standard, because it is applicable to the regional 
reliability organization, the Commission agrees with APPA, 
International Transmission and MidAmerican that, at a minimum, this 
Reliability Standard should provide a framework for the transfer 
capability calculation methodology, including data inputs and modeling 
assumptions. The Commission agrees with APPA that there should be an 
umbrella organization to assure consistency within the Eastern 
Interconnection and the other interconnections. We believe that the 
best organization to do this would be the ERO, because it is the only 
organization with knowledge of all of the individual Regional Entities 
that can carry out this function. Therefore, we direct the ERO to 
modify this Reliability Standard to provide such a framework.
ii. Transparency and Confidentiality
(a) Comments
    781. International Transmission cautions that, in making 
information regarding the framework for calculating transfer capability 
transparent to all participants, a balance must be maintained between 
the need for transparency and the need to maintain the confidentiality 
of sensitive critical energy infrastructure information (CEII). The 
results of certain critical contingency analyses would not be 
appropriate for public disclosure, but may be the basis for transfer 
capability limits imposed on some interfaces.
    782. MidAmerican suggests that transparency could be provided in 
the Eastern Interconnection by each reliability coordinator and each 
planning authority posting the transfer capability calculations 
performed pursuant to FAC-012-1, along with a document outlining how 
they were determined and the purposes for which they are used on a 
protected Web site. The protected site should be accessible only to 
qualified entities. MidAmerican suggests that the Western 
Interconnection's approach, the WECC message system used for certain 
qualified paths, is an appropriately transparent system.
(b) Commission Determination
    783. Although we are not proposing to approve or remand this 
proposed Reliability Standard, the Commission believes that it can be 
improved. The Commission believes that the process used to determine 
transfer capabilities should be transparent to the stakeholders, and 
agrees with International Transmission and MidAmerican that the results 
of those calculations should not be available for public disclosure but 
only for qualified entities on a confidential basis. In addition, the 
process and criteria used to determine transfer capabilities must be 
consistent with the process and

[[Page 16496]]

criteria used for other users of the Bulk-Power System. Simply stated, 
the criteria used to calculate transfer capabilities for use in 
determining ATC must be identical to those used in planning and 
operating the system. The Commission directs the ERO to take this into 
account in its Reliability Standards development process, and to modify 
the Reliability Standard consistent with Order No. 890 in Docket No. 
RM05-25-000.
    784. Accordingly, the Commission affirms the NOPR proposal to not 
approve or remand this Reliability Standard. We understand that the ERO 
implemented its Reliability Standards development process to revise the 
Reliability Standard and will be submitting it in accordance with the 
schedule identified in Order No. 890.
g. Establish and Communicate Transfer Capability (FAC-013-1)
    785. FAC-013-1 requires either the reliability coordinator or the 
planning authority, as determined by the regional reliability 
organization, to calculate transfer capabilities consistent with its 
transfer capability methodology and provide those capabilities to its 
transmission operators, transmission service providers and planning 
authorities.
    786. In the NOPR, the Commission proposed to approve Reliability 
Standard FAC-013-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to develop a modification to 
FAC-013-1 that: (1) Makes it applicable to all reliability coordinators 
and (2) removes the regional reliability organization as the entity 
that determines whether a planning authority has a role in determining 
transfer capabilities.
i. Comments
    787. APPA supports the Commission's proposal to approve FAC-013-1 
as a mandatory and enforceable Reliability Standard, but disagrees with 
the Commission's proposed modification to remove the regional 
reliability organization as the entity that determines whether a 
planning authority has a role in determining transfer capabilities. 
APPA believes that regional committee processes are essential to 
determine, through their planning and operating committees, which 
planning authorities and reliability coordinators are responsible for 
determining and distributing each of the specific transfer capability 
values within each regional footprint. APPA proposes that in the 
Eastern Interconnection, where multiple regional reliability 
organizations and Regional Entities exist, the Regional Entities should 
consider developing an umbrella organization or process comprised of 
representatives from each of the Eastern Interconnection's Regional 
Entities, to establish the planning and operational planning rules for 
the Interconnection. APPA believes that such a program would minimize 
seams issues when establishing facility ratings and transfer 
capabilities throughout the entire Interconnection.
    788. MidAmerican supports the Commission's proposal to make this 
Reliability Standard applicable to all reliability coordinators and 
planning authorities. MidAmerican believes in a clear separation of 
responsibilities between the reliability coordinators and planning 
authorities. MidAmerican believes that reliability coordinators should 
calculate transfer capabilities in the operating horizon, while 
planning authorities calculate transfer capabilities in the planning 
horizon, and would support additional clarification of the standard by 
explicitly stating the continued responsibility of planning authorities 
to calculate transfer capabilities for the planning horizon.
    789. TANC is concerned that, if the transmission service provider 
and the transmission operators are specifically named in Requirement 
R2.1 of this Reliability Standard, but are not included in the 
Applicability section, this will cause ambiguity. TANC questions 
whether a transmission service provider or transmission operator that 
does not receive the transfer capabilities from the reliability 
coordinator will be held accountable and penalized for not producing 
the transfer capabilities when the reliability coordinator never 
provided them. If this is the case, TANC questions whether there will 
be different penalties for the transmission service provider and 
transmission operator, or whether they will be subject to the same 
penalties as the entities listed in the Applicability section.
    790. EEI believes that the full range of issues discussed here are 
currently under review under Docket No. RM05-25 and proposes that these 
issues remain in a single forum to avoid confusion.
ii. Commission Determination
    791. The Commission does not believe that the regional reliability 
organization should be able to decide the type of entity to which this 
Reliability Standard applies. The Commission disagrees with APPA that 
regional committee processes are essential to determine which planning 
authorities and reliability coordinators are responsible for 
determining and distributing each of the specific transfer capability 
values. Reliability coordinators have a wider-area view of the 
transmission system than planning authorities, which is important in 
calculating inter- and intra-regional transfer capabilities. Therefore, 
the Commission agrees with MidAmerican that reliability coordinators 
should calculate transfer capabilities in the operating horizon. The 
Commission will not address MidAmerican's proposal regarding 
calculating transfer capabilities in the planning horizon because those 
Reliability Standards are being considered in Docket No. RM07-3-000 and 
are therefore beyond the scope of this proceeding.
    792. The Commission, as discussed elsewhere in this Final Rule, has 
considered APPA's proposal concerning creating an umbrella organization 
in regard to FAC-012-001.\276\
---------------------------------------------------------------------------

    \276\ See supra P 780.
---------------------------------------------------------------------------

    793. In regard to TANC's concern that transmission service 
providers and transmission operators may be liable because they are 
specifically named in Requirement R2.1, the Commission clarifies that, 
because the Reliability Standard only provides that the transmission 
service providers and transmission operators receive information 
regarding transfer capabilities, and does not require an affirmative 
action on the part of transmission service providers or transmission 
operators, a transmission service provider or transmission operator 
cannot be liable for violating the Reliability Standard.
    794. The Commission disagrees with EEI that these matters should be 
evaluated only in the OATT Reform Proceeding. In Order No. 890, the 
Commission directed transmission owners to use the ERO's Reliability 
Standards development process to implement changes required in that 
Final Rule.\277\
---------------------------------------------------------------------------

    \277\ Order No. 890 at P 196.
---------------------------------------------------------------------------

    795. Accordingly, the Commission approves Reliability Standard FAC-
013-1 as mandatory and enforceable, and, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, the Commission directs 
the ERO to develop a modification to FAC-013-1 through the Reliability 
Standards development process that makes it applicable to reliability 
coordinators.

[[Page 16497]]

6. INT: Interchange Scheduling and Coordination
    796. The Interchange Scheduling and Coordination (INT) group of 
Reliability Standards addresses interchange transactions,\278\ which 
occur when electricity is transmitted from a seller to a buyer across 
the power grid. Specific information regarding each transaction must be 
identified in an accompanying electronic label, known as a ``Tag'' or 
``e-Tag'' which is used by affected reliability coordinators, 
transmission service providers and balancing authorities to assess the 
transaction for reliability impacts. Communication, submission, 
assessment and approval of a Tag must be completed for reliability 
consideration before implementation of the transaction.
---------------------------------------------------------------------------

    \278\ The NERC glossary defines ``interchange'' as ``Energy 
transfers that cross Balancing Authority boundaries.'' NERC Glossary 
at 9.
---------------------------------------------------------------------------

a. Interchange Authority
    797. The Version 1 INT Reliability Standards submitted with NERC's 
August 28, 2006 supplemental filing include a new entity, the 
interchange authority, which oversees interchange transactions and is 
included as an applicable entity or referenced in the Requirements 
sections of INT-005-1, INT-006-1, INT-007-1, INT-008-1, INT-009-1 and 
INT-010-1.\279\ The Commission requested in the NOPR that NERC provide 
additional information regarding the role of the interchange authority 
so that the Commission could determine whether the interchange 
authority is a user, owner or operator of the Bulk-Power System 
required to comply with mandatory Reliability Standards.
---------------------------------------------------------------------------

    \279\ The NERC Glossary defines an ``interchange authority'' as 
``the responsible entity that authorizes implementation of valid and 
balanced Interchange Schedules between Balancing Authority Areas, 
and ensures communication of Interchange information for reliability 
assessment purposes.'' Id.
---------------------------------------------------------------------------

i. Comments
    798. ISO-NE states that it is unclear who the interchange authority 
should be, how its tasks could be performed operationally and how the 
interchange authority function relates to other reliability and market 
functions. ISO-NE states that NERC has not yet fully incorporated the 
concept of an interchange authority into its Functional Model and has 
not provided a means for an entity to register as an interchange 
authority under the Functional Model. Finally, ISO-NE states that NERC 
must still create a process to allow the appropriate entities to 
register as interchange authorities so that their status is clear to 
all applicable entities, and it urges that approval of the Reliability 
Standards that have the interchange authority as an applicable entity 
be withheld until these issues are resolved.
    799. APPA agrees that applicability of the Reliability Standards to 
the interchange authority is confusing. However, APPA suggests the best 
approach to the problem is for NERC to identify the source and sink 
balancing authorities as the applicable entity in these Reliability 
Standards until the Functional Model is revised to better specify the 
status and responsibility of interchange authorities.
    800. EEI observes that there is considerable confusion throughout 
the industry regarding the registration process and the relationship 
between registration and applicability of standards, with the 
interchange authority being an example of that confusion. However, EEI 
states it understands that the role of an interchange authority is 
currently being addressed and revisions to the Functional Model are 
currently moving through the approval process. If Version 3 of the 
Functional Model is approved by the NERC Board, EEI believes it will 
clarify that a sink balancing authority performing a Tag authority 
service could serve as an interchange authority and this modification 
would address the Commission's concern.
    801. The CAISO suggests that it is premature to place any INT 
Reliability Standards involving an interchange authority into effect 
until more information is provided concerning the interchange 
authority's role.
ii. Commission Determination
    802. The NERC glossary definition of interchange authority 
indicates that it is intended to provide essentially a quality control 
function in verifying and approving interchange schedules and 
communicating that information. Our understanding is that, in the 
interim, sink and source balancing authorities will serve as 
interchange authorities until the ERO has further clarified an 
interchange authority's role and responsibility in the modification of 
the Functional Model and in the registration process. The new 
interchange authority function allows an entity other than a balancing 
authority to perform this function in the future; the pre-existing INT-
001-1 Reliability Standard identified the balancing authority as the 
responsible entity to perform this function. Any such entity should be 
registered by the ERO in the ERO compliance registry, so that the 
responsibility of an entity, other than a balancing authority, that 
takes on this role in the future would be clear.
    803. In short, there is sufficient clarity concerning the nature 
and responsibilities of this function for it to be implemented at this 
time. Withholding approval of INT Reliability Standards pending further 
clarification on this matter would create an unnecessary gap in the 
coverage of the Reliability Standards that potentially could threaten 
the reliability of the Bulk-Power System.
b. Interchange Information (INT-001-2)
    804. INT-001-1 seeks to ensure that interchange information is 
submitted to the reliability analysis service identified by NERC.\280\ 
This Reliability Standard applies to purchasing-selling entities and 
balancing authorities. It specifies two Requirements that focus 
primarily on establishing who has responsibility in various situations 
for submitting the interchange information, previously known as 
transaction tag data, to the reliability analysis service identified by 
NERC. The Requirements apply to all dynamic schedules, delivery from a 
jointly owned generator and bilateral inadvertent interchange payback.
---------------------------------------------------------------------------

    \280\ Currently, the reliability analysis service used by NERC 
is the Interchange Distribution Calculator.
---------------------------------------------------------------------------

    805. The Commission proposed in the NOPR to approve Reliability 
Standard INT-001-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of its regulations, 
the Commission proposed to direct NERC to submit a modification to INT-
001-1 that: (1) Includes Measures and Levels of Non-Compliance and (2) 
includes a Requirement that interchange information must be submitted 
for all point-to-point transfers entirely within a balancing authority 
area, including all grandfathered and ``non-Order No. 888'' 
transfers.\281\
---------------------------------------------------------------------------

    \281\ This Requirement was included in INT-001-0 as Requirement 
R1.2.
---------------------------------------------------------------------------

    806. The Commission also noted in the NOPR that certain 
Requirements of INT-001-0 that relate to the timing and content of e-
Tags had been deleted in the Version 1 Reliability Standard. NERC 
indicated that these Requirements are business practices that would be 
included in the next version of the NAESB Business Practices. The 
Commission stated in the NOPR that NERC's explanation of this change 
was acceptable and proposed to approve INT-001-1 with the deletion of 
Requirements R1.1, R3, R4 and R5. However, the Commission also noted 
that NAESB had not yet filed the e-Tagging requirements as part of its

[[Page 16498]]

business practices, and that if no such business practice has been 
submitted at the time of the Final Rule, the Commission may reinstate 
these Requirements in the Final Rule.
    807. NERC submitted INT-001-2, which supersedes the Version 1 
Reliability Standards, in its November 15, 2006 filing. INT-001-2 adds 
Measures and Levels of Non-Compliance to the Version 0 Reliability 
Standard. In this Final Rule, the Commission addresses INT-001-2, as 
filed with the Commission on November 15, 2006.
i. Comments
    808. APPA states that NERC's submission of INT-001-2 on November 
15, 2006 has fulfilled the Commission's proposed directive to include 
Measures and Levels of Non-Compliance in this Reliability Standard. 
APPA also states that, while it does not oppose NERC consideration of 
the Commission's proposed directive regarding the submission of 
interchange information for all point-to-point transfers entirely 
within a balancing authority area, it does not understand the 
Commission's reliability concerns in this connection.
    809. MidAmerican states that it favors the Commission's proposed 
directive to NERC for a modification of the Reliability Standard as a 
substantial improvement for reliability. Constellation supports this 
proposal and states that the proposal, together with other initiatives, 
such as OATT reform, represent additional steps to achieving not only 
Bulk-Power System reliability, but also a reduction of undue 
discrimination in transmission services.
    810. NERC disagrees with the Commission's proposal to direct the 
submission of interchange information on all point-to-point transfers 
within a balancing area. NERC contends that this issue was discussed at 
great length in the Reliability Standards development process and the 
vast majority of commenters and voters agreed that such a requirement 
would have no merit from a reliability perspective. It also states that 
such data is not used today by the NERC interchange distribution 
calculator for reliability.\282\ Finally, NERC concludes that while it 
may be appropriate for this issue to be reconsidered in revisions to 
the Reliability Standards, a Commission directive to include a 
requirement that the collective expertise and the consensus of the 
industry have determined to be unnecessary for reliability constitutes 
``setting the standard.''
---------------------------------------------------------------------------

    \282\ The NERC glossary defines the interchange distribution 
calculator as ``[t]he mechanism used by Reliability Coordinators in 
the Eastern Interconnection to calculate the distribution of 
Interchange Transactions over specific Flowgates. It includes a 
database of all Interchange Transactions and a matrix of the 
Distribution Factors for the Eastern Interconnection.'' NERC 
Glossary at 9.
---------------------------------------------------------------------------

    811. LPPC agrees with the Commission that Requirements R1.1, R3, R4 
and R5 are good business practices, and it states that for this reason 
they should not be included in the Reliability Standards. These 
business practices should more appropriately be contained in NAESB 
standards, or perhaps the pro forma OATT.
    812. ERCOT maintains that INT-001-1 is not appropriate for the 
ERCOT region. ERCOT states that it is a single balancing authority. To 
the extent that INT-001-1 requires tagging transfers within a single 
balancing authority, it cannot be applied to ERCOT as written because 
all point-to-point transfers within ERCOT are financial transactions 
only. ERCOT notes that it tags transfers outside the ERCOT region.
    813. Allegheny states that the requirement to tag point-to-point 
transactions cannot be met in the PJM market where Tags are not used 
when a transaction's source and sink are within the PJM footprint. Such 
transactions are reported through the PJM eSchedule system, which 
already provides adequate information for the PJM region to conduct 
reliability and curtailment analyses. Allegheny states that there is no 
reliability gap in the PJM market arising from this issue.
    814. Santa Clara submits that LSEs should be applicable entities 
under proposed revised INT-001-2 to ensure that they have adequate 
notice of the requirements of this Reliability Standard. It states that 
the actions of LSEs are implicated in Requirement R1 of this proposed 
Reliability Standard.\283\
---------------------------------------------------------------------------

    \283\ INT-001-2 Requirement R1 provides that the LSE and 
purchasing-selling entity shall ensure that arranged interchange is 
submitted to the interchange authority.
---------------------------------------------------------------------------

ii. Commission Determination
    815. The Commission approves INT-001-2 as a mandatory and 
enforceable Reliability Standard. In addition, we direct the ERO to 
develop modifications to the Reliability Standard through the 
Reliability Standards development process, as discussed below.
    816. We agree with APPA that INT-001-2, submitted on November 15, 
2006 includes Measures and Levels of Compliance, and we will not direct 
any further action regarding Measures and Levels of Compliance at this 
time.
    817. MidAmerican and Constellation support the Commission's 
proposal that this Reliability Standard include a Requirement that 
interchange information must be submitted for all point-to-point 
transfers entirely within a balancing authority area, including all 
grandfathered and ``non-Order No. 888'' transfers. The Commission 
points out that unless these grandfathered and ``non-Order No. 888'' 
transfers are included in one of the INT Reliability Standards, they 
might not be subject to appropriate curtailment as necessary due to 
system conditions. Curtailments are determined using the interchange 
distribution calculator. Unless transactions internal to a balancing 
authority area are included in the calculator as we proposed, they are 
not recognized by the calculator and may never be curtailed. For 
instance, even if a transaction internal to a balancing authority area 
is non-firm and some inter-balancing authority trades are firm, the 
latter could be cut before the former, despite the curtailment 
priorities in the Order No. 888 tariff. While we recognize that most 
trades internal to a balancing authority area do not affect 
interchange, some do, since electricity flows do not necessarily follow 
the contract path.
    818. In addition, e-Tagging of such transfers was previously 
included in INT-001-0 and the Commission is aware that such transfers 
are included in the e-Tagging logs. In short, the practice already 
exists, but if this Requirement is removed from INT-001-2, no 
Reliability Standard would require that such information be provided. 
We therefore will adopt the directive we proposed in the NOPR and 
direct the ERO to include a modification to INT-001-2 that includes a 
Requirement that interchange information must be submitted for all 
point-to-point transfers entirely within a balancing authority area, 
including all grandfathered and ``non-Order No. 888'' transfers.
    819. The Commission agrees with ERCOT's conclusion that the 
Reliability Standard does not apply to financial point-to-point 
transfers within the ERCOT region. This interpretation is consistent 
with the proposed INT Reliability Standards. Likewise, Allegheny's 
views on tagging point-to-point transactions within the PJM market are 
consistent with the proposed INT Reliability Standards.
    820. With respect to Santa Clara's position that LSEs should be 
applicable entities under the Reliability Standard, the Commission 
notes that in situations where a LSE is securing energy from outside 
the balancing authority to supply its end-use customers, it would 
function as a purchasing-selling entity, as defined in the NERC 
glossary, and would be included in the NERC registry

[[Page 16499]]

on that basis. This interpretation flows from the language of the 
Reliability Standards, and the Commission does not perceive any 
ambiguity in this connection. Nevertheless, the Commission directs the 
ERO to consider Santa Clara's comments, and whether some more explicit 
language would be useful, in the course of modifying INT-001-2 through 
the Reliability Standards development process.
    821. The Commission accepts NERC's explanation that Requirements 
R1.1, R3, R4 and R5 of INT-001-0 that were deleted in INT-001-1 are 
business practices. NAESB voluntarily filed ``Standards for Business 
Practices and Communication Protocols for Public Utilities'' in Docket 
No. RM05-5-000 on November 16, 2006. This filing contains wholesales 
electric business practice standards that incorporate e-Tagging 
requirements and is the subject of a separate rulemaking process that 
is expected to result in rules that will become effective on or about 
the same time as the Reliability Standard becomes mandatory.
    822. Accordingly, the Commission approves Reliability Standard INT-
001-2 as mandatory and enforceable. In addition, the Commission directs 
the ERO to develop a modification to INT-001-2 through its Reliability 
Standards development process that includes a Requirement that 
interchange information must be submitted for all point-to-point 
transfers entirely within a balancing authority area, including all 
grandfathered and ``non-Order No. 888'' transfers.\284\
---------------------------------------------------------------------------

    \284\ The Requirement was included in INT-001-0 as Requirement 
R1.2.
---------------------------------------------------------------------------

c. Regional Difference to INT-001-2 and INT-004-1: WECC Tagging Dynamic 
Schedules and Inadvertent Payback
    823. NERC proposed a regional difference that would exempt WECC 
from requirements related to tagging dynamic schedules and inadvertent 
payback. The Commission noted in the NOPR that WECC is developing a 
tagging requirement for dynamic schedules. The Commission requested 
information from NERC on the status of the proposed tagging 
requirement, the time frame for its development, its consistency with 
INT-001-1 and INT-004-1 and whether the need for an exemption would 
cease when the tagging requirements become effective. The Commission 
stated that it would not approve or remand an exemption until NERC 
submits this information.\285\ Rather, we stated that we would consider 
any regional differences contained in a proposed WECC tagging 
requirement for dynamic schedules when submitted by NERC for Commission 
review.
---------------------------------------------------------------------------

    \285\ To date, the Commission has not received the requested 
information.
---------------------------------------------------------------------------

i. Comments
    824. APPA agrees with the Commission's proposed course of action 
addressing this regional difference.
    825. Xcel requests that the Commission accept the proposed regional 
difference; tagging requirements for dynamic schedules do not apply now 
in WECC, and it would be burdensome and would provide little 
reliability benefit to apply those requirements to WECC by June 2007. 
The Commission therefore should approve the proposed variance for an 
interim period until WECC's tagging requirements for dynamic schedules 
are developed and approved.
ii. Commission Determination
    826. The Commission stressed in Order No. 672 that uniformity of 
Reliability Standards should be the goal and practice, ``the rule 
rather than the exception.'' \286\ The Commission therefore stated in 
the NOPR that the absence of a tagging requirement for dynamic 
schedules in WECC is a matter of concern, and that for this reason it 
could not approve or remand this regional difference without the 
additional information it requested. To date the Commission has not 
received this information. Of particular importance in this compliance 
filing will be the ERO's demonstration that this practice is due to a 
physical difference in the system or results in a more stringent 
Reliability Standard. Without this information, we are unable to 
address Xcel's comments further. The Commission therefore directs the 
ERO to submit a filing within 90 days of the date of this order either 
withdrawing this regional difference or providing additional 
information.
---------------------------------------------------------------------------

    \286\ Order No. 672 at P 290.
---------------------------------------------------------------------------

d. Regional Difference to INT-001-2 and INT-003-2: MISO Energy Flow 
Information
    827. NERC proposed a regional difference that would allow MISO to 
provide market flow information in lieu of tagging intra-market flows 
among its member balancing authorities; the MISO energy flow 
information waiver is needed to realize the benefits of locational 
marginal pricing within MISO while increasing the level of granularity 
of information provided to the NERC TLR Process. The waiver request 
text states that it is understood that the level of granularity of 
information provided to reliability coordinators must not be reduced or 
reliability will be negatively affected. The waiver request text 
includes a condition specifying that the ``Midwest ISO must provide 
equivalent information to Reliability Authorities as would be extracted 
from a transaction tag.'' The Commission proposed in the NOPR to 
approve this regional difference. It explained there that, based on the 
information provided by NERC, the proposed regional difference is 
necessary to accommodate MISO's Commission-approved, multi-control area 
energy market. Thus, the Commission stated it believed that the 
regional difference is appropriate, because it is more stringent than 
the continent-wide Reliability Standard and otherwise satisfies the 
statutory standard for approval of a Reliability Standard.
i. Comments
    828. APPA agrees with Commission's proposed course of action in 
approving this regional difference.
ii. Commission Determination
    829. The information received by the Commission demonstrates that 
the proposed regional difference to INT-001-2 and INT-003-2, as filed 
on November 15, 2006, is necessary to accommodate MISO's Commission-
approved, multi-control area energy market. The Commission concludes 
that the regional difference is appropriate, because it is more 
stringent than the continent-wide Reliability Standard and otherwise 
satisfies the statutory standard for approval of a Reliability 
Standard, and therefore approves it as mandatory and enforceable.
e. Interchange Transaction Implementation (INT-003-2)
    830. The purpose of INT-003-1 is to ensure that balancing 
authorities confirm interchange schedules with adjacent balancing 
authorities before implementing the schedules in their area control 
error equations. INT-003-1 contains a Requirement that focuses on 
ensuring that a sending balancing authority confirms interchange 
schedules with its receiving balancing authority before implementing 
the schedules in its control area. The proposed Reliability Standard 
also requires that, for the instances where a high voltage direct 
current (HVDC) tie is on the scheduling path, both sending and 
receiving balancing authorities have to coordinate with the operator of 
the HVDC tie.

[[Page 16500]]

    831. The Commission proposed in the NOPR to approve Reliability 
Standard INT-003-1 as mandatory and enforceable. In addition the 
Commission proposed to direct NERC to submit a modification to INT-003-
1 that includes Measures and Levels of Non-Compliance.
    832. NERC filed INT-003-2 with the Commission on November 15, 2006. 
This Reliability Standard supersedes the Version 1 Reliability Standard 
INT-003-1 and adds Measures and Levels of Non-Compliance.
i. Comments
    833. APPA states that INT-003-2 fulfills the Commission's proposed 
directive to include Measures and Levels of Non-Compliance.
ii. Commission Determination
    834. INT-003-1 serves an important purpose in requiring receiving 
and sending balancing authorities to confirm and agree on interchange 
schedules. With the addition of Measures and Levels of Non-Compliance, 
INT-003-2 addresses the Commission's only reservation regarding this 
Reliability Standard. Accordingly, the Commission approves Reliability 
Standard INT-003-2, as filed with the Commission on November 15, 2006, 
as mandatory and enforceable.
f. Regional Differences to INT-003-2: MISO/SPP Scheduling Agent and 
MISO Enhanced Scheduling Agent
    835. NERC proposed a regional difference that would provide MISO 
and SPP with a variance from INT-003-1 to permit a market participant 
to use a scheduling agent to prepare a transaction Tag on its 
behalf.\287\ In addition, NERC proposed the MISO Enhanced Scheduling 
Agent Waiver, which creates a variance from INT-003-1 for MISO that 
permits an enhanced single point of contact scheduling agent.
---------------------------------------------------------------------------

    \287\ NERC proposed three regional differences for INT-003-1 
that would apply to MISO. One proposed regional difference was 
addressed in Reliability Standard INT-001-1. The remaining two are 
discussed here.
---------------------------------------------------------------------------

    836. The Commission proposed in the NOPR to approve these two 
additional regional differences. The Commission explained that, based 
on the information provided by NERC, the proposed regional differences 
for this INT Reliability Standard would provide administrative 
efficiency, and provide equal or greater amounts of information to the 
appropriate entities as required in MISO's Commission-approved multi-
control area energy market. The NOPR stated that the regional 
difference is appropriate because it is more stringent than the 
continent-wide Reliability Standard and otherwise satisfies the 
statutory standard for approval of a Reliability Standard.
i. Comments
    837. APPA agrees with the Commission's proposed approval of these 
regional differences.
    838. FirstEnergy states that it would be helpful if NERC clarified 
the function and effect of these waivers. FirstEnergy states that, 
where a specific task will be performed by another entity on behalf of 
the transferor, the transferor entity needs a delegation agreement, 
whereas in transferring a responsibility, the transferor entity needs a 
waiver. FirstEnergy states that currently balancing authorities are 
held accountable by regional reliability organizations for those 
functions the waivers transfer to the regional reliability 
organization. FirstEnergy suggests that NERC should clarify that, under 
these waivers, responsibility for complying with these Reliability 
Standards should be transferred to the RTOs that actually perform the 
tasks associated with these requirements.
ii. Commission Determination
    839. These two variances from INT-003-2, as filed with the 
Commission on November 15, 2006, permit a market participant to use a 
scheduling agent to prepare a transaction tag on its behalf, providing 
administrative efficiency and providing equal or greater amounts of 
information to the appropriate entities as required in MISO's 
Commission-approved multi-control area energy market. This regional 
difference is appropriate because it is more stringent than the 
continent-wide Reliability Standard and otherwise satisfies the 
statutory standard for approval of a Reliability Standard. The 
Commission therefore approves the MISO/SPP Scheduling Agent Waiver and 
the MISO Enhanced Scheduling Agent Waiver as mandatory and enforceable 
regional differences to INT-003-2.
    840. FirstEnergy may raise its suggestions in the Reliability 
Standards development process. However, we find that FirstEnergy's 
suggestion does not affect our decision to approve these two regional 
differences.
g. Dynamic Interchange Transaction Modifications (INT-004-1)
    841. INT-004-1 seeks to ensure that dynamic transfers are 
adequately tagged to be able to determine their reliability impact. It 
requires the sink balancing authority, i.e., the balancing authority 
responsible for the area where the load or end-user is located, to 
communicate any change in the transaction. It also requires the 
updating of Tags for dynamic schedules.
    842. In the NOPR, the Commission proposed to approve Reliability 
Standard INT-004-1 as mandatory and enforceable. The Commission also 
proposed to direct NERC to submit a modification to INT-004-1 that 
includes Levels of Non-Compliance.
i. Comments
    843. APPA agrees with the Commission that INT-004-1 can be approved 
as a mandatory and enforceable Reliability Standard. However, it 
suggests that the missing Levels of Non-Compliance should be developed 
and submitted for Commission approval before penalties are levied for 
violations.
ii. Commission Determination
    844. As explained in the NOPR, while the Commission has identified 
concerns with regard to INT-004-1, this proposed Reliability Standard 
serves an important purpose by setting thresholds on changes in dynamic 
schedules for which modified interchange data must be submitted. 
Further, the Requirements set forth in INT-004-1 are sufficiently clear 
and objective to provide guidance for compliance. Accordingly, the 
Commission approves Reliability Standard INT-004-1 as mandatory and 
enforceable. In addition, the Commission directs the ERO to consider 
adding these Measures and Levels of Non-Compliance to the Reliability 
Standard.
h. Interchange Authority Distributes Arranged Interchange (INT-005-1)
    845. INT-005-1 seeks to ensure the implementation of interchange 
between source and sink balancing authorities and that interchange 
information is distributed by an interchange authority to the relevant 
entities for reliability assessments.
    846. The Commission proposed in the NOPR to approve Reliability 
Standard INT-005-1 as mandatory and enforceable. The Commission also 
proposed to direct NERC to submit a modification to INT-005-1 that 
includes Levels of Non-Compliance. Further, the Commission noted that 
INT-005-1 is applicable to the ``interchange authority'' and requested 
that NERC provide additional information regarding the role of the 
interchange authority so that the Commission can determine whether it 
is a user, owner or operator of the Bulk-Power System that is required 
to comply with mandatory Reliability Standards.

[[Page 16501]]

i. Comments
    847. Comments on the interchange authority have been discussed 
above under the heading ``INT Reliability Standards General Issues.'' 
No other comments on INT-005-1 have been submitted.
ii. Commission Determination
    848. The Commission has set forth above its analysis and conclusion 
on interchange authorities. Our understanding is that, in the interim, 
source and sink balancing authorities will serve as interchange 
authorities until the ERO has clarified the role and responsibility of 
an interchange authority in the modification of the Functional Model 
and in the registration process.
    849. The Commission is satisfied that the Requirements of INT-005-1 
are appropriate to ensure that interchange information is distributed 
timely and available for reliability assessment. Accordingly, the 
Commission approves Reliability Standard INT-005-1 as mandatory and 
enforceable. In addition, the Commission directs the ERO to consider 
adding additional Measures and Levels of Non-Compliance to the 
Reliability Standard.
i. Response to Interchange Authority (INT-006-1)
    850. INT-006-1 applies to balancing authorities and transmission 
service providers, and requires these entities to evaluate the energy 
profile and ramp rate of generation that supports interchange 
transactions in response to a request from an interchange authority to 
change the status of an interchange from an arranged interchange 
transaction to a confirmed interchange.
    851. The Commission proposed in the NOPR to approve Reliability 
Standard INT-006-1 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to INT-006-
1 that: (1) Makes it applicable to reliability coordinators and 
transmission operators and (2) requires reliability coordinators and 
transmission operators to review composite transactions from the wide-
area reliability viewpoint and, where their review indicates a 
potential detrimental reliability impact, communicate to the sink 
balancing authorities necessary transaction modifications before 
implementation.
i. Comments
    852. APPA agrees that INT-006-1 is sufficient for approval as a 
mandatory and enforceable reliability standard. However, APPA states 
that the Commission should merely instruct NERC to respond to the 
Commission's concerns and refrain from directing NERC to make specific 
changes to the Reliability Standard; APPA states that while the changes 
the Commission proposes may be appropriate, it should be left to NERC's 
expertise and the Reliability Standards development process to address 
the Commission's concerns.
    853. FirstEnergy agrees that it is appropriate for the reliability 
coordinator to be included in the applicability section. However, it 
argues that it is impracticable in large organized markets, such as 
those of MISO and PJM, for a local entity, such as a transmission 
operator, to review wide-area transactions, and it does not improve 
reliability to do so. Transactions occurring totally within the market 
operation are provided as part of network service net scheduled 
interchange.
    854. EEI states that the ``wide-area reliability impact'' review 
envisioned by the Commission, which involves review of the composite 
energy interchange transactions, probably already takes place under 
Reliability Standards INT-005 through INT-009 in a cost-effective 
manner. EEI explains that since most transactions submitted by 
wholesale markets to the transactions tagging process span multiple 
hours with varying sizes (in MW), and are often submitted days before 
transaction start times, the wide-area review consists of ensuring that 
sufficient generator ramping capability exists, as well as examining 
for limits on transfer capabilities. This review is generally 
considered sufficient to the extent that analyses are taking place on 
the basis of projected system conditions. EEI suggests that the 
Commission-proposed review and validation of composite energy 
interchange transactions by reliability coordinators might be more 
effectively addressed through ``near real-time'' system review. It 
explains that, at this time, the broad range of system condition 
parameters is better known, and the reliability coordinators can make 
use of the TLR process to maintain system reliability.
    855. Entergy disagrees with the Commission's proposed 
modifications. It contends that they will require substantial changes 
to the tagging specifications. Entergy believes that the Commission's 
concerns may already be addressed by Reliability Standards INT-005 
through INT-009.
    856. MISO believes the Reliability Standards and e-Tag 
specifications already require reliability entities to evaluate and 
approve e-Tags. It questions the value of specifying reliability 
coordinators and transmission operators as applicable entities because 
their responsibilities are already laid out in the Reliability 
Standards.
    857. Northern Indiana contends that the NOPR's discussion of INT-
006-1 is unclear and confusing. It states that it does not understand 
what the Commission means by ``validate'' when the Commission proposes 
that reliability coordinators and transmission operators review and 
validate composite arranged interchanges. Northern Indiana also 
questions whether both reliability coordinators and transmission 
operators would be required to validate and approve the Tags and what 
the basis for approval would be. It questions what falls within the 
term ``potential detrimental reliability impact,'' what happens if a 
Tag is not validated within 20 minutes to the hour, and whether all 
schedules are canceled outright or passively approved.
    858. TVA suggests that the term ``composite Tag'' should be defined 
as part of the proposed modifications. CAISO also questions the meaning 
of ``composite Tag'' and seeks clarification on that issue. TVA notes 
that depending on the type of reliability analysis required to validate 
a ``composite Tag,'' it may prove impractical to conduct this 
evaluation for hourly transactions.
    859. CAISO states that neither NERC nor the Commission has 
identified a deficiency in the current interchange reliability 
assessment process or a pressing reliability need for this Reliability 
Standard. CAISO also has concerns about meeting the Commission-proposed 
directives regarding INT-006-1 since reliability coordinators and 
transmission operators within the Western Interconnection currently do 
not have a common database from which to draw the information needed to 
review composite transactions from a wide-area reliability viewpoint. 
CAISO requests the Commission to consider whether the Western 
Interconnection should comply with these proposed Requirements at all 
or whether a transition period is appropriate.
ii. Commission Determination
    860. The Commission approves INT-006-1 as mandatory and 
enforceable. In addition, we direct that NERC develop modifications to 
the Reliability Standard, as discussed below.
    861. The Commission remains convinced that a proactive approach is 
superior to a reactive approach in maintaining system reliability. 
While EEI and Entergy claim that reliability

[[Page 16502]]

coordinators and transmission operators' involvement in reliability 
reviews of interchange transactions are covered in INT-005 through INT-
010, and MISO claims that such review is covered in other Reliability 
Standards, we note the following: References to reliability coordinator 
and transmission operator involvement are virtually absent from the INT 
Reliability Standards. One finds such references only in Requirement R2 
of INT-010, which deals with interchange coordination exemptions, and 
there the involvement of reliability coordinators is restricted to 
situations that involve current or imminent reliability-related reasons 
for action. We cannot find any Requirements in the remaining INT 
Reliability Standards that require a wide-area reliability assessment, 
regardless of the time periods, by a reliability coordinator; wide-area 
reliability assessment, moreover, can only be carried out by 
reliability coordinators.
    862. With respect to MISO's comment on the value of applying the 
Reliability Standard to reliability coordinators and transmission 
operators given that the Reliability Standards and the e-Tag 
specification already require evaluation and active approval of 
reliability entities on e-Tags, we note that none of the INT 
Reliability Standards have those requirements and that the e-Tag 
specification is not part of the mandatory Reliability Standards. Like 
reliability coordinators who are responsible for reliable operation of 
entire reliability coordinator areas, a transmission operator is the 
reliability entity responsible for its local area operations. 
Interchange transactions would be likely to reduce system reliability 
if those transactions are not reviewed and approved by the appropriate 
reliability entities before implementation.
    863. With respect to the question raised by TVA and CAISO on the 
definition of ``composite Tags,'' we expressed our reliability concerns 
in the NOPR and explained that reliability coordinators and 
transmission operators should review composite energy interchange 
transaction information (composite Tags) for wide-area reliability 
impact. In addition, we stated that when the review indicated a 
potential detrimental reliability impact, the reliability coordinator 
or transmission operator should communicate to the sink balancing 
authority the necessary transaction modifications before 
implementation.\288\ While we did not require a specific notification 
time prior to actual transactions, this proactive approach should 
promote system reliability.
---------------------------------------------------------------------------

    \288\ NOPR at P 219.
---------------------------------------------------------------------------

    864. We agree with FirstEnergy that it is appropriate to include 
reliability coordinators as applicable entities for purposes of 
conducting wide-area reliability assessments; in large organized 
markets transmission operators may not be appropriate for this purpose 
because they do not have a wide-area view.
    865. While we did not address review time frames in the NOPR, we 
are in general agreement with EEI's suggestion that ``near-real time'' 
system review by reliability coordinators may be more practical, while 
still being efficient and effective in achieving reliability goals. A 
proactive approach, i.e. one that involves reliability coordinators in 
a way that permits them to make wide-area assessments of composite 
interchange transactions for purposes of evaluating reliability impact, 
including identifying potential IROL violations and mitigating them 
using TLR procedures before they become actual IROL violations, is far 
superior to a reactive approach, i.e., one that brings reliability 
coordinators in after the fact to invoke TLR procedures to avoid an 
IROL violation or other operating actions to extricate the system from 
reliability problems such as an actual IROL violation.
    866. The Commission stated in Order No. 672 that it expected 
entities to use the Reliability Standards development process to 
address their concerns about a Reliability Standard. With respect to 
CAISO's request that the Commission consider whether the Western 
Interconnection needs to comply with these Requirements at all or 
whether a transition period is appropriate, since CAISO did not raise 
either concern in the Reliability Standards development process, and 
others in the Western Interconnection have not raised a similar 
concern, CAISO should raise this issue in the Reliability Standards 
development process in the first instance. Reliability Standard INT-
006-1 will apply to CAISO.
    867. Accordingly, the Commission approves Reliability Standard INT-
006-1 as mandatory and enforceable. In addition, the Commission directs 
the ERO to develop a modification to INT-006-1 through the Reliability 
Standards development process that: (1) Makes it applicable to 
reliability coordinators and transmission operators and (2) requires 
reliability coordinators and transmission operators to review energy 
interchange transactions from the wide-area and local area reliability 
viewpoints respectively and, where their review indicates a potential 
detrimental reliability impact, communicate to the sink balancing 
authorities necessary transaction modifications before implementation. 
We also direct that the ERO consider the suggestions made by EEI and 
TVA and address the questions raised by Entergy and Northern Indiana in 
the course of the Reliability Standards development process.
j. Interchange Confirmation (INT-007-1)
    868. Reliability Standard INT-007-1 requires that before changing 
the status of submitted arranged interchanges to confirmed 
interchanges, the interchange authority must verify that the submitted 
arranged interchanges are valid and complete with relevant information 
and approvals from the balancing authorities and transmission service 
providers. The Commission proposed in the NOPR to approve INT-007-1 as 
mandatory and enforceable.
i. Comments
    869. APPA agrees with the Commission that INT-007-1 is sufficient 
for approval as a mandatory and enforceable Reliability Standard, 
subject to NERC's plans for the registration of entities as interchange 
authorities.
ii. Commission Determination
    870. The Commission approves Reliability Standard INT-007-1 as 
mandatory and enforceable. The Commission has set forth above its 
analysis and conclusion on interchange authorities. Our understanding 
is that in the interim source and sink balancing authorities will serve 
as interchange authorities until the ERO has clarified the role and 
responsibility of an interchange authority in the modification of 
Functional Model and in the registration process.
k. Interchange Authority Distribution of Information (INT-008-1)
    871. INT-008-1 requires the interchange authority to distribute 
information to all balancing authorities, transmission service 
providers and purchasing-selling entities involved in the arranged 
interchange when the status of the transaction has changed from 
arranged interchange to confirmed interchange. The Commission proposed 
in the NOPR to approve INT-008-1 as mandatory and enforceable.
i. Comments
    872. APPA agrees with the Commission that INT-008-1 is sufficient 
for approval as a mandatory and enforceable Reliability Standard,

[[Page 16503]]

subject to NERC's plans for the registration of entities as interchange 
authorities. It suggests that NERC should clarify which reliability 
entities have the responsibility for ensuring that interchange 
information is coordinated between the source and sink balancing 
authorities before implementing the Reliability Standard. APPA also 
states that NERC should modify this Reliability Standard to make clear 
what entities it in fact would apply to.
ii. Commission Determination
    873. The Commission approves Reliability Standard INT-008-1 as 
mandatory and enforceable. The Commission has set forth above its 
analysis and conclusion on interchange authorities. Our understanding 
is that a source and sink balancing authority will serve as the 
interchange authority until the ERO has clarified the role and 
responsibility of an interchange authority in the modification of the 
Functional Model and in the registration process. Finally, we direct 
the ERO to consider APPA's suggestions in the Reliability Standards 
development process.
l. Implementation of Interchange (INT-009-1)
    874. Reliability Standard INT-009-1 seeks to ensure that the 
implementation of an interchange between source and sink balancing 
authorities is coordinated by an interchange authority. The Commission 
proposed in the NOPR to approve INT-009-1 as mandatory and enforceable.
i. Comments
    875. APPA agrees with the Commission that INT-009-1 is sufficient 
for approval as a mandatory and enforceable Reliability Standard, 
subject to NERC's plans for the registration of entities as interchange 
authorities. It suggests that NERC modify its Functional Model to 
clarify which reliability entities have the responsibility for ensuring 
proper implementation of interchange transactions that have received 
reliability assessments. APPA also suggests that NERC modify this 
Reliability Standard to make clear what entities it in fact would apply 
to.
ii. Commission Determination
    876. The Commission approves Reliability Standard INT-009-1 as 
mandatory and enforceable. The Commission has set forth above its 
analysis and conclusion on interchange authorities. Our understanding 
is that a source and sink balancing authority will serve as the 
interchange authority until the ERO has clarified the role and 
responsibility of an interchange authority in the modification of the 
Functional Model and in the registration process. Finally, we direct 
the ERO to consider APPA's suggestions concerning this Reliability 
Standard in the Reliability Standards development process.
m. Interchange Exemptions (INT-010-1)
    877. INT-010-1 allows reliability entities to initiate or modify 
certain types of interchange schedules under abnormal operating 
conditions and to be exempt from compliance with other INT Reliability 
Standards.
    878. The Commission explained in the NOPR that Reliability Standard 
INT-010-1 includes provisions that allow modification to an existing 
interchange schedule or submission of a new interchange schedule that 
is directed by a reliability coordinator to address current or imminent 
reliability-related reasons. The Commission interpreted these current 
or imminent reliability-related reasons as not including actual IROL 
violations, since they require immediate action so that the system can 
be returned to a secure operating state as soon as possible and no 
longer than 30 minutes after a reliability-related system 
interruption--a period that is much shorter than the time that is 
expected to be required for new or modified transactions to be 
implemented.
    879. The Commission proposed to approve INT-010-1, interpreted as 
set forth above, as mandatory and enforceable.
i. Comments
    880. Northern Indiana supports the Commission's interpretation of 
INT-010-1, but it requests that the Reliability Standard be modified to 
explicitly state that it does not include actual IROL violations.
    881. ISO-NE supports Commission approval of INT-010-1, but does not 
share the Commission's concerns regarding the initiation or 
modification of interchange schedules to address SOL or IROL 
violations. It states that interchange schedules can in certain 
circumstances provide an additional effective tool to help prevent an 
SOL and IROL violation. While ISO-NE recognizes that other tools may in 
certain circumstances be more effective, it states that this neither 
diminishes the value nor precludes the use of the tools contained in 
INT-010-1. ISO-NE also notes that section 2.4 of INT-010-1, which 
describes Level 4 Non-Compliance, should be edited to state that 
``[t]here shall be a level four non-compliance * * *.`` instead of 
``[t]here shall be a level three non-compliance * * *.''
    882. APPA agrees with the Commission that INT-010-1 is sufficient 
for approval as a mandatory and enforceable Reliability Standard, but 
APPA does not agree with the Commission's interpretation of the 
Reliability Standard. APPA explains that the stated purpose of INT-010-
1 is to allow certain types of interchange schedules to be initiated or 
modified by reliability entities and to be exempt from compliance with 
other interchange standards under abnormal operating conditions. This 
Reliability Standard in effect authorizes reliability coordinators to 
direct, and balancing authorities to take, remedial actions to adjust 
interchange schedules immediately and then document these actions after 
the fact. INT-010-1 thus provides the emergency waiver from other INT 
Reliability Standards that makes adjusting interchange schedules the 
appropriate response to a SOL or IROL. APPA states that the 
Commission's proposed interpretation therefore should not be adopted.
    883. EEI cautions against adopting the Commission's interpretation 
of INT-010-1. EEI believes that the existing standard meets the 
Commission's expectation, i.e., permitting and encouraging immediate 
action to alleviate an SOL or IROL. EEI explains that without INT-010-
1, all interchange scheduling and schedule modifications would go 
through the normal process contained in INT-005 through INT-009. Only 
INT-010 would allow a balancing authority to make an immediate 
interchange action without obtaining a Tag. Within 60 minutes of the 
action, the balancing authority would follow up with the necessary 
documentation and carry forward the action, if necessary. In the 
absence of INT-010-1, a balancing authority taking such action would be 
in violation of INT-009 for failing to comply with the normal process 
requirements.
    884. EEI notes by way of example that, to relieve an SOL or IROL, a 
reliability coordinator requires immediate offsetting changes in the 
net scheduled interchange of ACE equations of source and sink balancing 
authorities. Within 60 minutes following the action, the reliability 
authority directs the balancing authority to reflect the schedule 
change event using an arranged interchange. The tagging activity 
ensures coordination going forward and provides a written record. All 
of this takes place after the operational tasks pertaining to the 
action to alleviate the SOL or IROL,

[[Page 16504]]

consistent with Commission expectations.
ii. Commission Determination
    885. For the reasons and interpretation noted in the NOPR, the 
Commission approves INT-010-1 as mandatory and enforceable.
    886. The Commission believes that our interpretation of INT-010-1 
is consistent with the way APPA and EEI understand the Reliability 
Standards. The Commission believes that making a modification to an 
existing interchange schedule on paper for current or imminent 
reliability-related situations involving actual IROL violations is 
ineffective because its implementation usually takes much longer than 
the 30-minute period that is allowed in the relevant IRO or TOP 
Reliability Standards. However, the Commission interprets INT-010-1 as 
allowing the actual physical transaction to be modified to alleviate an 
IROL event without first documenting the modification. The interchange 
schedule would then be modified after the fact to document the physical 
actions taken.
    887. With regard to ISO-NE's statement that interchange schedules 
can, in certain circumstances, provide an additional effective tool to 
help prevent SOL and IROL violations while other tools may, in certain 
circumstances, be more effective, the Commission clarifies that our 
concern is related to using interchange schedules to address actual 
IROL violations. We have no concern in using this as a tool help 
prevent potential SOL and IROL violations as asserted by ISO-NE. We 
further note that the phrase in Requirements R2 and R3 ``current or 
imminent reliability-related reasons'' can be interpreted as potential 
or actual IROL violations set forth in the comments from Northern 
Indiana, ISO-NE, APPA and EEI, and therefore modifications to INT-010-1 
are needed.
    888. Accordingly, the Commission approves Reliability Standard INT-
010-1 as mandatory and enforceable. In addition, we adopt the 
interpretation set forth in the NOPR that these current or imminent 
reliability-related reasons do not include actual IROL violations, 
since they require immediate control actions so that the system can be 
returned to a secure operating state as soon as possible and no longer 
than 30 minutes after a reliability-related system interruption--a 
period that is much shorter than the time that is expected to be 
required for new or modified transactions to be implemented. Finally, 
we direct the ERO to consider Northern Indiana and ISO-NE's suggestions 
in the Reliability Standards development process.
7. IRO: Interconnection Reliability Operations and Coordination
    889. The Interconnection Reliability Operations and Coordination 
(IRO) group of Reliability Standards detail the responsibilities and 
authorities of a reliability coordinator.\289\ The IRO Reliability 
Standards establish requirements for data, tools and wide-area view, 
all of which are intended to facilitate a reliability coordinator's 
ability to perform its responsibilities and ensure the reliable 
operation of the interconnected grid.
---------------------------------------------------------------------------

    \289\ According to the NERC glossary, at 15, a reliability 
coordinator is ``the entity with the highest level of authority who 
is responsible for the reliable operation of the Bulk Electric 
System, has the Wide Area view of the Bulk Electric System, and has 
the operating tools, processes and procedures, including the 
authority to prevent or mitigate emergency operating situations in 
both next-day analysis and real-time operations * * *.''
---------------------------------------------------------------------------

a. Reliability Coordination--Responsibilities and Authorities (IRO-001-
1)
    890. IRO-001-1 requires that a reliability coordinator have 
reliability plans, coordination agreements and the authority to act and 
direct reliability entities to maintain reliable system operations 
under normal, contingency and emergency conditions.
    891. In November 2006, NERC submitted IRO-001-1, which includes 
Measures and Levels of Non-Compliance.\290\ In addition, while the 
Version 0 Reliability Standard applied to reliability coordinators and 
regional reliability organizations, IRO-001-1 would in addition apply 
to transmission operators, balancing authorities, generator operators, 
transmission service providers, LSEs and purchasing-selling entities. 
The Version 1 Reliability Standard does not modify or add any 
Requirements, and it appears that the change in applicability 
corresponds to existing Requirement R8, which provides that 
transmission operators, balancing authorities, generator operators, 
transmission service providers, LSEs and purchasing-selling entities 
``shall comply with Reliability Coordinator directives unless such 
actions would violate safety, equipment, or regulatory or statutory 
requirements.''
---------------------------------------------------------------------------

    \290\ IRO-001-1 supercedes the Version 0 Reliability Standard. 
In this Final Rule, we review the November version, IRO-001-1.
---------------------------------------------------------------------------

    892. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct NERC to submit a 
modification to Requirement R1 of IRO-001-0 that: (1) Reflects the 
process set forth in the NERC Rules of Procedures and (2) eliminates 
the regional reliability organization as an applicable entity.
i. Comments
    893. APPA supports the approval of the Reliability Standard but 
expresses concern that the Version 1 standard does not include Measures 
that correspond to Requirements R2 and R9. APPA emphasizes the need for 
Measures corresponding to Requirement R9, which requires the 
reliability coordinator to act in the interests of reliability for the 
overall reliability coordinator area and the Interconnection before the 
interests of any other entity. APPA supports Requirement R8 with the 
extended applicability, provided that applicability is determined by 
reference to the NERC compliance registry. APPA agrees that the 
regional reliability organization should be eliminated as an applicable 
entity and suggests it be replaced with Regional Entities.
    894. FirstEnergy suggests that NERC clarify whether Requirement R8, 
which requires entities to comply with a reliability coordinator 
directive ``unless such actions would violate safety, equipment or 
regulatory or statutory requirements,'' refers to personnel safety, 
equipment safety or both. In addition, it suggests the establishment of 
a chain of command so that, for example, if a generator receives 
conflicting instructions from a balancing authority and a transmission 
operator, it can determine which instruction governs.
    895. Requirement R3 provides that a reliability coordinator ``shall 
have clear decision-making authority to act and direct actions to be 
taken'' by applicable entities to ``preserve the integrity and 
reliability of the Bulk Electric System and these actions shall be 
taken without delay but no longer than 30 minutes.'' Santa Clara 
contends that some actions would require driving to a remote site and 
therefore, mandating completion of the required action within 30 
minutes would be unreasonable. Thus, it recommends that NERC modify 
Requirement R3 to provide that ``actions shall commence without delay, 
but in any event shall commence within 30 minutes.''
    896. California Cogeneration comments that the Reliability Standard 
fails to address the operational limitations of QFs because they have 
contractual obligations to provide thermal energy to their industrial 
hosts.

[[Page 16505]]

It contends that a QF can be directed to change operations only in the 
case of a system emergency, pursuant to 18 CFR 292.307.
ii. Commission Determination
    897. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, as a 
separate action under section 215(d)(5), the NOPR proposed to direct 
the ERO to develop modifications to Requirement R1 \291\ to substitute 
``Regional Entity'' for ``regional reliability organization'' and 
reflect NERC's Rules of Procedure for registering, certifying and 
verifying entities, including reliability coordinators. Commenters do 
not raise any concerns regarding the proposed action. Accordingly, for 
the reasons stated in the NOPR, the Commission approves IRO-001-1 as 
mandatory and enforceable. In addition, for the reasons discussed in 
the NOPR, the Commission directs the ERO to develop modifications to 
the Reliability Standard through the Reliability Standards development 
process that reflect the process set forth in the NERC Rules of 
Procedures and eliminate the regional reliability organization as an 
applicable entity.\292\
---------------------------------------------------------------------------

    \291\ Requirement R1 of IRO-001-1 provides that each regional 
reliability organization, ``subregion'' or ``Interregional 
Coordinating group'' shall establish one or more reliability 
coordinators to continuously assess transmission reliability and 
coordinate emergency operations. See NOPR at P 506.
    \292\ See NOPR at P 505-06.
---------------------------------------------------------------------------

    898. While APPA, FirstEnergy and California Cogeneration suggest 
possible changes to IRO-001-1, they do not suggest that the proposed 
Reliability Standard should not be approved. The ERO should consider 
the commenters' suggestions when modifying the Reliability Standard 
pursuant to its Reliability Standards development process. Further, the 
Commission directs the ERO to consider adding Measures and Levels of 
Non-Compliance in the Reliability Standard as requested by APPA.
    899. However, we disagree with Santa Clara's suggested change 
regarding the 30-minute limit to implement a corrective control action 
in Requirement R3. When system integrity or reliability is jeopardized, 
e.g., exceeding IROLs or SOLs, the relevant reliability entities must 
take corrective control actions to return the system to a secure and 
reliable state as soon as possible and in no longer than 30 minutes. 
This is important to satisfy the relevant Reliability Standards such as 
IRO-005-0 and TOP-004-0 to minimize the amount of time the system 
operates in an insecure mode and is vulnerable to cascading outages.
b. Reliability Coordination--Facilities (IRO-002-1)
    900. IRO-002-1 establishes the requirements for data, information, 
monitoring and analytical tools and communication facilities to enable 
a reliability coordinator to meet the reliability needs of the 
Interconnection, to act in addressing real-time emergency conditions 
and to control analysis tools.\293\
---------------------------------------------------------------------------

    \293\ In its November 15, 2006, filing, NERC submitted IRO-002-
1, which supercedes the Version 0 Reliability Standard. IRO-002-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, IRO-002-1.
---------------------------------------------------------------------------

    901. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct NERC to submit a 
modification that: (1) Includes Measures and Levels of Non-Compliance 
and (2) modifies Requirement R7 to explicitly require a minimum set of 
tools for the reliability coordinator.
 i. Comments
    902. Dominion agrees with the proposal to require a minimum set of 
tools for reliability coordinators, explaining that such specificity is 
needed to ensure that proactive efforts to maintain reliability are 
being continuously pursued. According to Dominion, a general 
requirement for ``adequate'' tools is insufficient and the proposal to 
modify IRO-002-1 is appropriate since it will ensure that operators 
have a minimum set of tools with which to perform their duties.
    903. In contrast, both APPA and LPPC ask the Commission to reject 
the proposal to require a minimum set of tools because flexibility is 
needed to allow change as technology improves over time. LPPC states 
that the Commission should, instead, require a listing of capabilities 
that is not tied to a particular product or tool. APPA contends that, 
because the Measures now require the reliability coordinator to provide 
specifications to the Regional Entity to be in compliance, the Regional 
Entity will set the minimum standards for reliability tools. Further, 
according to APPA, setting a minimum requirement would establish a 
``lowest common denominator'' that might prove counterproductive.
    904. MRO states that IRO-002-0 is another Reliability Standard for 
which it will be difficult to identify Measures and Levels of Non-
Compliance because the Requirements include terms like ``adequate,'' 
``potential,'' ``could result'' and ``as required.''
ii. Commission Determination
    905. NERC's November 2006 revision to the Reliability Standard 
satisfies the proposal to include Measures and Levels of Non-
Compliance. While MRO comments that it will be difficult to identify 
Measures and Levels of Non-Compliance, it does not provide any specific 
suggestions for changes to NERC's proposal.
    906. Further, consistent with the NOPR, the Commission directs the 
ERO to modify IRO-002-1 to require a minimum set of tools that must be 
made available to the reliability coordinator. We believe that this 
requirement will ensure that a reliability coordinator has the tools it 
needs to perform its functions. Further, as noted by Dominion, such a 
requirement promotes a more proactive approach to maintaining 
reliability.
    907. With respect to the concerns of APPA and LPPC, the Commission 
clarifies that the Commission's intent is to have the ERO develop a 
requirement that identifies capabilities, not actual tools or products. 
The Commission agrees that the latter approach is not appropriate as a 
particular product could become obsolete and technology improves over 
time. We disagree with APPA that our concern is addressed by the new 
Measures as they neither specify a minimum set of capabilities nor 
require any uniformity among reliability coordinators or Regional 
Entities. We do not believe that the identification of minimum 
capabilities translates to ``lowest common denominator'' as suggested 
by APPA. If the Reliability Standards development process results in 
developing a ``lowest common denominator'' Reliability Standard that is 
geared toward guaranteeing compliance and avoiding penalties as opposed 
to ensuring reliability, the Commission could remand such a Reliability 
Standard.\294\
---------------------------------------------------------------------------

    \294\ See Order No. 672 at P 329.
---------------------------------------------------------------------------

    908. We disagree with MRO that it will be difficult to identify 
Measures and Levels of Non-Compliance since the Requirements include 
terms like ``adequate,'' ``potential,'' ``could result'' and ``as 
required.'' Many tariffs on file with the Commission do not specify 
every compliance detail, but rather provide some level of discretion as 
necessary to carry out a particular act. This does not mean the tariffs 
are unenforceable; rather, it means that, if a

[[Page 16506]]

dispute arises over compliance and there is a legitimate ambiguity 
regarding a particular fact or circumstance, that ambiguity can be 
taken into account in the exercise of the Commission's enforcement 
discretion.
    909. As we stated in the NOPR,\295\ Reliability Standard IRO-002-1 
serves an important purpose in ensuring that reliability coordinators 
have the information, tools and capabilities to perform their 
functions. The Measures and Levels of Non-Compliance submitted by NERC 
further enhance the Reliability Standard. Accordingly, the Commission 
approves Reliability Standard IRO-002-1 as mandatory and enforceable. 
In addition we direct the ERO to develop a modification to IRO-002-1 
through the Reliability Standards development process that requires a 
minimum set of tools that should be made available to reliability 
coordinators.
---------------------------------------------------------------------------

    \295\ NOPR at P 511.
---------------------------------------------------------------------------

 c. Reliability Coordination--Wide Area View (IRO-003-2)
    910. The purpose of IRO-003-2 is for a reliability coordinator to 
have a wide-area view of its own and adjacent areas to maintain 
situational awareness. Wide-area view also facilitates a reliability 
coordinator's ability to calculate SOL and IROL as well as determine 
potential violations in its own area.\296\
---------------------------------------------------------------------------

    \296\ In its November 15, 2006, filing, NERC submitted IRO-003-
2, which supersedes the Version 0 Reliability Standard. IRO-003-2 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, IRO-003-2.
---------------------------------------------------------------------------

    911. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission proposed to direct NERC to submit a 
modification that includes: (1) Measures and Levels of Non-Compliance 
and (2) criteria to define the term ``critical facilities'' in a 
reliability coordinator's area and its adjacent systems.
i. Comments
    912. APPA agrees that IRO-003-2 is sufficient for approval as a 
mandatory and enforceable Reliability Standard. However, APPA suggests 
that, instead of merely including criteria to define critical 
facilities as proposed, NERC and each Regional Entity should establish, 
document, use and make transparent the methodology, data and procedures 
they use to determine ``critical facilities.''
    913. Entergy agrees with the need for the criteria, but cautions 
that it must be flexible enough to allow for changing conditions 
experienced in real-time operations. Xcel notes that the term 
``critical facilities'' is not defined and suggests that the 
Reliability Standard not be approved until the term is defined.
ii. Commission Determination
    914. For the reasons stated in the NOPR,\297\ the Commission 
approves proposed Reliability Standard IRO-003-2 as mandatory and 
enforceable. NERC's November 2006 revision to the Reliability Standard 
satisfies the proposal to include Measures and Levels of Non-
Compliance.
---------------------------------------------------------------------------

    \297\ See NOPR at P 519.
---------------------------------------------------------------------------

    915. Further, pursuant to section 215(d)(5) of the FPA and Sec.  
39.5(f) of our regulations, we adopt in the Final Rule the proposal to 
direct that the ERO develop a modification to the Reliability Standard 
through the Reliability Standards development process to create 
criteria to define the term ``critical facilities'' in a reliability 
coordinator's area and its adjacent systems. In developing the required 
modification, the ERO should consider the suggestions of APPA, Entergy 
and Xcel.
d. Reliability Coordination--Operations Planning (IRO-004-1)
    916. The purpose of IRO-004-1 is to require each reliability 
coordinator to conduct next-day operations reliability analyses to 
ensure that the system can be operated reliably in anticipated normal 
and contingency system conditions. Operations plans must be developed 
to return the system to a secure operating state after contingencies 
and shared with other operating entities.
    917. In the NOPR, the Commission proposed to approve Reliability 
Standard IRO-004-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to submit a modification to IRO-
004-1 that requires the next-day analysis to identify effective control 
actions that can be implemented within 30 minutes during contingency 
conditions.
i. Comments
    918. APPA agrees that IRO-004-1 is sufficient for approval as a 
mandatory Reliability Standard and that the Requirements are 
sufficiently clear and objective to provide a basis for issuing a 
remedial action directive. However, it contends that many Requirements 
lack Measures and Levels of Non-Compliance, and the ERO and Regional 
Entities should not assess penalties until additional Measures and 
Levels of Non-Compliance are developed.
    919. Entergy agrees that a mitigation plan for potential operating 
problems identified in the next-day analysis may be an appropriate 
requirement, but cautions that it would be inappropriate to penalize an 
entity that chooses an alternate mitigation strategy when the issues 
arise in real time based on system conditions prevalent at that time.
    920. APPA, in contrast, disagrees with the proposed directive to 
identify effective control actions in the next-day analysis. It 
contends that real-time conditions are seldom the same as predicted in 
the day-ahead schedule, and state estimators using real-time operating 
conditions are much more accurate than analyses based on day-ahead 
schedules.
    921. FirstEnergy contends that IRO-004-1 should require a day-ahead 
planning process and reflect activities inherent within a market 
operation.
    922. Northern Indiana contends that the Commission's proposed 
directive is unclear. It asks whether the Commission is requiring the 
reliability coordinator to secure the system to an N-2 state, rather 
than an N-1 state within the next-day planning analysis. It contends 
that currently the Reliability Standard is N-1, and requests 
clarification that the Commission did not intend to mandate an increase 
in security from N-1 to N-2 in the NOPR.
    923. California PUC agrees that there is merit in requiring system 
operators to assess the outlook for the following day, but nevertheless 
is concerned with the Commission's proposed directive. Its main concern 
is that the list of identified control actions can be too long or too 
generic to be effective to address the myriad potential system 
contingencies that could arise on the next day.
    924. California Cogeneration states that the proposed Reliability 
Standard allows reliability coordinators to require data on gross load 
and generation behind the site boundary meter, which is contrary to a 
prior Commission order.\298\
---------------------------------------------------------------------------

    \298\ California Independent System Operator Corp., 96 FERC ] 
63,015 at 7 (2001). It states in part ``The intent of the 
Commission's directive was to remove the requirement to provide any 
behind-the-meter information, whether on generation or load.''
---------------------------------------------------------------------------

ii. Commission Determination
    925. For the reasons stated in the NOPR,\299\ the Commission 
approves proposed Reliability Standard IRO-004-1 as mandatory and 
enforceable. In

[[Page 16507]]

addition, the Commission directs the ERO to develop modifications to 
the Reliability Standard, as discussed below.
---------------------------------------------------------------------------

    \299\ See NOPR at P 529.
---------------------------------------------------------------------------

    926. We agree with Entergy that system operators must make their 
decision to use the most effective control action based on the 
prevailing system conditions, to return the system to a secure state 
following a contingency. Therefore, the chosen control action may be 
different than those identified in next-day operations planning. We 
reiterate that our intent is to require a comprehensive next-day 
operations planning study that includes identification of effective 
solutions to aid system operators in real-time operations.
    927. We disagree with APPA's comment that day-ahead planning to 
identify effective control actions would not enhance system reliability 
because we believe this is also the intent of the ERO for including 
such a Requirement in this Reliability Standard.\300\ Our proposed 
directive is to augment the Requirement that the plans to alleviate SOL 
and IROL violations are assessed to ensure that the control actions can 
be implemented and effective within 30 minutes after a contingency.
---------------------------------------------------------------------------

    \300\ IRO-004-1 Purpose Statement states in part ``Plans must be 
developed to alleviate SOL and IROL violations.''
---------------------------------------------------------------------------

    928. We agree with APPA that state estimators and real-time 
contingency analyses using real-time operating conditions produce more 
accurate study results compared to those from next-day operations 
planning analyses that are based on day-ahead schedules and forecast 
conditions. However, we remain convinced that a proactive approach that 
includes identification of effective operating solutions to deal with 
contingencies is far superior to a reactive approach that identifies 
solutions when the system conditions prevail in real-time operations. 
The former can identify solutions that may not be otherwise available 
to the system operators--e.g. certain planned generation or 
transmission outages are approved conditional upon re-affirmation prior 
to their removal from service or a short recall time subject to certain 
system conditions developing in real-time operations.
    929. We disagree with FirstEnergy that IRO-004-1 should include the 
day-ahead planning process and reflect activities inherent in a market 
operation because day-ahead planning includes financial activities that 
may not occur in real-time. The Commission believes that, for 
reliability purposes, the simulation should include only what will 
actually occur.
    930. The proposed Reliability Standards IRO-005-1 and TOP-004-0 
require that in the event of an IROL violation, i.e. power flow on an 
interface exceeding its IROL, the system must be returned to a secure 
state within 30 minutes regardless of the cause of the violation, so 
that the system is once again capable of withstanding the next 
contingency without resulting in cascading failures.
    931. In response to Northern Indiana, our intent is not to mandate 
an increase in security from N-1 to N-2, but rather is to ensure there 
is no reliability gap in the IROL-related Reliability Standards. To do 
this, the Commission believes it is necessary to provide operators with 
control actions needed to mitigate an IROL violation while within the 
30-minute period after a first contingency. We are not requiring an 
increase to N-2, which would require planning the system for any two 
contingencies at all times.
    932. With respect to California PUC's comment, we note that it is 
just as important for day-ahead operation planners to review and derive 
system operating limits to deal with a myriad of contingencies for 
different system configurations and generation dispatches, as it is for 
them to assess the feasibility of returning the system to a secure 
operating state after these contingencies have occurred. Similar to 
reviewing and deriving SOLs and IROLs to ascertain that system 
reliability will be maintained based on the most onerous forecast 
conditions and critical contingencies, identifying corrective control 
actions would not encompass each and every contingency and system 
condition. This is because previous operating experiences and 
established operating practices would have covered a significant 
portion of the contingencies and the corresponding control actions 
already.
    933. We further note that for those few IROL contingencies under 
the forecast and most onerous system conditions, if operation planners 
equipped with a suite of off-line analytical tools, but without any 
burden, distraction or interference from real-time operations, cannot 
identify the effective control actions, it can be argued that it would 
be unrealistic to expect system operators to do so with an additional 
requirement--i.e. identification and implementation of an effective 
control action all within 30 minutes. In addition, the control actions 
identified in the next-day analysis may quite often provide relevant 
information to the system operators of the control options they have 
available.
    934. We believe that our use of NERC's definition of bulk electric 
system in combination with its registration process should assuage 
California Cogeneration's concerns.
    935. In response to APPA's concern that NERC did not provide a 
Measure for each Requirement, we reiterate that it is in the ERO's 
discretion whether each Requirement requires a corresponding Measure. 
The ERO should consider this issue through the Reliability Standards 
development process.
    936. Accordingly, we approve Reliability Standard IRO-004-1 as 
mandatory and enforceable. Further, we direct the ERO to modify IRO-
004-1 through the Reliability Standards development process to require 
the next-day analysis to identify control actions that can be 
implemented and effective within 30 minutes after a contingency. The 
Commission also directs the ERO to consider adding Measures and Levels 
of Non-Compliance to the Reliability Standard as requested by APPA.
e. Reliability Coordination--Current Day Operations (IRO-005-1)
    937. IRO-005-1 ensures energy balance and transmission reliability 
for the current day by identifying tasks that reliability coordinators 
must perform throughout the day.
    938. In the NOPR, the Commission proposed to approve Reliability 
Standard IRO-005-1 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to submit a modification to IRO-
005-1 that includes Measures and Levels of Non-Compliance. The 
Commission proposed that the Measures and Levels of Non-Compliance 
specific to IROL violations should be commensurate with the magnitude, 
duration, frequency and causes of the violation. Further, the 
Commission proposed to direct the ERO to conduct a survey on IROL 
practices and actual operating experiences, and indicated that it may 
propose further modifications to IRO-005-1 based on the survey 
results.\301\
---------------------------------------------------------------------------

    \301\ NOPR at P 545 (``We propose to direct NERC to perform a 
survey of present operating practices and actual operating 
experience concerning drifting in and out of IROL violations. As 
part of the survey, we will require reliability coordinators to 
report any violations of IROLs, their causes, the date and time of 
the violations, and the duration in which actual operations exceeded 
IROL to the ERO on a monthly basis for one year beginning two months 
after the effective date of the Final Rule.'')

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[[Page 16508]]

i. Comments
    939. FirstEnergy supports the approval of the proposed Reliability 
Standard as mandatory and enforceable as interpreted by NERC (i.e., 
that exceeding IROL for less than 30 minutes is not a violation), 
pending further action through the NERC Reliability Standards 
development process.
    940. MidAmerican supports the Commission's proposed survey and 
notes that based on its experience, IROL violations have been 
faithfully reported across NERC.
    941. The CAISO urges the Commission to proceed with caution if 
headed in the direction of absolute compliance with IROL. However, it 
supports the survey to determine the extent to which systems are 
actually ``drifting'' in and out of IROL limits.
    942. APPA indicates its support of the Commission's directive to 
undertake a survey regarding IROL practices and experiences. However it 
feels that it should be NERC's role to decide on the survey. It 
contends that, based on the survey results and using the Reliability 
Standard development process, NERC would decide what modifications to 
IRO-005-2 are appropriate.
    943. Entergy agrees that it is appropriate to use a mitigation plan 
to resolve an SOL or IROL violation when the actual contingency that 
causes an SOL or IROL violation is experienced. However, with an 
acceptable mitigation plan, it is not necessary to require transmission 
operators to keep facility loading below a level where a potential SOL 
or IROL violation would occur assuming a low probability of the 
contingency. Entergy requests clarification that the Commission's 
guidance is not intended to preclude the use of such alternative 
procedures. The Commission should be cautious not to restrictively 
define SOL or IROL in a manner that causes the system operator to take 
preemptive action through this Reliability Standard to address events 
that may technically be SOL or IROL violations, but which have a low 
probability of occurrence and can be mitigated through other proven 
procedures.
    944. ISO-NE agrees that NERC should promptly address the 
ambiguities in the current definition of an IROL. It has a concern that 
the phrase ``The Transmission Service Provider shall respect these SOLs 
and IROLs'' in Requirement R14 may cause confusion that this entity is 
expected to respect SOLs and IROLs in the operating time frame.\302\
---------------------------------------------------------------------------

    \302\ IRO-005-1 Requirement R14 states ``Each Reliability 
Coordinator shall make known to Transmission Service Providers 
within its Reliability Coordinator Area, SOLs or IROLs within its 
wide-area view. The Transmission Service Provider shall respect 
these SOLs or IROLs in accordance with filed tariffs and regional 
Total Transfer Calculation and Available Transfer Calculation 
processes.''
---------------------------------------------------------------------------

    945. TAPS raises an issue with Requirement R13 that states in part 
``[i]n instances where there is a difference in derived limits,* * * 
Load-Serving Entities * * * shall always operate the Bulk Electric 
System to the most limiting parameter.'' TAPS further states that, 
since LSEs do not operate the system within SOLs or IROLs, the only 
thing such entities, particularly small ones, can do is shed load. It 
contends that if the Reliability Standard is mandatory, it should apply 
only within the parameters proposed by NERC--subject to its Bulk 
Electric System definition and its June registry criteria. Further, 
given the apparent error in the Reliability Standard, the Commission 
should ask NERC to re-examine it.
ii. Commission Determination
    946. The Commission approves proposed Reliability Standard IRO-005-
1 as mandatory and enforceable. In addition, the Commission directs the 
ERO to develop modifications to the Reliability Standard through the 
Reliability Standards development process, as discussed below.
    947. The Commission clarifies the intent of and need for the 
proposed survey. We reiterate that the intent is to learn about the 
operating experiences and practices of operating entities; 
specifically, how they operate their systems to respect IROLs in the 
normal system conditions, i.e. prior to a contingency. The survey 
results will facilitate future development and modifications of IROL-
related Reliability Standards to better clarify and eliminate potential 
multiple interpretations of respecting IROLs that may exist in the 
proposed Reliability Standards.\303\ In addition, the survey will 
identify the reliability risks and the frequency and number of 
operating practices involving drifting in and out of IROL.\304\ The 
survey results will also provide guidance on the frequency, duration 
and magnitude of IROL violations, their causes and whether these IROL 
violations occur during normal or contingency conditions.
---------------------------------------------------------------------------

    \303\ NOPR at P 540: IRO-005-1 could be interpreted as allowing 
a system operator to respect IROLs in two possible ways: (1) 
Allowing IROL to be exceeded during normal operations, i.e., prior 
to a contingency, provided that corrective actions are taken within 
30 minutes or (2) exceeding IROL only after a contingency and 
subsequently returning the system to a secure condition as soon as 
possible, but no longer than 30 minutes. Thus, the system can be one 
contingency away from potential cascading failure if operated under 
the first interpretation and two contingencies away from cascading 
failure under the second interpretation.
    \304\ The term ``drifting in and out of IROLs'' refers to 
operating the normal system (i.e. prior to a contingency) with 
frequent occurrences in which IROLs are exceeded, but each 
occurrence lasting less than 30 minutes. Currently, this mode of 
operation is not considered as a violation of NERC Reliability 
Standards.
---------------------------------------------------------------------------

    948. We note the support from FirstEnergy, MidAmerican, CAISO and 
APPA for our proposed survey. Regarding MidAmerican's comment that 
reporting on IROL violations is a routine practice, we note that the 
proposed Reliability Standards only require reporting on those 
violations that have exceeded IROLs for longer than 30 minutes. The 
current reporting requirements and results will not provide an adequate 
assessment of the existing operating practices regarding IROLs and the 
reliability risks and the extent of drifting in and out of IROLs.
    949. In response to Entergy, the Commission believes that operating 
the system within IROL under normal system condition and exceeding IROL 
only after a contingency and subsequently returning the system to a 
secure condition as soon as possible, but no longer than 30 minutes, 
may be appropriate. This mode of operation will minimize the system 
risk of being one contingency away from potential cascading failures.
    950. ISO-NE asks that the ERO should promptly clarify the current 
definition for IROL violations. However, we do not share ISO-NE's 
concern that transmission service providers may be responsible for 
respecting SOLs and IROLs in real-time operation. Requirement R14 only 
requires a transmission service provider to use the SOLs and IROLs 
provided by the reliability coordinator in its tariff, it does not 
require any action in the operating time frame.
    951. We do not share TAPS' concern regarding LSEs initiating load 
shedding as their own control action to respect IROLs or SOLs. The 
appropriate control actions to respect IROLs and SOLs are the 
responsibilities of a reliability coordinator and transmission 
operator. If load shedding is required, it is the responsibility of a 
reliability coordinator or a transmission operator to direct the 
appropriate entities including LSEs to carry it out. However, we urge 
the ERO to provide further clarification in this regard and include 
TAPS' concern in developing the modification of this Reliability 
Standard.
    952. Accordingly, the Commission approves Reliability Standard IRO-
005-1 as mandatory and enforceable.

[[Page 16509]]

Further, because IRO-005-1 has no Measures or Levels of Non-Compliance, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission directs the ERO to develop a modification 
to IRO-005-1 through the Reliability Standards development process that 
includes Measures and Levels of Non-Compliance. The Commission further 
directs that the Measures and Levels of Non-Compliance specific to IROL 
violations must be commensurate with the magnitude, duration, frequency 
and causes of the violations and whether these occur during normal or 
contingency conditions. Finally, the Commission directs the ERO to 
conduct a survey on IROL practices and actual operating experiences by 
requiring reliability coordinators to report any violations of IROL, 
their causes, the date and time, the durations and magnitudes in which 
actual operations exceeds IROLs to the ERO on a monthly basis for one 
year beginning two months after the effective date of the Final Rule. 
We may propose further modifications to IRO-005-1 based on the survey 
results.
f. Reliability Coordination--Transmission Loading Relief (IRO-006-3)
    953. IRO-006-3 ensures that a reliability coordinator has a 
coordinated method to alleviate loadings on the transmission system if 
it becomes congested to avoid limit violations. IRO-006-3 establishes a 
detailed Transmission Loading Relief (TLR) process for use in the 
Eastern Interconnection to alleviate loadings on the system by 
curtailing or changing transactions based on their priorities and 
according to different levels of TLR procedures.\305\ The proposed 
Reliability Standard includes a regional difference for reporting 
market flow information to the Interchange Distribution Calculator 
rather than tagged transaction information for the MISO and PJM areas. 
It also includes by reference the equivalent Interconnection-wide 
congestion management methods used in the WECC and ERCOT regions.
---------------------------------------------------------------------------

    \305\ The equivalent Interconnection-wide transmission loading 
relief procedures for use in WECC and ERCOT are known as ``WSCC 
Unscheduled Flow Mitigation Plan'' and Section 7 of the ``ERCOT 
Protocols,'' respectively.
---------------------------------------------------------------------------

    954. In the NOPR, the Commission proposed to approve Reliability 
Standard IRO-006-3 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to submit a modification to IRO-
006-3 that: (1) Includes a clear warning that a TLR procedure is an 
inappropriate and ineffective tool to mitigate IROL violations; (2) 
identifies in a Requirement the available alternatives to use of the 
TLR procedure to mitigate an IROL violation and (3) includes Measures 
and Levels of Non-Compliance that address each Requirement. In 
addition, the Commission proposed to approve the WECC and ERCOT load 
relief procedures as superior to the national standard.
i. Comments
    955. APPA agrees that IRO-006-3 is sufficient for approval as a 
mandatory Reliability Standard. It suggests that the ERO should 
consider development of detailed Measures and Levels of Non-Compliance 
that address each Requirement in IRO-006-3. Until then, penalties 
should not be imposed except for egregious violations and the 
associated penalties should be imposed by the Commission.
    956. APPA, Entergy and MidAmerican agree that the TLR procedure is 
an inappropriate and ineffective tool to mitigate actual IROL 
violations and that a clear warning to that effect should be included. 
MidAmerican specifically suggests that the warning must also apply to 
actual emergency situations in addition to actual IROL violations.
    957. Similarly, ISO-NE supports the Commission's conclusions with 
regard to reliance on TLRs to address actual IROL violations. Further, 
it supports the Commission's proposal that the ERO should modify the 
Reliability Standard to provide flexibility for ISOs and RTOs to rely 
on redispatch as a means to mitigate an IROL violation.
    958. Xcel suggests that instead of the proposed modification of a 
clear warning, it should include a requirement that TLR procedures 
should not be used for alleviating actual IROL violations. It asserts 
that the latter approach would be more measurable than the Commission's 
proposed modification.
    959. Entergy and MidAmerican believe that TLR procedures can be an 
effective mechanism to avoid potential SOL and IROL violations or 
potential emergency situations.
    960. In contrast, Progress Energy disagrees with the Commission's 
reasoning on the ineffectiveness of using TLR procedures to alleviate 
actual IROL violations.
ii. Commission Determination
    961. The Commission approves IRO-006-3 as mandatory and 
enforceable. In addition, we direct the ERO to develop modifications to 
the Reliability Standard as discussed below.
    962. The Commission remains convinced, based on Blackout 
Recommendation No. 31,\306\ the submissions from APPA, Entergy, 
MidAmerican, ISO-NE and Xcel, and NERC's comments on the Staff 
Preliminary Assessment,\307\ that proposed directives to include a 
clear warning that a TLR procedure is an inappropriate and ineffective 
tool to mitigate IROL violations and to identify the available 
alternatives to use of the TLR procedure to mitigate an IROL violation 
are the appropriate improvements to address the deficiencies in using 
TLR procedures to mitigate actual IROL violations or actual emergency 
situations. The Commission endorses Blackout Recommendation No. 31.
---------------------------------------------------------------------------

    \306\ Blackout Recommendation No. 31, at 163 is to ``Clarify 
that the transmission loading relief (TLR) process should not be 
used in situations involving an actual violation of an Operating 
Security Limit.''
    \307\ The NERC comments to Staff Assessment at 49 state that 
``NERC agrees that the TLR procedure alone is usually not effective 
as a control measure to mitigate an IROL violation and explains that 
the TLR procedure was not intended to be effective in this manner.''
---------------------------------------------------------------------------

    963. The Commission agrees with Entergy and MidAmerican that TLR 
procedures can be an effective mechanism to avoid potential IROL 
violations and potential emergencies. Regarding this, we reiterate that 
our concerns have always been on the use of TLR to mitigate actual 
IROLs or actual emergencies, and not on potential IROLs or emergencies, 
as indicated in the Blackout Report, Staff Assessment and the NOPR.
    964. We do not understand Progress Energy's disagreement because no 
reason is provided.
    965. Accordingly, in addition to approving the Reliability 
Standard, the Commission directs the ERO to develop a modification to 
IRO-006-3 through the Reliability Standards development process 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. In developing the 
required modification, the ERO should consider the suggestions of 
MidAmerican and Xcel. In addition, the Commission approves the WECC and 
ERCOT load relief procedures as superior to the national Reliability 
Standard. As identified in the NOPR, the Commission directs the ERO to 
modify the WECC and ERCOT procedures to ensure

[[Page 16510]]

consistency with the standard form of the Reliability Standards 
including Requirements, Measures and Levels of Non-Compliance.\308\
---------------------------------------------------------------------------

    \308\ See NOPR at P 564-65.
---------------------------------------------------------------------------

g. Regional Difference to IRO-006-3: PJM/MISO/SPP Enhanced Congestion 
Management (Curtailment/Reload/Reallocation)
i. Background
    966. As explained in the NOPR, IRO-006-003 provides for a regional 
difference for MISO, PJM and SPP.\309\ According to NERC, the regional 
difference is needed to allow RTO market practices, simplify 
transaction information requirements for market participants, and 
provide reliability coordinators with appropriate information for 
security analysis and curtailments, reloads, reallocations and 
redispatch requirements.
---------------------------------------------------------------------------

    \309\ NOPR at P 568.
---------------------------------------------------------------------------

    967. The regional difference to IRO-006-3 applies the congestion 
management process included in Joint Operating Agreements filed by 
MISO, PJM and SPP and specified in seams agreements reached among MISO, 
PJM, and their neighboring non-market areas during the RTOs' market 
formation and expansions. Under the congestion management process in 
the waiver, each RTO calculates an amount of energy (market flow) 
flowing across coordinated flowgates. These market flows are separated 
into their appropriate priorities based on the RTO's schedules and 
reservations and are available for curtailment under the appropriate 
TLR Levels in the NERC interchange distribution calculator. Under the 
TLR method for curtailing interchange transactions and in the per 
generator method for generation-to-load impacts, NERC uses a five 
percent curtailment threshold, but in the waiver, the RTO's market 
flows with an impact of greater than zero percent on a coordinated 
flowgate are represented and made available for curtailment under the 
appropriate TLR priorities.
    968. In their comments on the Staff Preliminary Assessment, MISO-
PJM contended that there is unduly discriminatory treatment of the 
market flows of MISO and PJM versus the generation-to-load impacts of 
non-market entities because the waiver subjects the RTOs to curtailment 
(and the corresponding redispatch costs) in circumstances where the 
non-market entities would not be subject to curtailment.
    969. In the NOPR, the Commission did not propose to approve or 
remand this regional difference.
ii. Comments
(a) Application of the Regional Difference
    970. MISO-PJM contends that there is unduly discriminatory 
treatment against market flows of MISO and PJM during the application 
of the TLR Standard. The RTOs argue that NERC should modify IRO-006-3 
and the MISO and PJM regional difference to require modifying the 
market flow threshold used by the interchange distribution calculator 
to assign relief obligations to MISO, PJM, and SPP from zero to a 
standard percentage that is technically feasible to implement on a non-
discriminatory basis, netting of market flow impacts, tag impacts, and 
generation-to-load impacts, and reporting to the interchange 
distribution calculator all net generation-to-load impacts for both 
market and non-market transmission providers. Constellation supports 
MISO-PJM's argument that there is unduly discriminatory treatment of 
the MISO and PJM market flows compared to the generation-to-load 
impacts of non-market entities in the application of the TLR standard.
    971. MISO-PJM indicates that they have raised the equity issue with 
the NERC Operating Reliability Subcommittee (Operating Subcommittee), 
that their markets currently are being asked to curtail market flow 
impacts down to zero percent while tagged transactions and generation-
to-load impacts during TLR 5 are being asked to curtail impacts that 
are five percent or greater. MISO-PJM states that the NERC Operating 
Subcommittee has indicated that they will address reliability issues 
only and that they are not the appropriate group to address equity 
issues.
(b) Seams Agreements
    972. Several entities argue that the Commission should not overturn 
the existing IRO-006-3 regional difference. MidAmerican states that 
MISO and PJM should continue to pursue a negotiated solution to the 
issues outlined in MISO-PJM's filings. Mid-Continent states that the 
Commission should reject the MISO-PJM proposal to require NERC to allow 
them to report only the transactions with five percent or greater 
impacts on flowgates rather than report all transactions for 
curtailments, since MISO and PJM offered to report all transactions to 
avoid negative impacts on the reliability of the transmission system. 
Mid-Continent argues that not doing so would impact the reliability of 
the transmission system.
    973. Mid-Continent asks the Commission to not implement MISO and 
PJM's proposal to modify NERC's procedures and to not override seams 
agreements. MidAmerican claims that MISO-PJM comments amount to an 
abrogation of existing seams agreements. MidAmerican states that the 
seams agreements were negotiated in a give-and-take process between the 
parties resulting in the existing waiver which was proposed by PJM and 
MISO in response to Commission orders. MidAmerican states that if any 
changes are sought to these waivers, they should be addressed in 
negotiation with the appropriate parties. MidAmerican suggests that any 
changes should be requested by way of the NERC process for developing 
Reliability Standards and that any negotiated agreements should be 
presented to the Commission for approval. Mid-Continent claims that 
MISO-PJM have not provided valid reasons to replace the current 
Reliability Standards or to take actions that would modify existing 
seams agreements signed by MISO and PJM. Mid-Continent asks the 
Commission not to short-circuit the NERC Reliability Standards process 
which will give full consideration to the reliability implications of 
MISO's and PJM's proposal.
    974. APPA agrees with the Commission's proposed approach in 
allowing MISO, PJM, NERC and other ``relevant entities'' to continue 
their negotiations regarding this regional difference. APPA cautions 
that any agreement reached by NERC and approved by the Commission 
regarding a regional difference for this Reliability Standard should be 
governed by reliability considerations and should not permit market 
design considerations to override NERC's Reliability Standards. 
MidAmerican suggests a process where the RTOs invite parties to 
reconsider the seams agreements, the parties negotiate changes, the 
Commission approves new agreements and waivers are then sought from 
NERC to the extent necessary. MidAmerican argues that since the RTOs do 
not allege any reliability problem there is no need to reject or upend 
the existing NERC waiver.
(c) Modifying the Congestion Management Process and Alternatives for 
Temporary Application of the Waiver
    975. Mid-Continent states that it agrees with the Commission's 
proposal to not adopt MISO and PJM's request to instruct NERC to modify 
the current waiver to the TLR in the RTOs and believes that instead the 
Commission should direct NERC to address these issues through the 
Reliability Standards

[[Page 16511]]

development process with input from neighboring systems. Mid-Continent 
states that changes to the waiver must not discriminate against non-
market regions; must not negatively impact the reliability of 
neighboring systems and must be consistent with seams agreements signed 
by the RTOs.
    976. NRECA claims that issues associated with market flows and 
generation-to-load impacts have not been resolved and is concerned that 
MISO-PJM's suggestion that ``consensus'' has been reached on the issues 
is premature. NRECA is also concerned that implementation of the MISO 
and PJM proposal could increase reliance on TLRs. NRECA urges the 
Commission to not short circuit or circumvent the Reliability Standards 
development process or the RTO stakeholders process and states that the 
Commission should permit the stakeholders to reach full consensus.
    977. MISO-PJM indicates that they have been working with both the 
NERC Operating Subcommittee and the Congestion Management Process 
Working Group (Congestion Working Group) to achieve a consensus on 
these changes, and that based on this, the Commission stated in the 
NOPR that it prefers that MISO, PJM and others continue negotiations to 
resolve these issues rather than imposing a solution on market 
participants. MISO-PJM state that they have held extensive discussions 
with a group composed of NERC Operating Subcommittee and Congestion 
Working Group participants. MISO-PJM indicates that detailed analyses 
has been performed to evaluate the effect of changing the market flow 
threshold from zero percent to five percent in one percent increments 
and that the NERC Operating Subcommittee has recommended that the 
market flow threshold used by the interchange distribution calculator 
to assign relief obligations to the MISO, PJM, and SPP be changed from 
zero percent to three percent for a 12 month interim period. MISO-PJM 
assert that at the end of the 12 months, a decision will be made 
whether to recommend a permanent change to the market flow threshold 
from zero percent to three percent or a change to some other value. 
MISO-PJM state that according to the NERC Operating Subcommittee, this 
recommendation is to only address the reliability issue raised by MISO, 
PJM and SPP so that they are able to meet their relief assignment 
during TLR.
    978. MISO-PJM also states that to receive congestion management 
process Council endorsement and support for the change being developed 
by the NERC Operating Subcommittee group, it requires unanimous 
approval by the congestion management process Council and that, though 
the 12 month field test to change the market flow threshold from zero 
percent to three percent has the support of MISO, PJM, SPP and TVA, it 
does not have the unanimous approval of all signatories to the seams 
agreements. MISO-PJM states that MAPPCOR (MAPP) has not agreed to the 
field test recommended by the NERC Operating Subcommittee and that MAPP 
has asserted that MISO should continue to honor their contractual 
obligation and report market flow impacts down to zero percent for 
relief assignments as specified in the MISO-MAPP Seams Operating 
Agreement. MISO is concerned that once the field test is complete and 
the NERC Operating Subcommittee recommends the use of a three percent 
threshold or some other threshold to address the reliability issue, the 
MISO may still have a contractual obligation with MAPP to use market 
flows down to zero percent for relief assignments. MISO-PJM states that 
this contractual obligation can only be altered if MISO and MAPP can 
agree on a change to the Seams Operating Agreement but expects 
resistance to change the Seams Operating Agreement. MISO and PJM do not 
believe they can address the equity issue by continuing discussions 
with the NERC Operating Subcommittee.
    979. MISO-PJM also state that by continuing to use market flows 
down to zero percent for relief assignments on reciprocally coordinated 
flowgates between MISO and MAPP, there will be situations where MISO is 
unable to meet its relief obligation. MISO-PJM states that they have 
sought unsuccessfully to execute redispatch agreements with those 
parties who have direct counter-flow on the identified flowgates where 
the MISO is unable to meet its relief obligation. MISO-PJM believe that 
the Commission should address this continuing discriminatory treatment 
of the market impacts on flowgates. MISO-PJM state that of the three 
areas where MISO-PJM raised comments on discriminatory treatment of the 
markets, only one area (changing the market flow threshold for a 12 
month field test) has resulted in steps being taken to address the 
discriminatory treatment and that even this one area can only be 
considered a partial success because there is only a solution to 
address the reliability issue, but not the equity issue.
    980. MISO-PJM explain in their supplemental comments that NERC has 
demonstrated a willingness to consider the reliability issue by 
authorizing a 12 month field test allowing PJM, MISO and SPP market 
flows to use a three percent threshold, to observe the impact on 
reliability, but will not address what it refers to as ``equity 
issues.'' MISO-PJM explains the field test has been approved by all the 
reciprocal entities that have signed seams agreements except MAPP. 
MISO-PJM state that, at the end of the 12 months, a decision will be 
made whether to use a three percent threshold or some other threshold 
to address the reliability concerns. MISO-PJM explain that the same 
entities that make up the Mid-Continent objected to the field test 
because they asserted MISO has a contractual obligation under the MAPP 
Seams Operating Agreement to continue reporting its market flows down 
to zero percent. MISO-PJM contend that because the MISO has agreed to 
honor its contractual obligation during the field test and will 
continue to use a zero percent threshold for all flowgates that are 
reciprocal between MISO and MAPP, this means that the flowgates under 
the control of the Mid-Continent parties will not participate in the 
field test and NERC will have no data to show the impact of changing 
the market flow threshold to three percent on these flowgates.
    981. MISO-PJM state that as long as the regional difference does 
not become a mandatory standard during the field test, they are 
satisfied that appropriate steps are being taken to address 
reliability.
(d) Reporting of Generator to Load Impacts by Non Market Areas
    982. MISO-PJM supports modifications to the TLR process that would 
require all participants (both market and non-market) to report their 
market flow impacts and generator-to-load impacts to the interchange 
distribution calculator and honor their allocations when they report 
their firm versus their non-firm usage. MISO-PJM believes that taking 
this step would also address the threshold equity issue and the netting 
issue because all entities would be subject to the same treatment. 
MISO-PJM requests that the Commission to either direct NERC to initiate 
a process to modify the interchange distribution calculator such that 
market flows and generator-to-load impacts from non-market areas are 
both reported to the interchange distribution calculator and are 
subject to curtailment based on their priorities from the allocations 
or that the Commission take action to do so.
    983. MISO-PJM states that the reporting of generator-to-load 
impacts by the non-market entities is the one area that is not 
currently under

[[Page 16512]]

discussion with a stakeholder group. MISO-PJM explains that both the 
market and non-market entities receive an allocation on flowgates and 
that both the market entities and the non-market entities use the 
allocations when selling firm transmission service. MISO-PJM states 
that only the market entities report their market flows to the 
interchange distribution calculator and use their allocations to 
determine what portion of market flows will be considered firm and 
believe that the non-market entities could also report their firm and 
non-firm generator-to-load usage to the interchange distribution 
calculator and receive relief assignments based on this usage. MISO-PJM 
indicates that this would remove the assumption that all generator-to-
load impacts from the non-market entities represent firm usage. MISO-
PJM states that reporting relief obligations by one group of 
participants and not reporting by the other results in conflicting 
actions during the TLR process because market entities suffer the 
financial consequences of redispatch at the same time reliability is 
not being accomplished due to off-setting actions by non-market 
entities.
    984. MISO-PJM states that, to address the discriminatory treatment 
of the markets, the Commission could order the TLR Reliability Standard 
to be modified to have the market entities discontinue reporting their 
market flows to the interchange distribution calculator. MISO-PJM 
believes that instead of this order, the preference is to have the 
market entities continue reporting their market flow impacts and the 
non-market entities report their generator-to-load impacts to the 
interchange distribution calculator. The allocations would be used to 
set the priority of these impacts.
    985. Mid-Continent states that the regional difference requiring 
PJM and MISO to report all flows instead of net flows was part of the 
commitments MISO and PJM made to meet NERC's tagging requirements. Mid-
Continent contends that it is appropriate to treat MISO-PJM market 
flows differently because they are greater than the system flows that 
resulted from control area-based system operation. Mid-Continent 
further claims that MISO cannot achieve the redispatch the interchange 
distribution calculator requires because of MISO's own actions since 
MISO does not report actual flows to the interchange distribution 
calculator and MISO and PJM's congestion management tools do not 
utilize all redispatch options.
(e) Accounting for Counter Flows During TLR
    986. MISO-PJM state that there have been discussions at the NERC 
Operating Subcommittee about taking into account counter-flows during 
TLR when assigning relief. MISO-PJM contends that by considering 
counter-flows, those entities that are responsible for the loading 
problem on a net basis will be responsible for fixing the loading 
problem during TLR. MISO-PJM states that the MISO, PJM and SPP markets 
operate on a net flow basis and, therefore, have additional reasons for 
wanting to consider counter-flows. MISO-PJM expects that by summer 
2007, the Task Force will have a recommendation on netting in the 
interchange distribution calculator for the NERC Operating Subcommittee 
to consider. MISO-PJM state that it is premature to speculate on the 
outcome of the discussions with the NERC Operating Subcommittee at this 
time. MISO-PJM clarifies that they are not asking the Commission to 
take any action on this issue but to let the NERC Operating 
Subcommittee address the technical merits of netting impacts in the 
interchange distribution calculator.
    987. Mid-Continent states that eliminating the requirements to 
report flows in both directions may adversely impact reliability 
because the interchange distribution calculator will not have enough 
information to assign responsibilities to the contributors of a 
constraint.
iii. Commission Determination
    988. The Commission will not approve or remand this regional 
difference. The treatment of the market flows of MISO-PJM versus the 
generation-to-load impacts of non-market entities in the application of 
the TLR standard has been addressed by the Commission in a number of 
cases.\310\ In approving the plans of various transmission owning 
utilities to join PJM, the Commission attached several conditions 
including a requirement that certain non-market utilities be held 
harmless from effects of loop flow and congestion resulting from the 
utilities' RTO choices.\311\ Further, during MISO's market start 
up,\312\ the Commission determined that the markets could not start 
without the MISO having at least a specific, transparent plan for how 
it will handle the interface of multiple transmission tariffs and 
market-to-non-market seams \313\ and required the MISO to file any 
resolution of seams, or a status report of progress on seams resolution 
including detailed plans as to how MISO will address seams absent 
agreements, within 60 days of the date of the order. The regional 
difference to IRO-006-3 applies the congestion management process that 
was included in the Joint Operating Agreement filed by MISO, PJM and 
SPP and that was specified in the seams agreements reached between 
MISO, PJM, and their neighboring non-market areas in order to meet the 
Commission's requirements described above.\314\
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    \310\ See Alliance Companies, 100 FERC ] 61,137 (2001) and 
Midwest Independent Transmission System Operator, Inc. and PJM 
Interconnection, L.L.C., 106 FERC ] 61,251 (2004).
    \311\ Commonwealth Edison Company and American Electric Power 
Service Corporation, 106 FERC ] 61,250 (2004). This order required 
ComEd to demonstrate that its proposal held utilities in Wisconsin 
and Michigan harmless from all adverse impacts associated with loop 
flow or congestion that would result from its choice to join PJM.
    \312\ See Midwest Independent Transmission System Operator, 
Inc., 108 FERC ] 61,163 (2004).
    \313\ To resolve this issue, the Commission encouraged market 
participants to use the PJM-Midwest ISO joint operating agreement as 
a model or starting point for seams agreements, particularly with 
respect to the seams with the various utilities in the MAPP region.
    \314\ See Midwest Independent Transmission System Operator, 
Inc., 110 FERC ] 61,290 (2005).
---------------------------------------------------------------------------

    989. The Commission recognizes MISO-PJM's concerns that: (1) The 
congestion management process could be placing an undue burden on the 
RTO regions to provide redispatch especially on remote flowgates where 
an RTO's dispatch has a small impact and (2) under the congestion 
management process, the calculation of market flows for relief 
assignments on Reciprocal Coordinated Flowgates between the MISO and 
MAPP could create situations where MISO is unable to meet its relief 
obligation without curtailing load. We also understand that these 
concerns are exacerbated by the possibility of civil penalties for non-
compliance with the requirement to use market flows down to zero 
percent for relief assignments on reciprocal coordinated flowgates 
between MISO and MAPPCOR. Especially during transitions when markets 
with multiple control areas are started up, markets are expanded to 
include other control areas, or non-market control areas are 
consolidated, this can have an effect on the loop flows experienced by 
neighboring regions and the redispatch required by the neighboring 
regions due to fewer tagged transactions reported to the interchange 
distribution calculator. The Commission recognizes that there are 
concerns by neighboring entities to be held harmless from increased 
redispatch responsibility caused by these transitions.

[[Page 16513]]

    990. The Commission concludes that the issues described by MISO-PJM 
(i.e., defining the obligation of a certain region to provide 
redispatch when a flowgate becomes congested) are best handled through 
seams agreements rather than being subject to the NERC processes. We 
recognize that the two areas of seams agreements and Reliability 
Standards could overlap if the agreements reached do not allow for 
reliable outcomes where parties can achieve the relief assigned. As 
such, the Commission will neither approve nor remand the waiver of the 
regional difference to IRO-006-3 while the 12-month field test allowing 
PJM, MISO and SPP market flows to use a three percent threshold is 
being conducted. After the 12-month field test is complete, the 
Commission will reexamine approving the waiver as a mandatory and 
enforceable Reliability Standard.
    991. The Commission instructs the RTOs to continue working with the 
non-market regions to develop revised seams agreements that allow for 
equitable and feasible treatment of market flows in the NERC TLR/
redispatch process. The solution should not harm system reliability and 
should not subject either non-RTO transmission owners or the RTO 
markets to unreasonable redispatch responsibilities. We note that if 
consensus cannot be reached, the RTOs may file a section 205 or section 
206 proposal to revise the terms and conditions of the congestion 
management process if the terms agreed on in the seams agreements and 
Joint Operating Agreement have become unjust or unreasonable or may 
file to terminate the agreements as allowed in the seams agreements.
    992. The Commission will not adopt MISO-PJM's proposal to require 
non-market entities to report their generator-to-load impacts to the 
interchange distribution calculator with the allocations used to set 
the priority of these impacts in this Reliability Standards process. If 
NERC determines that this information and corresponding curtailment 
options are needed for reliability, NERC should file to modify IRO-006-
3 to include these additions. However, the economic implications of the 
reporting of generator-to-load impacts by non-market entities are not 
in the scope of the reliability process and are better addressed on a 
case-by-case basis or, as appropriate, in the proceeding on RTO Border 
Utility Issues.\315\
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    \315\ See RTO Border Utility Issues, Notice of Technical 
Conference on Seams Issues for RTOs and ISOs in the Eastern 
Interconnections (Docket No. AD06-9-000) (issued Jan. 25, 2007).
---------------------------------------------------------------------------

    993. In addressing MISO-PJM's claim that the ERO should modify IRO-
006-3 and the MISO-PJM regional difference to require netting 
generation-to-load impacts to recognize counterflow, we will let the 
ERO Operating Subcommittee address the technical merits of netting flow 
impacts in the interchange distribution calculator.
h. Procedures, Processes, or Plans To Support Coordination Between 
Reliability Coordinators (IRO-014-1)
    994. The stated purpose of IRO-014-1 is to ensure that each 
reliability coordinator's operations are coordinated so that they will 
not have an adverse reliability impact on other reliability coordinator 
areas and to preserve the reliability benefits of interconnected 
operation. Specifically, IRO-014-1 ensures energy balance and 
transmission by requiring a reliability coordinator to have operating 
procedures, processes or plans for the exchange of operating 
information and coordination of operating plans.
    995. In the NOPR, the Commission proposed to approve IRO-014-1 as 
mandatory and enforceable.
i. Comments
    996. APPA agrees with the Commission's proposed approval of IRO-
014-1 as mandatory and enforceable.
ii. Commission Determination
    997. For the reasons stated in the NOPR, the Commission approves 
IRO-014-1 as mandatory and enforceable.
i. Notifications and Information Exchange Between Reliability 
Coordinators (IRO-015-1)
    998. IRO-015-1 establishes Requirements for a reliability 
coordinator to share and exchange reliability-related information among 
its neighbors and participate in agreed-upon conference calls and other 
communication forums with adjacent reliability coordinators.
    999. In the NOPR, the Commission proposed to approve IRO-015-1 as 
mandatory and enforceable.
i. Comments
    1000. APPA agrees with the Commission's proposed approval of IRO-
015-1 as mandatory and enforceable.
ii. Commission Determination
    1001. For the reasons stated in the NOPR, the Commission approves 
IRO-015-1 as mandatory and enforceable.
j. Coordination of Real-Time Activities Between Reliability 
Coordinators (IRO-016-1)
    1002. IRO-016-1 establishes Requirements for coordinated real-time 
operations, including: (1) Notification of problems to neighboring 
reliability coordinators and (2) discussions and decisions for agreed-
upon solutions for implementation. It also requires a reliability 
coordinator to maintain records of its actions.
    1003. In the NOPR, the Commission proposed to approve IRO-016-1 as 
mandatory and enforceable.
i. Comments
    1004. APPA agrees with the Commission's proposed approval of IRO-
015-1 as mandatory and enforceable. However, it indicates that it is 
unclear in Level of Non-Compliance 2.1, how a reliability coordinator 
can demonstrate that it coordinated with other reliability coordinators 
without having retained evidence such as detailed logs or telephone 
recordings of having done so.\316\
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    \316\ IRO-016-1 Level of Non-Compliance 2.1 states: ``For 
potential, actual or expected events which required Reliability 
Coordinator-to-Reliability Coordinator coordination, the Reliability 
Coordinator did coordinate, but did not have evidence that it 
coordinated with other Reliability Coordinators.''
---------------------------------------------------------------------------

ii. Commission Determination
    1005. For the reasons stated in the NOPR, the Commission approves 
IRO-016-1 as mandatory and enforceable.
    1006. We construe Level of Non-Compliance 2.1 as requiring evidence 
of coordination, but allowing flexibility on the type of evidence.
8. MOD: Modeling, Data, and Analysis
    1007. The Modeling, Data and Analysis group of Reliability 
Standards is intended to standardize methodologies and system data 
needed for traditional transmission system operation and expansion 
planning, reliability assessment and the calculation of available 
transfer capability (ATC) in an open access environment. The 23 MOD 
Reliability Standards may be grouped into four distinct categories. The 
first category covers methodology and associated documentation, review 
and validation of Total Transfer Capability (TTC), ATC, Capacity 
Benefit Margin (CBM) and Transmission Reliability Margin (TRM) 
calculations.\317\ The second category covers steady-state and dynamics 
data and models.\318\ The third category

[[Page 16514]]

covers actual and forecast demand data.\319\ The fourth category covers 
verification of generator real and reactive power capability.\320\
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    \317\ MOD-001-0 through MOD-009-0.
    \318\ MOD-010-0 through MOD-015-0.
    \319\ MOD-016-0 through MOD-021-0.
    \320\ MOD-024-1 through MOD-025-1.
---------------------------------------------------------------------------

    1008. In the NOPR, the Commission proposed that one out of 23 MOD 
Reliability Standards be approved unconditionally, nine be approved 
with direction for modification and 13 remain pending with direction 
for modification.\321\ The Commission, describing these 13 pending 
standards as fill-in-the-blank Reliability Standards, generally 
proposed to seek additional information before acting on them. 
Responding to CenterPoint's proposal to exempt ERCOT from the MOD 
Reliability Standards that address available transfer capability, the 
Commission explained that it would consider any regional difference at 
the time NERC submits one for Commission review. Therefore, the 
Commission stated that if ERCOT wished to request a regional 
difference, it should do so through the ERO process.
---------------------------------------------------------------------------

    \321\ Approved: MOD-018-0; approved with modification: MOD-06-0, 
MOD-007-0, MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, MOD-019-0 
through MOD-021-0; and pending: MOD-001-0 through MOD-005-0, MOD-08-
0, MOD-09-0, MOD-011-0, MOD-013-1 through MOD-015-0, MOD-024-1 and 
MOD-025-1.
---------------------------------------------------------------------------

i. Comments
    1009. ISO/RTO Council and ISO-NE agree with the Commission's 
proposal to neither approve nor remand the 13 MOD Reliability Standards 
until NERC supplies additional information. ISO/RTO Council and ISO-NE 
also recommend that the Commission go further and defer its approval of 
the MOD Reliability Standards that incorporate references to the 13 
fill-in-the-blank Reliability Standards until those 13 are approved 
unconditionally. ISO/RTO Council and ISO-NE believe that the following 
Reliability Standards are dependent upon the 13 fill-in-the-blank 
standards: MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, MOD-018-0, MOD-
019-0, and MOD-021-0 and as such, the Commission should not approve and 
make them enforceable at this time. ISO-NE warns that these listed 
standards share the same infirmities as the 13 the Commission found it 
could not yet approve. ISO-NE cautions that until the missing 
information is provided in the 13 cross-referenced standards, it will 
be impossible for the affected entities to determine what criteria they 
are expected to satisfy.
    1010. EPSA, in contrast to ISO/RTO Council and ISO-NE, expresses 
its concern with the Commission's proposal not to act on the 13 fill-
in-the-blank standards. EPSA considers the fill-in-the-blank standards 
vitally important to reliability and competitive markets and worries 
that progress may be lost while the regions endeavor to file the 
additional required information.
ii. Commission Determination
    1011. The Commission will adopt the NOPR proposal and retain the 
same disposition of the MOD Reliability Standards that it proposed 
there. We confirm in this Final Rule that one out of 23 MOD standards 
is approved unconditionally, nine are approved with direction for 
modification and 13 remain pending with direction for modification. We 
will discuss our rationale for this decision in the Commission 
Determination section for each particular Reliability Standard.
    1012. We reject ISO/RTO Council and ISO-NE's request that we defer 
our approval of Reliability Standards from the MOD group that 
incorporate references to the 13 fill-in-the-blank standards. While we 
understand ISO/RTO Council and ISO-NE's concern about cross-referencing 
pending Reliability Standards, the data that is needed will be provided 
as described in the Common Issues section.\322\ In the interim, 
compliance with the pending Reliability Standards should continue on a 
voluntary basis, and the Commission considers compliance with them a 
matter of good utility practice. The Commission believes, moreover, 
that the blanks will be filled in in a timely manner, since in this 
rule we require the ERO to develop a Work Plan and submit a compliance 
filing describing the process for collection of the information set 
forth in the deferred standards.
---------------------------------------------------------------------------

    \322\ See Common Issues Pertaining to Reliability Standards: 
Fill-in-the-Blank Standards, supra section II.E.5.
---------------------------------------------------------------------------

    1013. In response to EPSA's concern that opportunities for 
discrimination and concerns about reliability remain while we await 
additional information, we emphasize that the Commission has provided 
specific direction regarding appropriate modifications to the MOD 
standards here and in Order No. 890, and has required the submission of 
a Work Plan for completion of that work within 90 days.\323\ Moreover, 
the OATT and OASIS transparency reforms adopted in Order No. 890 will 
ensure that opportunities for discrimination will be minimized while 
NERC completes work on the MOD Reliability Standards.
---------------------------------------------------------------------------

    \323\ OATT Reform Final Rule, Order No. 890, issued February 15, 
2007.
---------------------------------------------------------------------------

b. MOD Standards Related to ATC, TTC, CBM and TRM
i. OATT Reform and the MOD Standards
    1014. As pointed out in the NOPR, the Commission has been 
considering ATC, TTC, CBM and TRM calculation issues in Docket Nos. 
RM05-17-000 and RM05-25-000, and addressed them in Order No. 890. In 
order to maintain a consistent approach with regard to ATC issues, we 
confirm here the determinations made in Order No. 890. Each such 
determination is addressed below.
    1015. In Order No. 890, the Commission addressed the potential for 
undue discrimination by requiring industry-wide consistency and 
transparency of all components of ATC calculation methodology and 
certain definitions, data and modeling assumptions. The Commission also 
indicated there that the lack of consistent, industry-wide ATC 
calculation standards poses a threat to the reliable operation of the 
Bulk-Power System, particularly with respect to the inability of one 
transmission provider to know with certainty its neighbors' system 
conditions affecting its own ATC values. As a result of this 
reliability component, the Commission asserted that the proposed ATC 
reforms are also supported by FPA section 215, through which the 
Commission has the authority to direct the ERO to submit a Reliability 
Standard that the Commission considers appropriate to implement FPA 
section 215.\324\
---------------------------------------------------------------------------

    \324\ FPA section 215(d)(5).
---------------------------------------------------------------------------

    1016. In Order No. 890, the Commission directed public utilities, 
working through NERC and NAESB, to develop Reliability Standards and 
business practices to improve the consistency and transparency of ATC 
calculations. The Commission required public utilities, working through 
NERC, to modify the ATC-related Reliability Standards within 270 days 
of publication of Order No. 890 in the Federal Register. The Commission 
also directed public utilities to work through NAESB to develop 
business practices that complement NERC's new Reliability Standards 
within 360 days of publication of Order No. 890 in the Federal 
Register. Finally, the Commission directed NERC and NAESB to file a 
joint status report on standards and business practices development, 
and a Work Plan for completion of this

[[Page 16515]]

task, within 90 days of publication of Order No. 890 in the Federal 
Register.
    1017. The electric utility industry has also acknowledged this 
problem and has taken steps to address the lack of consistency and 
transparency in the way ATC is calculated. NERC formed a Long-Term 
Available Flowgate Capacity Task Force to review NERC's standards on 
ATC, which issued a final report in 2005.\325\ Based on the 
recommendations in the NERC Report, NERC has begun two Standards 
Authorization Request proceedings to revise the standards on ATC.\326\ 
NAESB has also begun a proceeding to develop business practice 
standards to enhance the processing of transmission service requests 
that affect ATC calculation. Following the issuance of the OATT Reform 
NOPR on May 19, 2006, and the Reliability Standards NOPR on October 19, 
2006, NERC accelerated development of these standards in accordance 
with the guidelines provided in these NOPRs. NERC and NAESB 
representatives participated in the Commission's Technical Conference 
held on October 12, 2006, and informed the Commission on the status of 
Reliability Standards development.\327\ NERC posted the Draft Standard 
MOD-001-1, proposing ATC/TTC/AFC (Available Flowgate Capability) 
revisions, on its Web site on February 15, 2007.\328\
---------------------------------------------------------------------------

    \325\ The NERC Report made recommendations for greater 
consistency and greater clarity in the calculation of ATC/AFC. The 
task force also recommended greater communication and coordination 
of ATC/AFC information to ensure that neighboring entities exchange 
relevant information. See NERC, Long-Term AFC/ATC Task Force Final 
Report (2005) (NERC Report) at 2, available at: fttp://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf.
    \326\ The first SAR proceeding proposes changes to the existing 
standards on ATC to, among other things, further establish 
consistency in the calculation of ATC and to increase the clarity of 
each transmission provider's ATC calculation methodology. The second 
SAR proceeding proposes certain changes to NERC's existing CBM and 
TRM standards and calls for greater regional consistency and 
transparency in how CBM and TRM are treated in transmission 
providers' ATC calculations.
    \327\ Technical Conference regarding Preventing Undue 
Discrimination and Preference in Transmission Service under RM05-25 
et al. (October 12, 2006).
    \328\ That posting preceded by one day the issuance of Order No. 
890. Therefore, the posted draft Standard MOD-001-1 does not reflect 
the requirements of Order No. 890, but rather is guided by the NOPR 
issued in the OATT Reform and Reliability Standards proceedings.
---------------------------------------------------------------------------

(a) Comments
    1018. EPSA commends the Commission for recognizing the direct 
connection between the MOD group of Reliability Standards and the 
initiative to reform Order No. 888 to address existing opportunities to 
discriminate against competitive power suppliers in access to the 
transmission system. TAPS and EPSA note that in both the OATT Reform 
NOPR and the Reliability Standards NOPR, the Commission has articulated 
serious concerns about the lack of clarity, transparency and uniformity 
in the critical calculations pertaining to one of the most fundamental 
aspects of the wholesale bulk power transmission system, and urge the 
Commission to make these calculations transparent, consistent, and 
better yet, regional. TAPS agrees with Staff's concerns raised in the 
NOPR about ATC, TTC, CBM and TRM standards. Constellation particularly 
supports the proposed changes to MOD-001-0, MOD-004-0, MOD-006-0 and 
MOD-007-0 because these Reliability Standards, as modified, will 
provide more information to users regarding ATC, TTC, existing 
transmission commitments (ETC), AFC, CBM and TRM, and that information 
will begin the process of providing consistent standards for their 
calculation.
    1019. Constellation agrees with EPSA and cautions that it will take 
time for NERC to develop, and for the Commission to definitively 
approve, ATC-related standards. Constellation therefore proposes that 
the Commission should, upon issuance of a Final Rule, require 
transmission providers to post the information that the Commission 
directs regarding these values, even if work toward more consistency is 
not yet complete. Constellation believes that this will aid in ensuring 
that users request and receive more reliable transmission service on a 
nondiscriminatory basis.
    1020. Contrary to the majority of commenters that support 
Commission action regarding ATC issues, MISO states that a Reliability 
Standard is not the place to address perceived comparability issues. 
MISO states that NERC is responsible for Reliability Standards, but not 
for tariffs and business practices that deal with market and equity 
issues.
(b) Commission Determination
    1021. We agree with the many commenters that recognize the direct 
connection between the MOD group of Reliability Standards and available 
transfer capability methodologies addressed in Order No. 890, in which 
we developed policies to lessen, if not fully eliminate, opportunities 
to discriminate against competitive power suppliers in access to the 
transmission system.
    1022. We recognize the concerns raised by EPSA and Constellation 
that opportunities for discrimination and related reliability concerns 
may remain during the interim Reliability Standards modification 
process, in part because of the discretion that transmission service 
providers will retain in calculating ATC values. We point out, however, 
that all transmission providers are required to file a modified 
Attachment C to their OATTs detailing their ATC calculation 
methodologies in advance of the development of the new Reliability 
Standards. All transmission providers are required to comply with their 
OATTs, and are subject to the filing of a complaint or Commission-
initiated enforcement action if discrimination occurs. Regarding 
Constellation's recommendation that the Commission act in advance, and 
require transmission service providers to post the information that the 
Commission directs regarding ATC values, even if work toward more 
consistency is not yet complete, we clarify that we will require 
transmission service providers to comply with existing ATC-related 
posting obligations on OASIS as supplemented by Order No. 890. These 
requirements are not subject to standardization by the ERO, and will be 
effective in accordance with the timeline stated in Order No. 890.
    1023. We disagree with MISO's contention that the Reliability 
Standards are an inappropriate venue for addressing ATC comparability 
issues. ATC raises both comparability and reliability issues, and it 
would be irresponsible to take action under FPA section 206 to require 
consistency in ATC calculations without considering the reliability 
impact of those decisions. Therefore, the Commission in Order No. 890 
provided direction to public utilities, working through NERC and NAESB, 
regarding development of the ATC-related Reliability Standards and 
business practices, and we repeat that direction here.
c. Documentation of Total Transfer Capability and Available Transfer 
Capability Calculation Methodologies (MOD-001-0)
    1024. The purpose of MOD-001-0 is to promote the consistent and 
uniform application of transfer capability calculations among 
transmission system users. The Reliability Standard requires each 
regional reliability organization to develop a regional TTC and ATC 
methodology in conjunction with its members and to post the most recent 
version of its TTC and ATC methodologies on a Web site accessible by 
NERC, the regional reliability organization, and transmission users.
    1025. In the NOPR, the Commission identified MOD-001-0 as a fill-
in-the-

[[Page 16516]]

blank standard that requires each regional reliability organization to 
develop its respective methods for determining TTC and ATC and to make 
those methodologies available to others for review. The NOPR stated 
that the Commission would not propose to approve or remand MOD-001-0 
until the ERO submits additional information.
    1026. Although the Commission did not propose any action with 
regard to MOD-001-0, it addressed a number of concerns regarding the 
Reliability Standard, consistent with those proposed in the OATT Reform 
NOPR. The Commission proposed that this standard should: (1) At a 
minimum, provide a framework for ATC, TTC and ETC calculation; (2) 
require disclosure of algorithms and processes used in ATC calculation; 
(3) identify a detailed list of information to be exchanged among 
transmission providers for the purposes of ATC modeling; (4) include 
requirements that the assumptions used in ATC and AFC calculations be 
consistent with those used for planning expansion or operation of the 
Bulk-Power System to the maximum extent practicable; \329\ (5) include 
a requirement that applicable entities make available assumptions and 
contingencies underlying ATC and TTC calculations; (6) address only ATC 
while the TTC should be addressed under FAC-012-1; and (7) identify to 
whom MOD-001-0 standards apply, i.e., users, owners and operators of 
the Bulk-Power System.\330\ We will discuss the comments and Commission 
conclusions for each of these modifications separately below.
---------------------------------------------------------------------------

    \329\ NOPR at P 609.
    \330\ Id. at P 610. We note that our observation regarding 
applicable entities here also applies to MOD-002-0, MOD-003-0, MOD-
004-0, MOD-005-0, MOD-008-0, MOD-009-0, MOD-011-0, MOD-013-0, MOD-
014-0, MOD-015-0, MOD-016-0, MOD-024-0 and MOD-025-0.
---------------------------------------------------------------------------

i. Comments
    1027. APPA agrees with the Commission that MOD-001-0 in its current 
form is a fill-in-the-blank standard, is not sufficient in its current 
form and should not be accepted for approval as a mandatory Reliability 
Standard until the accompanying regional procedures are submitted and 
approved.
ii. Commission Determination
    1028. The Commission adopts the NOPR proposal not to approve or 
remand MOD-001-0 until the ERO submits additional information. 
Consistent with Order No. 890, and comments received in response to the 
NOPR, the Commission directs the ERO to consider modifications of MOD-
001-0 through the Reliability Standards development process as 
discussed below.
iii. Provide a Framework for ATC, TTC and ETC Calculation
(a) Comments
    1029. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to, at a minimum, provide a framework for ATC, TTC and ETC 
calculation.
(b) Commission Determination
    1030. We continue to believe that MOD-001-0 should, at a minimum, 
provide a framework for ATC, TTC and ETC calculations. This framework 
should consider industry-wide consistency of all ATC components and 
certain data inputs and exchange, modeling assumptions, calculation 
frequency, and coordination of data relevant for the calculation of 
ATC. Consistent with Order No. 890, we do not require a single 
computational process for calculating ATC for several reasons. First, 
it is not our intent to require transmission providers to incur the 
expense of developing and adopting a new one-size-fits-all software 
package to calculate ATC without proven benefits. More importantly, we 
find that the potential for discrimination and decline in reliability 
level does not lie primarily in the choice of an ATC calculation 
methodology, but rather in the consistent application of its 
components, and input and exchange data, along with modeling 
assumptions. Consistent and transparent ATC calculation will provide 
equivalent results between regions and will therefore prevent 
transmission service providers from overselling transfer capability 
that can stress conditions on their own and adjacent systems, and 
jeopardize reliability. In addition, we are especially concerned with 
the lack of data exchange between neighboring transmission service 
providers, which is a prerequisite for accurate calculation of ATC.
    1031. The Commission understands that the ERO currently is 
developing three ATC calculation methodologies (contract or rating path 
ATC, network ATC, and network AFC).\331\ If all of the ATC components, 
and certain data inputs and assumptions are consistent, the three ATC 
calculation methodologies will produce predictable and sufficiently 
accurate, consistent, equivalent and replicable results. It is 
therefore not necessary to require a single industry-wide ATC 
calculation methodology.
---------------------------------------------------------------------------

    \331\ October 12, 2006 Technical Conference regarding Preventing 
Undue Discrimination and Preference in Transmission Service under 
RM05-25 et al. These three methodologies are different computational 
processes to determine a transmission system's ATC. The first, 
contract path, examines TTC for every A-to-B path on the system in 
concert with all others, reduces ATC by path for ETC, TRM and CBM, 
as appropriate, and produces ATC for each path. The second method, 
network ATC, uses a simulator to look not at each path, but at each 
transmission element (line, substation, etc.) and run first 
contingency simulations to establish ATC on a network basis, rather 
than a path basis. The third method, network AFC, uses a simulator 
to examine critical flowgates over a wider area, then requires a 
second step to convert AFC values to particular path ATC values.
---------------------------------------------------------------------------

    1032. In addition, consistent with Order No. 890, we note that 
there is neither a definition of AFC/TFC (Total Flowgate Capability) in 
the ERO's glossary nor an existing Reliability Standard that discusses 
AFC. Consistent with our approach to achieving consistency and 
transparency, we direct the ERO to develop AFC/TFC definitions and 
requirements used to identify a particular set of transmission 
facilities as flowgates. We extend the same requirements for industry-
wide consistency of all AFC components and certain data inputs and 
exchange, modeling assumptions, calculation frequency, and coordination 
of data relevant for the calculation of AFC as we stated above for ATC. 
However, we remind transmission providers that our regulations require 
the posting of ATC values associated with a particular path, not AFC 
values associated with a flowgate. Accordingly, transmission providers 
using an AFC methodology must convert flowgate (AFC) values into path 
(ATC) values for OASIS posting. In order to display consistent posting 
of ATC and TTC values on OASIS, we direct the ERO to develop a 
Requirement in the Reliability Standard for conversion of AFC into ATC 
values for use by transmission providers that currently apply flowgate 
methodology.
    1033. We underscore Order No. 890's objective of greater 
consistency in ETC calculations. The Commission directs the ERO to 
develop a consistent approach for determining the amount of transfer 
capability a transmission provider may set aside for its native load 
and other committed uses. We expect that the ERO will address ETC 
through the MOD-001-0 Reliability Standard rather than through a 
separate Reliability Standard. By using MOD-001-0, the ETC calculation 
principles can be adjusted to apply to each of the three ATC 
methodologies being developed by the ERO. In order to provide specific 
direction to public utilities and the ERO, we determine that

[[Page 16517]]

ETC should be defined to include committed uses of the transmission 
system, including: (1) Native load commitments (including network 
service); (2) grandfathered transmission rights; (3) firm and non-firm 
point-to-point reservations; (4) rollover rights associated with long-
term firm service and (5) other uses identified through the ERO 
process. ETC should not be used to set aside transfer capability for 
any type of planning or contingency reserve; these are to be addressed 
through CBM and TRM.\332\ In addition, in the short-term ATC 
calculation, all reserved but unused transfer capability (non-
scheduled) must be released as non-firm ATC.
---------------------------------------------------------------------------

    \332\ TRM also includes such things as loop flow and parallel 
path flow.
---------------------------------------------------------------------------

    1034. We reiterate the finding in Order No. 890 that including all 
requests for transmission service in ETC is likely to overstate usage 
of the system and understate ATC. Accordingly, we find that 
reservations that have the same point of receipt (POR) (generator) but 
different point of delivery (POD) (load), for the same time frame, 
should not be modeled in the ETC calculation simultaneously if their 
combined reserved transmission capacity exceeds the generator's 
nameplate capacity at a POR. This will prevent unrealistic use of 
transmission capacity associated with power output from a generator 
identified as a POR. One approach that could be used is examining 
historical patterns of actual reservation use during a particular 
season, month, or time of day.
    1035. In summary, we direct the ERO to modify MOD-001-0 to provide 
a framework for ATC, TTC and ETC calculation that, consistent with the 
discussion above: (1) Requires industry-wide consistency of all ATC 
components and certain data inputs and exchange, modeling assumptions, 
calculation frequency, and coordination of data relevant for the 
calculation of ATC; (2) provides predictable and sufficiently accurate, 
consistent, equivalent, and replicable ATC calculations regardless of 
the methodology used by the region; (3) provides the definition of AFC 
and method for its conversion to ATC; (4) lays out clear instructions 
on how ETC should be defined and (5) identifies to whom MOD-001-0 
Reliability Standards apply, i.e., users, owners and operators of the 
Bulk-Power System.
iv. Require Disclosure of Algorithms and Processes Used in ATC 
Calculation
(a) Comments
    1036. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to require documentation including mathematical algorithms, 
process flow diagrams, data inputs and identification of flowgates.
(b) Commission Determination
    1037. The Commission adopts the proposal from the NOPR to direct 
the ERO to modify Reliability Standard MOD-001-0 to require disclosure 
of the algorithms and processes used in ATC calculation. In addition, 
consistent with Order No. 890, the Commission believes that further 
clarification is necessary regarding the ATC calculation algorithm for 
firm and non-firm ATC.\333\ Currently, the ERO has no specifications 
for calculating non-firm ATC. We find that the same potential for 
discrimination exists for non-firm transmission service as for firm 
service, and greater uniformity in both firm and non-firm ATC 
calculations will substantially reduce the remaining potential for 
undue discrimination. Therefore, we direct the ERO to modify 
Reliability Standard MOD-001-0 to require disclosure of the algorithms 
and processes used in ATC calculation, and also to implement the 
following principles for firm and non-firm ATC calculations: (1) For 
firm ATC calculations, the transmission provider shall account only for 
firm commitments and (2) for non-firm ATC calculations, the 
transmission provider shall account for both firm and non-firm 
commitments, postbacks of redirected service, unscheduled service and 
counterflows.
---------------------------------------------------------------------------

    \333\ The NERC ATC definition does not differentiate firm and 
non-firm ATC from the following high level generic ATC definition: A 
measure of the transfer capability remaining in the physical 
transmission network for further commercial activity over and above 
already committed uses. It is defined as Total Transfer Capability 
less existing transmission commitments (including retail customer 
service), less a Capacity Benefit Margin, less a Transmission 
Reliability Margin.
---------------------------------------------------------------------------

v. Identify a Detailed List of Information To Be Exchanged Among 
Transmission Providers for the Purposes of ATC Modeling
(a) Comments
    1038. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to require applicable entities to identify a detailed list of 
information to be shared.
(b) Commission Determination
    1039. The Commission adopts the NOPR proposal and reiterates the 
requirement in Order No. 890 that the ERO must revise the MOD 
Reliability Standards to require the exchange of data and coordination 
among transmission providers. We direct the ERO to modify MOD-001-0 to 
ensure that the following data, at a minimum, be exchanged among 
transmission providers for the purposes of ATC modeling: (1) Load 
levels; (2) transmission planned and contingency outages; (3) 
generation planned and contingency outages; (4) base generation 
dispatch; (5) existing transmission reservations, including 
counterflows; (6) ATC recalculation frequency and times and (7) source/
sink modeling identification.\334\ The Commission concludes that the 
exchange of such data is necessary to support the reforms requiring 
consistency in the determination of ATC adopted in this Final Rule. As 
explained above, transmission providers are required to coordinate the 
calculation of TTC/TFC and ATC/AFC with others, and this requires a 
standard means of exchanging data.
---------------------------------------------------------------------------

    \334\ NOPR at P 169.
---------------------------------------------------------------------------

vi. Include Requirements That the Assumptions Used in ATC and AFC 
Calculations Should Be Consistent, to the Maximum Extent Practicable, 
With Those Used for Planning the Expansion or Operation of the Bulk-
Power System
(a) Commission Determination
    1040. The Commission adopts the NOPR's proposal to require 
transmission providers to use data and modeling assumptions for short- 
and long-term ATC calculations that are consistent with those used for 
the planning of operations and system expansion, to the maximum extent 
practicable. This includes, for example: (1) Load levels; (2) 
generation dispatch; (3) transmission and generation facilities 
maintenance schedules; (4) contingency outages; (5) topology; (6) 
transmission reservations; (7) assumptions regarding transmission and 
generation facility additions and retirements and (8) counterflows, 
which must be the same in the models used in the transmission 
operational and planning studies performed for the transmission 
providers' native load. We find that requiring consistency in the data 
and modeling assumptions used for ATC calculation will remedy the 
potential for undue discrimination by eliminating discretion and 
ensuring comparability in the manner in which a

[[Page 16518]]

transmission provider operates and plans its system to serve native 
load, and the manner in which it calculates ATC for service to third 
parties.
    1041. We clarify that we require consistent use of assumptions 
underlying operational planning for short-term ATC and expansion 
planning for long-term ATC calculation. We also clarify that there must 
be a consistent basis for or approach to determining load levels in 
each of these sets of calculations. For example, one approach may be 
for transmission providers to calculate load levels using an on- and 
off-peak model for each month when evaluating yearly service requests 
and calculating yearly ATC. The same (peak- and off-peak) or 
alternative approaches may be used for monthly, weekly, daily and 
hourly ATC calculations. Regardless of the ultimate choice, it is 
imperative that all transmission providers use the same approach to 
modeling load levels to eliminate undue discrimination and enable the 
meaningful exchange of data among transmission providers. Accordingly, 
we direct the ERO to develop consistent requirements for modeling load 
levels in MOD-001-0.
    1042. With respect to modeling of generation dispatch, we direct 
the ERO to develop requirements in MOD-001-0 specifying how 
transmission providers should determine which generators should be 
modeled in service, including guidance on how independent generation 
should be considered. Accordingly, we direct the ERO to revise 
Reliability Standard MOD-001-0 by specifying that base generation 
dispatch will model: (1) All designated network resources and other 
resources that are committed to or have the legal obligation to run, as 
they are expected to run and (2) all uncommitted resources that are 
deliverable within the control area, economically dispatched as 
necessary to meet balancing requirements.
    1043. Regarding transmission reservations modeling, we direct the 
ERO to develop requirements in Reliability Standard MOD-001-0 that 
specify: (1) A consistent approach on how to simulate reservations from 
points of receipt to points of delivery when sources and sinks are 
unknown and (2) how to model existing reservations.
    1044. Consistent with Order No. 890, the Commission directs the ERO 
to modify Reliability Standard MOD-001-0 to require ATC to be updated 
by all transmission providers on a consistent time interval and in a 
manner that closely reflects the actual topology of the system, e.g., 
generation and transmission outages, load forecasts, interchange 
schedules, transmission reservations, facility ratings and other 
necessary data. This process must also consider whether ATC should be 
calculated more frequently for constrained facilities.
    1045. In conclusion, we direct the ERO to modify MOD-001-0 to 
require that: (1) Assumptions used for short-term ATC calculations be 
consistent with those used for operation planning to the maximum extent 
practicable; (2) assumptions used for long-term ATC calculations be 
consistent with those used for system planning to the maximum extent 
practicable and (3) ATC be updated by all transmission providers on a 
consistent time interval.
vii. Include a Requirement That Applicable Entities Make Available 
Assumptions and Contingencies Underlying ATC and TTC Calculations
(a) Comments
    1046. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to include a requirement that applicable entities make available 
a comprehensive list of assumptions and contingencies underlying ATC 
and TTC calculations.
(b) Commission Determination
    1047. We adopt the NOPR's proposal that this Reliability Standard 
should include a requirement that applicable entities make available a 
comprehensive list of assumptions and contingencies underlying ATC/AFC 
and TTC/TFC calculations. While we require the submission of 
contingency files under MOD-010-0, here we only direct the ERO to 
consider development of a requirement that the transmission service 
provider declare what type of contingencies it uses for specific 
calculations of ATC/AFC and TTC/TFC, and release the contingency files 
upon request if not submitted with the data filed with the ERO in 
compliance with MOD-010-0.
    1048. In order to increase the transparency of ATC calculations, we 
adopt the NOPR's proposal and direct the ERO to develop in MOD-001-0 a 
requirement that each transmission service provider provide on OASIS 
its OATT Attachment C, in which Order No. 890 requires transmission 
providers to include a detailed description of the specific 
mathematical algorithm the transmission provider uses to calculate both 
firm and non-firm ATC for various time frames such as: (1) The 
scheduling horizon (same day and real-time), (2) operating horizon (day 
ahead and pre-schedule) and (3) planning horizon (beyond the operating 
horizon). In addition, a transmission provider must include a process 
flow diagram that describes the various steps that it takes in 
performing the ATC calculation.
viii. Address Only ATC While TTC Should Be Addressed Under FAC-012-1
(a) Comments
    1049. APPA concurs with the NOPR's proposal that TTC should be 
standardized under FAC-012-1, and that there appears to be little or no 
distinction between the definitions for TTC (MOD-001-0) and TC (FAC-
012-1). APPA anticipates that this distinction will either be clarified 
or eliminated through ongoing Reliability Standards development 
activity.
    1050. Conversely, MidAmerican notes that the transfer capability 
covered by FAC-012-1 may not relate to the TTC that is the subject of 
the MOD-001-0 standard. MidAmerican opines that the purpose of the FAC-
012-1 standard is to ensure that each reliability coordinator and 
planning authority documents the methodology used to develop inter- and 
intra-regional transfer capabilities used in the reliable planning and 
operation of the Bulk-Electric System. MidAmerican further details that 
transfer capabilities that are covered by FAC-012-1 could be used by a 
reliability coordinator to operate the system in a temporary situation 
or by the planning authority as the basis for a sensitivity case. It 
adds that in neither of these cases would these transfer capabilities 
necessarily be included in calculations for ATC that would be used for 
offering transmission capacity for sale.
(b) Commission Determination
    1051. We adopt the NOPR proposal and require that TTC be addressed 
under the Reliability Standard that deals with transfer capability such 
as FAC-012-1, rather than MOD-001-0. The FAC series of standards 
contain the Reliability Standards that form the technical and 
procedural basis for calculating transfer capabilities. FAC-008-1 
provides the basis for determining the thermal ratings of facilities 
while FAC-009-1 provides the basis for communicating those ratings. 
FAC-010-1 and FAC-011-1 provide the system operating limits 
methodologies for the planning and operational horizon respectively and 
FAC-014 provides for the communication of those ratings.\335\
---------------------------------------------------------------------------

    \335\ FAC-010, FAC-011, and FAC-014 are addressed in Docket No. 
RM07-03 because they were submitted later than the original 107 
Reliability Standards and we did not have sufficient time to allow 
appropriate review and comment.

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

[[Page 16519]]

    1052. The Commission directs the ERO, through the Reliability 
Standards development process, to modify FAC-012-1 and any other 
appropriate Reliability Standards to assure consistency in the 
determination of TTC/TFC for services provided under the pro forma 
OATT, and requires that those processes be the same as those used in 
operation and planning for native load and reliability assessment 
studies. Changes to the process of calculating TTC are appropriate if 
implementation is coordinated with revisions to the other applicable 
operating or planning standards. We acknowledge that reliability 
regions have historically calculated transfer capability using 
different approaches, and we agree that regional differences should be 
respected.\336\ However, as already discussed above regarding ATC, TTC 
requirements will be determined in the ERO Reliability Standards 
development process, and any request for a regional difference from the 
Reliability Standards must take place through the ERO process.
---------------------------------------------------------------------------

    \336\ For example, WECC has a documented open process for 
establishing TTC for the Western Interconnection.
---------------------------------------------------------------------------

    1053. We disagree with MidAmerican's opinion that transfer 
capabilities that are addressed by FAC-012-1 are necessarily different 
from TTC used for ATC calculation. The NERC glossary defines transfer 
capability (TC) \337\ as essentially identical to TTC.\338\ We believe 
that modeling principles for simulating power transfers and 
determination of transfer capabilities should be the subject of a 
single standard. Those principles should be the same regardless of 
whether transfer capability is used for the purpose of operations, 
planning or offering for sale. By modeling principles we refer to the 
way transfers are simulated and the type of analysis that should be 
performed, such as steady-state, dynamic stability or voltage 
stability. We are certain that consistent calculation of transfer 
capabilities will prevent over- and under-estimation of the total 
transfer capability available for sale. We agree with APPA that this 
distinction should either be clarified or eliminated through the 
ongoing Reliability Standards development process, and therefore direct 
the ERO to modify MOD-001-0 to address TTC under transfer capability-
related standards such as the FAC group of Reliability Standards.
---------------------------------------------------------------------------

    \337\ Transfer Capability is defined in the NERC glossary as 
``[t]he measure of the ability of interconnected electric systems to 
move or transfer power in a reliable manner from one area to another 
over all transmission lines (or paths) between those areas under 
specified system conditions. The units of transfer capability are in 
terms of electric power, generally expressed in megawatts (MW). The 
transfer capability from `Area A' to `Area B' is not generally equal 
to the transfer capability from `Area B' to `Area A.' '' NERC 
Glossary at 18.
    \338\ Total Transfer Capability is defined in the NERC glossary 
as ``[t]he amount of electric power that can be moved or transferred 
reliably from one area to another area of the interconnected 
transmission systems by way of all transmission lines (or paths) 
between those areas under specified system conditions.'' Id.
---------------------------------------------------------------------------

ix. Identify the Entities To Whom the MOD Standards Apply
(a) Comments
    1054. APPA agrees in part with the Commission's conclusion that 
``NERC should identify the applicable entities in terms of users, 
owners and operators of the Bulk-Power Systems.'' \339\ APPA, however, 
is concerned that this approach may confuse rather than clarify 
compliance responsibilities. According to APPA, a regional organization 
in conjunction with entities that plan, own, operate (and use) 
transmission facilities within each region must be involved in the 
development of any regional TTC and ATC methodology. In this context, 
APPA views the ``regional reliability organization'' as the technical 
arm of the reliability region, made up of the various committees whose 
members are users, owners and operators of the Bulk-Power System, along 
with support from the regional reliability organization staff. Further, 
APPA notes that ultimately, it is these core users, owners and 
operators of the Bulk-Power System that are responsible for the 
development of and adherence to the ATC methodology, and that the 
regional reliability organization, as an organization, is responsible 
for ensuring that the methodology is developed (under R1) and publicly 
posted (under R2).
---------------------------------------------------------------------------

    \339\ NOPR at P 610.
---------------------------------------------------------------------------

    1055. In addition, APPA states that under the statutory framework 
established in FPA section 215, as interpreted by the Commission in 
Order No. 672, it is clear that the compliance monitor within each 
region is the Regional Entity, and the Regional Entity is not a user, 
owner or operator of the Bulk-Power System. APPA notes that while 
regional delegation agreements may be used to impose certain 
reliability compliance functions upon Regional Entities and their 
affiliates, no Regional Entity should be charged with enforcing 
compliance against itself. Ultimately, APPA is concerned that the 
quality of regional modeling and technical assessments will be 
diminished if the collaborative efforts used for the past 50 years of 
interconnected operations are displaced due to pressures to identify a 
single entity or class of entities with direct compliance 
responsibilities for regional modeling standards. APPA states that 
identifying all users, owners and operators as responsible entities 
does not answer the question either. APPA expresses its intention that 
it will work with NERC and with other stakeholders to ensure that this 
industry-based expertise is maintained and enhanced, while ensuring 
that responsible entities are identified in this and other NERC 
standards.
(b) Commission Determination
    1056. APPA is suggesting that respective regional organizations, 
their technical staff, and committees of users, owners and operators of 
the Bulk-Power System be charged with developing the methodologies. We 
disagree. These Reliability Standards should be developed through the 
Commission-approved Reliability Standards development process which 
will identify the entities that should implement the Reliability 
Standards, the Requirements necessary to achieve the goals identified 
in Order No. 890, and the Measures necessary to monitor compliance.
    1057. The Commission agrees with APPA that the collaborative 
efforts and knowledge developed over decades of interconnected 
operation should not be wasted. We do not believe that will happen 
through the Reliability Standards development process and that all of 
the applicable entities will have significant roles to play in 
achieving the goal the Commission has set out in Order No. 890. 
Therefore, we adopt the proposal in the NOPR and direct the ERO to 
modify MOD-001-0 to reflect the users, owners and operators to which 
the Reliability Standard will apply.
x. Summary of Commission Determination
    1058. Accordingly, the Commission neither accepts nor remands MOD-
001-0 until the ERO submits additional information. Although the 
Commission does not propose any action with regard to MOD-001-0, we 
address above a number of concerns regarding the Reliability Standard, 
consistent with those set forth in Order No. 890. We direct the ERO to 
develop modifications to the Reliability Standard through the 
Reliability Standards development process that: (1) Provide a framework 
for ATC, TTC and ETC calculation,

[[Page 16520]]

developing industry-wide consistency of all ATC components; (2) require 
disclosure of algorithms, for both firm and non-firm ATC and processes 
used in the ATC calculation; (3) identify a detailed list of 
information to be exchanged among transmission providers for the 
purposes of ATC modeling; (4) include a requirement that the 
assumptions used in ATC and AFC calculations should be consistent with 
those used for planning the expansion or operation of the Bulk-Power 
System to the maximum extent practicable; (5) include a requirement 
that ATC be updated by all transmission providers on a consistent time 
interval; (6) include a requirement that applicable entities make 
available assumptions and contingencies underlying ATC and TTC 
calculations; (7) address only ATC/AFC while TTC/TFC should be 
addressed under transfer capability standards such as FAC-012-1 and (8) 
identify the applicable entities in terms of users, owners and 
operators of the Bulk-Power System.
d. Review of Transmission Service Provider Total Transfer Capability 
and Available Transfer Capability Calculations and Results (MOD-002-0)
    1059. MOD-002-0 concerns the review of transmission service 
providers' compliance with the regional methodologies for calculating 
TTC and ATC. It requires that the regional reliability organization: 
(1) Develop and implement a procedure to periodically review and ensure 
that the TTC and ATC calculations and resulting values developed by 
transmission service providers comply with the regional TTC and ATC 
methodology and applicable regional criteria; (2) document the results 
of its periodic review and (3) provide the results of its most current 
reviews to NERC upon request.
    1060. In the NOPR, the Commission identified MOD-002-0 as a fill-
in-the-blank standard that requires each regional reliability 
organization to develop and implement a procedure to periodically 
review and ensure that a transmission service provider's TTC and ATC 
calculations comply with regional TTC and ATC methodologies and 
criteria. The NOPR stated that the Commission would not propose to 
approve or remand MOD-002-0 until the ERO submits additional 
information.
i. Comments
    1061. APPA agrees that MOD-002-0 is a fill-in-the-blank standard. 
It is not sufficient in its current form and should not be approved as 
a mandatory Reliability Standard until the accompanying regional 
procedures are submitted and approved.
ii. Commission Determination
    1062. The Commission adopts the NOPR proposal not to approve or 
remand MOD-002-0 until the ERO submits additional information. Because 
the regional procedures have not been submitted to the Commission, it 
is not possible to determine at this time whether MOD-002-0 satisfies 
the statutory requirement that a proposed Reliability Standard be 
``just, reasonable, not unduly discriminatory or preferential, and in 
the public interest.'' Accordingly, the Commission neither approves nor 
remands this Reliability Standard until the regional procedures are 
submitted. In the interim, compliance with MOD-002-0 should continue on 
a voluntary basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice.
e. Regional Procedure for Input on Total Transfer Capability and 
Available Transfer Capability Methodologies and Values (MOD-003-0)
    1063. MOD-003-0 requires each regional reliability organization to: 
(1) Develop and document a procedure on how a transmission user can 
present its concerns or questions regarding TTC and ATC calculations 
including the TTC and ATC values, and how these concerns will be 
addressed and (2) make its procedure for receiving and addressing these 
concerns available to other regional reliability organizations, NERC 
and transmission users on its Web site.
    1064. In the NOPR, the Commission identified MOD-003-0 as a fill-
in-the-blank standard that requires each regional reliability 
organization to develop and document a procedure on how a transmission 
user can present its concerns regarding the TTC and ATC methodologies 
of a transmission service provider. The NOPR stated that the Commission 
would not propose to approve or remand MOD-003-0 until the ERO submits 
additional information.
i. Comments
    1065. APPA agrees that MOD-003-0 is a fill-in-the-blank standard. 
It notes that it is not sufficient in its current form and should not 
be approved as a mandatory Reliability Standard until the accompanying 
regional procedures are submitted and approved. In addition, APPA hopes 
that if NERC develops the MOD-001-0 Reliability Standard properly, it 
will include a reporting procedure for addressing shortcomings in 
information for all transmission customers (LSE, generator owner and 
purchasing-selling entity) in the MOD-001-0 Standard. APPA argues that, 
as a result, MOD-003-0 may be redundant and should be eliminated.
ii. Commission Determination
    1066. The Commission adopts the NOPR proposal not to approve or 
remand MOD-003-0 until the ERO submits additional information. Because 
the regional procedures have not been submitted to the Commission, it 
is not possible to determine at this time whether MOD-003-0 satisfies 
the statutory requirement that a proposed Reliability Standard be 
``just, reasonable, not unduly discriminatory or preferential, and in 
the public interest.'' Accordingly, the Commission neither accepts nor 
remands this Reliability Standard until the regional procedures are 
submitted. In the interim, compliance with MOD-003-0 should continue on 
a voluntary basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice.
    1067. We direct the ERO to consider APPA's suggestion that MOD-003-
0 may be redundant and should be eliminated if the ERO develops a 
modification to the MOD-001-0 Reliability Standard through the 
Reliability Standards development process that includes reporting 
requirements.
f. Documentation of Regional Reliability Organization Capacity Benefit 
Margin Methodologies (MOD-004-0)
    1068. MOD-004-0 requires each regional reliability organization to: 
(1) Develop and document a regional CBM \340\ methodology in 
conjunction with its members and (2) post the most recent version of 
its CBM methodology on a Web site accessible by NERC, regional 
reliability organizations and transmission users.
---------------------------------------------------------------------------

    \340\ The NERC glossary defines ``capacity benefit margin'' or 
``CBM'' as the amount of firm transmission transfer capability 
preserved by a transmission provider for load serving entities whose 
loads are located on the transmission service provider's system, to 
enable access by the load serving entity to generation from 
interconnected systems to meet generation reliability requirements. 
NERC Glossary at 2.
---------------------------------------------------------------------------

    1069. In the NOPR, the Commission identified MOD-004-0 as a fill-
in-the-blank standard that requires each regional reliability 
organization to develop and document a regional CBM methodology. The 
NOPR stated that because the regional CBM methodologies had not been 
submitted, the Commission would not propose to

[[Page 16521]]

approve or remand MOD-004-0 until the ERO submits the additional 
information.
    1070. Although not proposing any action, the Commission nonetheless 
indicated that MOD-004-0 could be improved by: (1) Providing more 
specific requirements on how CBM should be determined and allocated to 
interfaces and (2) including a provision ensuring that CBM, TRM and ETC 
cannot be used for the same purpose, such as the loss of an identical 
generation unit. Further, the Commission expressed concern that the 
Reliability Standard may unduly impact competition because of the lack 
of consistent criteria and clarity with regard to the entity on whose 
behalf CBM has been set aside. This lack of consistent criteria has the 
potential to result in the transmission provider's setting aside 
capacity that it might not otherwise need to set aside, thus increasing 
costs for native load customers and blocking third party uses of the 
transmission system.
i. Comments
    1071. APPA agrees with the Commission that MOD-004-0 should not be 
approved as a mandatory Reliability Standard until the relevant 
regional procedures are submitted and approved.\341\
---------------------------------------------------------------------------

    \341\ APPA notes that it has expressed its own concerns with CBM 
calculations and set-asides in its August 7, 2006 Initial Comments 
filed in Docket No. RM05-25-000, at 31-55. APPA is hopeful these 
concerns can be addressed through NERC's Reliability Standards 
development process.
---------------------------------------------------------------------------

    1072. FirstEnergy states that transmission capacity margins such as 
CBM and TRM are vitally important to the reliability of the system, and 
any methodology that would unduly limit these margins could create a 
danger of limiting transmission capacity over interconnected facilities 
that would limit the ability of balancing authorities and others to 
obtain generation reserves needed from the grid during contingency 
events. In contrast, TAPS questions how TRM or, especially, CBM, can be 
viewed as Reliability Standards if they are optional for the 
transmission provider.
    1073. MidAmerican supports greater uniformity of CBM definitions 
and calculations and states that the revised standard and/or new 
standards should support transparency and uniformity by encouraging 
increased availability of information and consistent data input and 
modeling assumptions. EEI emphasizes that additional data and 
information-sharing requirements would improve the transparency of 
various calculations and assumptions related to CBM, including this 
standard and the other CBM-related standards. EEI believes that, 
similar to the peer review processes of the planning studies carried 
out under the TPL standards, industry participants are best suited to 
developing the totality of assumptions, system conditions and other 
input variables that support the calculations.
    1074. EEI notes that, with respect to the Commission's particular 
concern about criteria in determining resources and loads used in the 
CBM methodology, NERC's ``ATC Definitions and Determination'' \342\ 
document clearly delineates the purpose and intent of the calculation 
of CBM and TRM. EEI states that CBM is intended to provide generation 
reliability, and TRM is intended to provide transmission reliability. 
EEI believes that, to the extent capacity capable of supplying CBM is 
located in the vicinity of the designated facility experiencing an 
outage, transmission may or may not be available under the native load 
reservation normally used for the facility. Therefore, EEI argues, CBM 
may be needed on an interface where capacity is available for use as 
CBM, and not allowing all generation to be considered in this manner 
may unduly increase the generation reserve requirement within the 
transmission provider's system.
---------------------------------------------------------------------------

    \342\ NERC, Available Transfer Capability Definitions and 
Determination--A Framework for Determining Available Transfer 
Capabilities of the Interconnected Transmission Networks for a 
Commercially Viable Electricity Market (June 1996).
---------------------------------------------------------------------------

    1075. EEI agrees with the Commission's concern about double-
counting TRM for those transmission providers who do not opt to use 
CBM. However, EEI argues that for transmission providers who do opt to 
use CBM, it may be appropriate in some circumstances to use the same 
generation unit outage to determine the impact on both generation and 
transmission reliability because the impacts are different. EEI 
cautions that artificially restricting such use is not appropriate, 
especially before NERC's development of TRM and CBM standards and their 
presentation to FERC through the Reliability Standards development 
process. EEI recommends that the Commission encourage transmission 
providers to make CBM and TRM capacity available to wholesale markets 
for purchase on a non-firm basis, because doing so would ensure that 
both CBM and TRM capacity are available to the transmission provider 
during system emergencies, as intended. EEI notes that at other times 
the transfer capability associated with TRM and CBM would be available 
to the market, alleviating the concern of possible double-counting. 
MidAmerican also supports the Commission's conclusion that double-
counting would be inappropriate, although MidAmerican states that it is 
not aware of any cases of double-counting of margins.
    1076. TAPS notes the significant potential for abuse \343\ that 
could result from the current flexibility afforded transmission 
providers in the calculation of CBM and TRM, and proposes innovative 
approaches \344\ to take CBM and (to the extent it is intended to cover 
transmission required for reserve sharing) TRM out of the hands of 
individual transmission providers, and to therefore reduce the 
opportunity for abuse.
---------------------------------------------------------------------------

    \343\ Documented by NERC's April 14, 2005 Long-Term AFC/ATC Task 
Force Final Report.
    \344\ TAPS refers the Commission to its August 7, 2006 comments 
in Docket No. RM05-25-000 at 21-24.
---------------------------------------------------------------------------

ii. Commission Determination
    1077. The Commission adopts the NOPR proposal not to approve or 
remand MOD-004-0 until the ERO submits additional information. Because 
the regional procedures have not been submitted to the Commission, it 
is not possible to determine at this time whether MOD-004-0 satisfies 
the statutory requirement that a proposed Reliability Standard be 
``just, reasonable, not unduly discriminatory or preferential, and in 
the public interest.'' Accordingly, the Commission neither accepts nor 
remands this Reliability Standard until the regional procedures are 
submitted. In the interim, compliance with MOD-004-0 should continue on 
a voluntary basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice. 
Consistent with Order No. 890 and comments received in response to the 
NOPR, the Commission directs the ERO, through the Reliability Standards 
development process, to modify MOD-004-0 as discussed below.
    1078. We agree with FirstEnergy that CBM is important for system 
reliability by allowing the LSEs to meet their historical, state, RTO 
or regional generation reliability criteria requirement such as reserve 
margin, loss of load probability, loss of largest units, etc. We agree 
with EEI and MidAmerican that transparency of the studies supporting 
CBM determination will reduce the opportunity for transmission service 
providers to overestimate the amount of CBM and misuse transfer 
capability. We therefore direct the ERO to develop Requirements

[[Page 16522]]

regarding transparency of the generation planning studies used to 
determine CBM values. We also clarify that CBM should only be set aside 
upon request of any LSE within a balancing area to meet its verifiable 
historical, state, RTO or regional generation reliability criteria 
requirement such as reserve margin, loss of load probability, loss of 
largest units, etc. We expect verification of the CBM values to be part 
of the Requirements with appropriate Measures and Levels of Non-
Compliance.
    1079. We continue to believe this Reliability Standard should be 
modified to include a provision ensuring that CBM, TRM and ETC cannot 
be used for the same purpose, such as loss of the identical generating 
unit. In order to limit misuse of transfer capability set aside as CBM, 
we direct the ERO to provide more specific requirements for how CBM 
should be determined and allocated across transmission paths or 
flowgates. As we stated in Order No. 890, we do not mandate a 
particular methodology for allocating CBM to paths or flowgates. For 
example, one approach could be based on the location of the outside 
resources or spot market hubs that a LSE has historically relied on 
during emergencies resulting from an energy deficiency, but we agree 
with EEI that flexible rules should be allowed to prevent unnecessary 
increase of the generation reserve requirement within the transmission 
provider's system. Therefore, we support flexibility, but expect that 
the ERO, using its Reliability Standards development process, will 
adequately approach these complex technical issues and propose a new 
version of MOD-004-0 that addresses the methods for CBM determination 
and allocation on paths that will reduce reliability and discrimination 
concerns.
    1080. In response to TAPS's question asking how CBM can be viewed 
as a Reliability Standard if it is optional to the transmission 
provider, our understanding is that transmission providers that have 
opted not to use CBM have instead set aside transmission margin (needed 
to bring in outside power to meet generation reliability criteria) 
either through ETC or TRM. CBM is not the only way to reserve 
transmission capacity for a margin. However, if the Reliability 
Standard is not clear regarding the method of calculating transmission 
margins, it may cause double-counting of transmission margins and 
reduction of ATC. As we stated in Order No. 890, we find that clear 
specification of the permitted purposes for which entities may reserve 
CBM and TRM will virtually eliminate double-counting of TRM and CBM. 
Therefore, we direct the ERO to modify its standard in order to prevent 
setting aside transfer capability for the same purposes.
    1081. We share TAPS's concern that there is a significant potential 
for abuse as a result of the current flexibility afforded to 
transmission providers in the calculation of both CBM and TRM. In 
response to TAPS's concern, we clarify that in accordance with the OATT 
Reform Final Rule and the ERO CBM definition, each LSE has the right to 
request CBM be set aside and use it to meet its verifiable historical, 
state, RTO or regional generation reliability criteria requirement such 
as reserve margin, loss of load probability, loss of largest units, 
etc. As such, the LSEs that request CBM be set aside must be identified 
as applicable entities with identified Requirements, including 
Requirements on generation studies to verify the set aside, Measures 
and Levels of Non-Compliance. We direct the ERO to modify the 
Reliability Standard accordingly.
    1082. We agree with TAPS that there is a need for clearer 
requirements in the standard regarding to whom and how to submit a 
request for CBM set-aside, and what the transmission service provider 
should do if the sum of all CBM requirements exceeds the amount of 
available transfer capability. We direct the ERO to address the 
reliability aspects in the Reliability Standards development process 
and explore with NAESB whether business practices would be required.
    1083. Accordingly, the Commission neither accepts nor remands MOD-
004-0 until the ERO submits additional information. In the interim, 
compliance with MOD-004-0 should continue on a voluntary basis, and the 
Commission considers compliance with the Reliability Standard to be a 
matter of good utility practice. Although the Commission did not 
propose any action with regard to MOD-004-0, it addressed above a 
number of concerns regarding the Reliability Standard, consistent with 
those set forth in Order No. 890. Therefore, we direct the ERO to 
develop modifications to the Reliability Standard through the 
Reliability Standards development process to: (1) Clarify that CBM 
shall be set aside upon request of any LSE within a balancing area to 
meet its verifiable historical, state, RTO or regional generation 
reliability criteria; (2) develop requirements regarding transparency 
of the generation planning studies used to determine CBM value; (3) 
modify the current Requirements to make clear the process for how CBM 
is allocated across transmission paths or flowgates; (3) modify its 
standard in order to prevent setting aside CBM and TRM for the same 
purposes; (4) modify the standard by adding LSE as an applicable entity 
and (5) coordinate with NAESB business practice standards.
    1084. We direct the ERO to consider APPA's suggestion that MOD-004-
0 may be redundant and should be eliminated if the ERO develops a 
modification to the MOD-002-0 Reliability Standard that includes 
reporting requirements
g. Procedure for Verifying Capacity Benefit Margin Values (MOD-005-1)
    1085. MOD-005-1 specifies the requirements regarding the periodic 
review of a transmission service provider's adherence to the regional 
reliability organization's CBM methodology. It requires each regional 
reliability organization to: (1) Develop and implement a procedure to 
review at least annually the CBM calculations and the resulting values 
determined by member transmission service providers; (2) document its 
CBM review procedure and (3) make the results of the most current CBM 
review available to NERC upon request.
    1086. In the NOPR, the Commission identified MOD-005-0 as a fill-
in-the-blank standard that requires each regional reliability 
organization to develop and implement a procedure to review CBM 
calculations and the resulting values and to make the documentation of 
the results of the CBM review available to NERC and others. The NOPR 
stated that because the regional procedures had not been submitted, the 
Commission would not propose to approve or remand MOD-005-0 until the 
ERO submits the additional information.
i. Comments
    1087. APPA agrees that MOD-005-0 is a fill-in-the blank standard, 
and that in its current form, it is not sufficient and should not be 
accepted for approval as a mandatory Reliability Standard until the 
necessary regional procedures have been submitted and approved. APPA 
suggests that NERC modify MOD-006-0, so that MOD-004-0 and MOD-005-0 
could be eliminated.
ii. Commission Determination
    1088. The Commission adopts the NOPR proposal not to approve or 
remand MOD-005-0 until the ERO submits additional information. Because 
the regional procedures have not been submitted to the Commission, it 
is not possible to determine at this time whether MOD-005-0 satisfies 
the statutory requirement that a proposed Reliability Standard be 
``just,

[[Page 16523]]

reasonable, not unduly discriminatory or preferential, and in the 
public interest.'' Accordingly, the Commission neither accepts nor 
remands this Reliability Standard until the regional procedures are 
submitted. In the interim, compliance with MOD-005-0 should continue on 
a voluntary basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice.
    1089. As to APPA's comment on incorporating MOD-004 and MOD-005 
into MOD-006, we direct the ERO to consider those comments through the 
Reliability Standards development process.
h. Procedure for Use of Capacity Benefit Margin Values (MOD-006-0)
    1090. The purpose of MOD-006-0 is to promote the consistent and 
uniform use of transmission CBM calculations among transmission system 
users. MOD-006-0 requires that each transmission service provider 
document its procedure for the scheduling of energy against a CBM 
reservation and make the procedure available on a Web site accessible 
by the regional reliability organization, NERC and transmission users.
    1091. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-006-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-006-
0 that: (1) Includes a provision that will ensure that CBM and TRM are 
not used for the same purpose; (2) modifies Requirement R1.2 so that 
concurrent occurrence of generation deficiency and transmission 
constraints is not a required condition for CBM usage; (3) modifies 
Requirement R1.2 to define ``generation deficiency'' based on a 
specific energy emergency alert level and (4) expands the applicability 
section to include the entities that actually use CBM, such as LSEs.
    1092. In addition, the Commission proposed that NERC should clarify 
the requirements to address when and how CBM can be used to reduce 
transmission provider discretion with regard to CBM usage. The 
Commission provided guidance expressing its belief that CBM should be 
used only when the LSE's local generation capacity is insufficient to 
meet balancing Reliability Standards, and that CBM should have a zero 
value in the calculation of non-firm ATC.
i. Comments
    1093. APPA supports the Commission's proposal to approve MOD-006-0. 
Moreover, APPA agrees with the Commission's proposed directives \345\ 
that the standard should address the use of CBM and TRM for the same 
purpose. However, APPA believes that the specificity of the 
Commission's proposed directives to NERC, if implemented, would 
undermine NERC's role as the approved ERO with the technical expertise 
to develop and revise standards for the Commission's subsequent review. 
APPA therefore suggests that the Commission in its Final Rule make 
clear to NERC its concerns about MOD-006-0, but then let NERC address 
those concerns through its Reliability Standard development process.
---------------------------------------------------------------------------

    \345\ NOPR at P 642.
---------------------------------------------------------------------------

    1094. Regarding the Commission's proposal that MOD-006-0 R1.2 be 
modified ``so that concurrent occurrence of transmission constraints 
and a generation deficiency is not a requirement for CBM usage,'' WEPCO 
asserts that the Commission is misinterpreting CBM. WEPCO states that 
if there is no transmission constraint then there is no need to use 
CBM. In that case, transmission capacity exists for a LSE to import 
energy. If there is a transmission constraint, CBM reserves 
transmission capacity that the LSE can use to import energy for 
reliability needs.
    1095. EEI points out that the explicit intention for CBM is that it 
be used only during conditions where there are emergency generation 
deficiencies. However, EEI emphasizes that the Commission's 
recommendation does not consider that the LSE's supply and demand 
balance varies season to season, over time, and with supply and demand 
uncertainties. EEI says that the development of CBM quantities must be 
carried out in a manner that sets aside transmission capability for 
forecasted conditions and uncertainties much like the native load 
reservations necessary for serving reasonably-forecasted native load. 
An argument may be made that during a period of time when a LSE's 
expected reserves are substantially greater than its targeted reserves, 
the need for CBM set-aside decreases. However, should the LSE foresee 
that this ``excess'' would occur substantially in the future, a 
reduction in CBM would not be warranted since substantial uncertainties 
still exist.
    1096. Additionally, regarding the Commission's proposal that a LSE 
that ``has sufficient generation resources within its balancing 
authority to meet the balancing Reliability Standards, should not need 
to preserve capacity for CBM at all,'' WEPCO argues that just because 
the balancing authority has sufficient generation does not mean that 
there is sufficient transmission capacity to deliver the energy to the 
LSE. WEPCO states that the LSE may be remote from the bulk of the 
balancing authority, so there may be occasions when a LSE that has 
sufficient generation resources within its balancing authority to meet 
the balancing Reliability Standards may still need to reserve capacity 
for CBM. In addition, EEI argues that the Commission's viewpoint does 
not take into account the availability of these resources unless they 
are under contract with the LSE to provide this service. EEI contends 
that the implication of this suggestion is to unduly restrict the 
sources of generation capacity available for CBM during times of 
generation shortage, which results in the LSE's being captive to local 
generation that is available and does not allow access to the market 
outside of the LSE's balancing authority. Additionally, EEI cautions 
that this action may require the LSE to develop contractual agreements 
with local generation and thus increase costs to the LSE's rate payers.
    1097. Given the strong direction on CBM issues in the OATT Reform 
NOPR, TAPS assumes that the Commission would not be approving the 
Version 0 standards on these competitively crucial issues, but would 
continue to address them forcefully in the OATT Reform proceeding. TAPS 
notes that, although that is the course largely adopted by the NOPR in 
this proceeding, the NOPR \346\ proposes to approve MOD-006-0 and MOD-
007-0, with directions to improve these standards. TAPS notes that such 
action is inconsistent with the Commission's general approach to ATC/
TTC/TRM/CBM standards in this docket and the OATT Reform NOPR. TAPS 
further states that, given the absence of clear access of non-
transmission owner LSEs to CBM, the proposed expansion of MOD-007-0 to 
include such LSEs in the NOPR \347\ seems bizarre.
---------------------------------------------------------------------------

    \346\ Id. at P 642, 648.
    \347\ Id. at P 647-48.
---------------------------------------------------------------------------

ii. Commission Determination
    1098. The Commission adopts the NOPR proposal to approve MOD-006-0 
as mandatory and enforceable. Consistent with Order No. 890 and 
comments received in response to the NOPR, the Commission directs the 
ERO to modify MOD-006-0 as discussed below.
    1099. Consistent with the views of many commenters, we adopt the 
NOPR proposal that requires a provision that will ensure that CBM and 
TRM are not used for the same purpose. As discussed under MOD-004-0 
concerning the

[[Page 16524]]

reservation of transfer capacity, we believe that if the Reliability 
Standard is not clear regarding the conditions specifying both the 
reservation and the use of CBM, it may cause double-counting. Such 
double-counting will lead to an unnecessary reduction of ATC, and 
create opportunities for discrimination. Therefore, we direct the ERO 
to modify its standard to prevent use of CBM and TRM for the same 
purposes. We agree with APPA that the ERO should use its Reliability 
Standards development process to address the double-counting problem.
    1100. We adopt the NOPR's proposal and direct the ERO to modify 
Requirement R1.2 so that a transmission constraint is not a required 
condition for CBM usage. The glossary definition and the use as defined 
in Order No. 890 is that CBM ``is intended to be used by the LSE only 
in time of emergency generation deficiencies.'' \348\ Therefore we 
direct the ERO to modify the standard in the manner proposed in the 
NOPR.
---------------------------------------------------------------------------

    \348\ See NERC Glossary at 2.
---------------------------------------------------------------------------

    1101. We adopt the NOPR proposal that requires modification of 
Requirement R1.2 to define ``generation deficiency'' based on a 
specific energy emergency alert level. This approach will provide 
clarity as to when the use of CBM may be permitted. We therefore direct 
the ERO to modify the Reliability Standard to include a specific energy 
emergency alert level that will trigger CBM usage.
    1102. We also reiterate the direction in Order No. 890 that CBM 
should have a zero value in the calculation of non-firm ATC because 
non-firm service may be curtailed so that CBM can be used. CBM is 
reserved as part of the firm transfer capability so that it is 
available when needed for energy emergencies. We determine that each 
LSE should be permitted to call for use of CBM, provided all of the 
other Requirements of R1.1 are met. We direct that CBM may be 
implemented up to the reserved value when a LSE is facing firm load 
curtailments.
    1103. We adopt the NOPR proposal that CBM should be used only when 
the LSE's local generation capacity is insufficient to meet balancing 
Reliability Standards, with the clarification that the local generation 
is that generation capacity that is either owned or contracted for by 
the LSE. We disagree with WEPCO that just because the balancing 
authority has sufficient generation does not mean that there is 
transmission capacity to deliver the energy to the LSE. The Commission 
finds that such a scenario would violate existing transmission 
operating and transmission planning Reliability Standards. There is an 
explicit requirement in the transmission operating standards that 
generation reserves must be deliverable to load.\349\ Also, there is an 
explicit requirement in the transmission planning standards that all 
firm load must be supplied under various system conditions with and 
without contingencies.\350\ The Commission is not prescribing how these 
requirements should be met. There are a variety of approaches to do so, 
including adequate transmission capability, local or dynamic generation 
transfers into the area or DSM. To clarify for EEI, our proposal does 
not take into account the availability of these resources unless they 
are under contract with the LSE to provide this service. We developed 
our NOPR proposal on the rationale derived from the CBM concept, and 
believe that if there are enough resources to meet generation 
reliability criteria within the balancing authority, there is no need 
to request CBM.
---------------------------------------------------------------------------

    \349\ TOP-002-2.
    \350\ TPL-002-0.
---------------------------------------------------------------------------

    1104. We also adopt the NOPR proposal to require the applicability 
section to include the entities that actually use CBM, such as LSEs. 
The current CBM definition in the NERC glossary determines that LSEs 
are users of CBM. Load-serving entities determine when to use CBM, 
initiate CBM use and call for its end. Load-serving entities therefore 
have to comply with the standard requirements that specify the 
conditions under which CBM will be used. We direct the ERO to modify 
the standard accordingly.
    1105. With regard to TAPS's comments concerning its assumption that 
the Commission would not be approving the Version 0 standards on these 
issues, but would continue to address them in the OATT Reform 
proceeding, the Commission finds that MOD-006-0 and MOD-007-0 do not 
establish CBM values, but rather address CBM implementation and 
documentation. The implementation of CBM has critical implications for 
the reliable operation of the Bulk-Power System and we find that these 
Reliability Standards should be mandatory and enforceable. The 
competitively significant issue is to assure that there is no double-
counting of CBM and to determine the magnitude of CBM which is 
addressed in other Reliability Standards that the Commission has not 
approved or remanded.
    1106. The Commission approves MOD-006-0 as mandatory and 
enforceable. In addition, the Commission directs the ERO to develop a 
modification to Reliability Standard MOD-006-0 through the Reliability 
Standards development process that: (1) Includes a provision that will 
ensure that CBM and TRM are not used for the same purpose; (2) provides 
that CBM should be used for emergency generation deficiencies; (3) 
modifies Requirement R1.2 to define ``generation deficiency'' based on 
a specific energy emergency alert level; (4) includes a provision that 
CBM should have a zero value in the calculation of non-firm ATC and (5) 
expands the applicability section to include the entities that actually 
use CBM, such as LSEs.
i. Documentation of the Use of Capacity Benefit Margin (MOD-007-0)
    1107. MOD-007-0 requires transmission service providers that use 
CBM to report and post its use.
    1108. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-007-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-007-
0 that expands the applicability section to include the entities that 
actually use CBM, such as LSEs.
i. Comments
    1109. APPA supports the Commission's proposed approval of MOD-007-
0. However, it believes that the issue of whether LSEs should be made 
subject to MOD-007-0 should be left to NERC in the first instance to 
decide. In so doing, NERC should consider expanding MOD-007-0 to cover 
not only LSEs, but also balancing authorities. Under NERC's Functional 
Model, the balancing authority is the entity that would schedule energy 
over transmission capacity reserved as CBM. Moreover, it is the 
balancing authority that would know the information necessary to report 
an incident during which the balancing authority had to import energy 
from outside the balancing authority's own area from a resource 
designated as operating reserves and change the net scheduled 
interchange with the neighboring balancing authorities to allow the 
energy to flow into the balancing authority's area.
ii. Commission Determination
    1110. The Commission approves MOD-007-0 as mandatory and 
enforceable. Consistent with the comments received in response to the 
NOPR, the Commission directs the ERO

[[Page 16525]]

to modify the standard as discussed below.
    1111. We also adopt the NOPR's proposal to require the 
applicability section to include the entities that actually use CBM and 
report on their CBM use, such as LSEs. The current CBM definition in 
the NERC glossary determines when a LSE is a CBM user. The LSE 
determines how much CBM will be set aside, when CBM use will start and 
when it will end. The LSE must therefore comply with the standard 
requirements that require reporting and posting of CBM use. We direct 
the ERO to modify the standard to include the entities that actually 
use CBM, such as LSEs. In addition, we agree with APPA that the 
Reliability Standard should apply to balancing authorities and direct 
the ERO to include balancing authorities within the entities to which 
this standard is applicable.
    1112. Accordingly, the Commission approves MOD-007-0 as mandatory 
and enforceable. In addition, the Commission directs the ERO to develop 
a modification through its Reliability Standards development process 
that expands the applicability of MOD-007-0 to include the entities 
that actually use CBM, such as LSEs and balancing authorities.
j. Documentation and Content of Each Regional Transmission Reliability 
Margin Methodology (MOD-008-0)
    1113. MOD-008-0 requires the development and posting of a regional 
methodology for TRM, which is transmission capacity that is reserved to 
provide reasonable assurance that the interconnected transmission 
network will remain secure under various system conditions. The 
Reliability Standard requires each regional reliability organization 
to: (1) Develop and document a regional TRM methodology in conjunction 
with its members and (2) post on a Web site the most recent version of 
its TRM methodology.
    1114. In the NOPR, the Commission identified MOD-008-0 as a fill-
in-the-blank standard, proposing that because the regional 
methodologies had not been submitted, the Commission would not propose 
to approve or remand MOD-008-0 until the ERO submitted the additional 
information. The Commission expressed concern about the lack of: (1) 
Clear requirements on how TRM should be calculated and allocated across 
paths and (2) consistent criteria and clarity with regard to the entity 
on whose behalf TRM had been set aside.
    1115. The Commission requested comment in the NOPR on how TRM is 
currently calculated and allocated across paths, and what would be a 
recommended approach for the future.
i. Comments
    1116. APPA agrees that MOD-008-0 is a fill-in-the-blank standard, 
is not sufficient as currently drafted, and should not be approved as a 
mandatory Reliability Standard until NERC and the regional reliability 
organizations and regional entities develop the necessary regional 
methodologies and the Commission approves them.
    1117. MISO adds that there should be a consistent framework to be 
followed by entities in determining TRM. It states that relevant MOD 
standards should be revised if such a framework is not clearly 
delineated. However, MISO cautions that a Reliability Standard should 
not be used to address a perceived equity concern. MidAmerican also 
supports greater uniformity of TRM definitions and calculations, and 
proposes that a revised standard and/or new standards should encourage 
transparency with increased availability of information, consistent 
data input and certain modeling assumptions. International Transmission 
agrees and proposes that TRM consistency should be addressed either on 
a regional basis or on an Interconnection-wide basis.
    1118. In response to the Commission's request for comments on the 
current calculation of TRM, and recommended approaches for the future, 
International Transmission provides a description of the MISO approach 
to TRM. International Transmission states that during the operating 
horizon (next 48 hours), TRM is limited to a reserve sharing component 
which only applies to flowgates that are not based on transmission 
outages (unit tripping and transmission outages are considered a double 
contingency). International Transmission states that the logic behind 
this approach is that there are fewer uncertainties in the operating 
horizon because schedules and market flows are known. International 
Transmission explains that during the planning horizon (next 48 hours), 
a two percent TRM component for uncertainty is used on all flowgates, 
including those requiring reserve sharing TRM. In addition, other 
assumptions regarding the sale of transmission service enter into the 
need for TRM to cover ``uncertainties.'' In addition, International 
Transmission cautions that MISO's minimal two percent margin may not be 
sufficient for long-term planning horizon requests (i.e., over 13 
months) if planning ``assumptions'' are not reasonable. International 
Transmission argues that MISO must also employ proper sensitivity 
studies to other system variables for a two percent margin to be 
sufficient. TRMs in the five to ten percent range are not necessarily 
unreasonable if a wide range of potential system operating conditions 
is not studied. Regardless of the ultimate approach adopted in future 
standards, International Transmission proposes that all entities follow 
a consistent framework when calculating TRM.
    1119. MidAmerican responds with a discussion of its current 
approach to TRM calculation, which has been performed in accordance 
with MAPP-approved methodologies. MidAmerican states that these 
methodologies include an amount to allow for both the delivery of 
operating reserves and for uncertainties. Since delivery of operating 
reserves keeps the interconnected network in service, benefiting all 
market participants, MidAmerican contends that it is appropriate for 
TRM to include an amount to allow for the delivery of operating 
reserves. The allowance for uncertainty is calculated as a percentage 
of TTC required to protect reliability. All market participants benefit 
from the provision of an appropriate margin for uncertainty because the 
reliability of the interconnected network is maintained and service 
interruptions are reasonably minimized.
    1120. With respect to applicable entities, APPA proposes the 
addition of two new functional entities. Specifically, APPA believes 
that NERC should expand the applicability section of MOD-008-0 to 
include planning authorities and reliability coordinators. APPA points 
out that these are the only entities that can evaluate the amount of 
error in their transfer capability predictions.
    1121. ERCOT states that the Commission's concerns about TRM do not 
apply to ERCOT, because ERCOT has a balanced grid in which all 
transmission is firm, no transmission is reserved and there are no 
transmission paths.
ii. Commission Determination
    1122. The Commission does not approve or remand MOD-008-0 until the 
ERO submits additional information. Consistent with Order No. 890 and 
comments received in response to the NOPR, the Commission directs the 
ERO to modify MOD-008-0 through the Reliability Standards development 
process, as discussed below.
    1123. Consistent with the NOPR proposal and Order No. 890, the 
Commission directs the ERO to modify standard MOD-008-0 to clarify how 
TRM should be calculated and allocated

[[Page 16526]]

across paths or flowgates. We understand that the standards drafting 
process is underway as a joint project with NAESB. We agree with 
International Transmission, MidAmerican and MISO about the need for 
more uniformity and transparency in TRM calculation methodology and 
use, in order to eliminate potential reliability and discrimination 
concerns. Consistent with Order No. 890, the Commission directs the ERO 
to specify the parameters for entities to use in determining 
uncertainties for which TRM can be set aside and used, such as: (1) 
Load forecast and load distribution error; (2) variations in facility 
loadings; (3) uncertainty in transmission system topology; (4) loop 
flow impact; (5) variations in generation dispatch; (6) automatic 
reserve sharing and (7) other uncertainties as identified through the 
NERC Reliability Standards development process. We find that clear 
specification in this Final Rule of the permitted purposes for which 
entities may reserve CBM and TRM will also virtually eliminate double-
counting of TRM and CBM. Therefore, we direct the ERO to determine 
clear requirements regarding permitted uses for TRM through its 
Reliability Standards development process.
    1124. We agree with the commenters that the percentage reduction of 
line rating can be one way to establish an appropriate maximum TRM if 
thermal considerations are the only limiting factors. While this is a 
relatively simple method, it ignores limitations relative to voltage or 
stability limitations which are the more typical reasons for 
transmission limitations. If adopted as the Reliability Standard 
method, it should not restrict a transmission provider from using a 
more sophisticated method that may allow for greater ATC without 
reducing overall reliability. However, we disagree with the use of an 
arbitrary percentage over a long time frame that is not based on either 
proven historical need or sensitivity studies that support that 
determination. Therefore, consistent with our OATT Reform Final Rule, 
we direct the ERO to develop requirements regarding transparency of the 
documentation that supports TRM determination.
    1125. We agree with APPA that NERC should revise the applicability 
section of this standard to add planning authorities and reliability 
coordinators, and in addition, any other entities that may be 
identified in the Reliability Standards development process.
    1126. Regarding ERCOT's statement that TRM does not apply to ERCOT, 
we reiterate our position that any request for a regional exemption 
from the applicable Reliability Standards must take place in the 
Reliability Standards development process.
    1127. The Commission neither accepts nor remands MOD-008-0 until 
the ERO submits additional information. In the interim, compliance with 
MOD-008-0 should continue on a voluntary basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice. Although the Commission did not propose any 
action with regard to MOD-008-0, it addressed above a number of 
concerns regarding the Reliability Standard, consistent with those 
proposed in Order No. 890. Accordingly, we direct the ERO to develop 
modifications to the Reliability Standard through the Reliability 
Standards development process including: (1) Clear requirements on how 
TRM should be calculated, including a methodology for determining the 
maximum TRM value, and allocated across paths; (2) clear requirements 
for permitted purposes for which TRM can be set aside and used; (3) 
clear requirements for availability of documentation that supports TRM 
determination and (4) expanding the applicability to add planning 
authorities and reliability coordinators and any other appropriate 
entity identified in the Reliability Standards development process.
k. Procedure for Verifying Transmission Reliability Margin Values (MOD-
009-0)
    1128. MOD-009-0 requires each regional reliability organization to 
develop and implement a procedure to review TRM calculations and the 
resulting values determined by member transmission providers to ensure 
compliance with the regional TRM methodology.
    1129. In the NOPR, the Commission identified MOD-009-0 as a fill-
in-the-blank standard that requires each regional reliability 
organization to develop a procedure for review of TRM calculations and 
the resulting values. In the NOPR, the Commission stated that because 
the regional procedures had not been submitted, the Commission would 
not propose to approve or remand MOD-009-0 until the ERO submits the 
additional information.
i. Comments
    1130. APPA agrees that MOD-009-0 is a fill-in-the-blank standard, 
is not sufficient as currently drafted, and should not be approved as a 
mandatory Reliability Standard until NERC and the regional reliability 
organizations and regional entities develop the necessary regional 
methodologies and the Commission approves them.
ii. Commission Determination
    1131. The Commission will not approve or remand MOD-009-0 until the 
ERO submits additional information. Because the regional procedures 
have not been submitted to the Commission, it is not possible to 
determine at this time whether MOD-009-0 satisfies the statutory 
requirement that a proposed Reliability Standard be ``just, reasonable, 
not unduly discriminatory or preferential, and in the public 
interest.'' Accordingly, the Commission neither approves nor remands 
this Reliability Standard until the regional procedures are submitted. 
In the interim, compliance with MOD-009-0 should continue on a 
voluntary basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice.
l. Steady-State Data for Modeling and Simulation of Interconnected 
Transmission System (MOD-010-0)
    1132. The purpose of this Reliability Standard is to establish 
consistent data requirements, reporting procedures and system models 
for use in reliability analysis. MOD-010-0 requires the transmission 
owner, transmission planner, generator owner and resource planner to 
provide steady-state data, such as equipment characteristics, system 
data, and existing and future interchange schedules to the regional 
reliability organization, NERC, and other specified entities.
    1133. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-010-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-010-
0 that: (1) Adds a new requirement for transmission owners to provide 
the list of contingencies they use in performing system operation and 
planning studies and (2) expands the applicability section to include 
the planning authority.
i. Comments
    1134. APPA agrees with the Commission that MOD-010-0 is sufficient 
for approval as a mandatory and enforceable Reliability Standard. APPA 
believes, however, that the Commission's proposed directives to NERC to 
revise this standard are unduly prescriptive, and may not in fact be 
the best way to revise the standard.
    1135. ISO/RTO Council and ISO-NE do not support adoption of this 
standard because its requirements refer several

[[Page 16527]]

times to the data requirements and reporting procedures specified in 
MOD-011-0, which has been identified by the Commission as a fill-in 
the-blank standard. ISO/RTO Council and ISO-NE argue that demonstrating 
compliance with MOD-010-0 is dependent on an unapproved standard, that 
the unapproved standard lacks some required criteria or procedures that 
must be developed by the regional reliability organization, that MOD-
010-0 cannot be effectively implemented, and that responsible entities 
therefore should not be subject to compliance with an incomplete 
standard.
    1136. Constellation strongly supports the Commission's proposals 
with respect to MOD-010-O and MOD-012-0 because these proposals, 
together with other initiatives, such as OATT reform, represent 
additional steps not only to achieving a reliable bulk power system, 
but also to reducing undue discrimination in transmission services. 
Constellation supports the Commission's proposals because they will 
involve generation owners in facility ratings discussions and 
discussions of other limiting components and will provide more clarity 
in the requirements of the Reliability Standard, making enforcement 
more objective and robust.
    1137. Many commenters submitted comments both supporting and 
opposing the Commission's proposal to modify the standard to require 
listing the contingencies that transmission owners use when they 
perform system operation and planning studies.
    1138. FirstEnergy supports the Commission's proposal to require 
transmission owners to provide the list of contingencies used in 
performing system operation and planning studies. FirstEnergy 
emphasizes that such a requirement, however, should accommodate various 
electronic formats that are commonly used in industry simulation tools. 
FirstEnergy states that compliance with this Reliability Standard 
should not require transmission owners to replace existing computer 
and/or software systems, and that the new standard should also require 
the regional reliability organizations (or Regional Entities) to 
coordinate the lists of contingencies across wide-areas.
    1139. In its support of the Commission's proposal, MidAmerican and 
TANC stress that a requirement that the transmission owner provide a 
list of contingencies to neighboring systems will benefit reliability 
by enabling neighboring systems to accurately study the effects of 
contingencies on their own systems. In its concurring comments, TANC 
recommends that the Commission clarify that the list of the 
contingencies that are used in performing system operation and planning 
studies include all the contingencies, N-1, N-2, as well as multiple 
contingencies.
    1140. MidAmerican cautions that a list of contingencies could be 
used in a ``cook-book'' manner to reach the wrong conclusions. A 
contingency must be modeled in specific and appropriate conditions to 
understand the reliability issues associated with the contingency.\351\ 
Similarly, NERC states that there may be a need to better understand 
the reliability need for transmission owners to provide a list of 
contingencies and to whom the list should be provided.
---------------------------------------------------------------------------

    \351\ MidAmerican further cautions that other contingencies 
exist that must be studied under still-different conditions. 
Advanced applications associated with real-time contingency analysis 
review an extensive list of events in combination with other events. 
Ahead of time, there is no way to be sure exactly which events are 
the worst in any given operating condition. A single reliability 
standard cannot contain all the coordination that is needed to allow 
a system to fully understand all the reliability challenges of a 
neighboring system. Thus, MidAmerican contends that a better 
approach is to continue the joint operational and long-term planning 
that planning authorities, reliability coordinators and other 
regional entities are currently conducting with transmission 
planners, transmission owners and others to ensure that the 
interconnected network is operated and planned in a coordinated way.
---------------------------------------------------------------------------

    1141. Northern Indiana and MidAmerican note that such a list of 
contingencies should be considered a particularly sensitive form of 
CEII since it would be a list of events that, when they occur, cause 
critical situations on a system. Northern Indiana and MidAmerican argue 
that the Commission should include the need to provide for protection 
against public disclosure through the NERC administrative process in 
its discussion of any final Reliability Standard. In addition, 
California Cogeneration states that Requirements R1 and R2 of this 
standard should not apply to entities that have no material impact on 
the grid. California Cogeneration warns that the standard may also 
require generator owners to provide data on behind-the-meter 
operations, the provision of which should be seriously limited, and 
data on future interchange schedules, the confidentiality of which 
should be maintained.
    1142. PG&E and Xcel oppose the proposed modification requiring a 
list of contingencies stating that the requirement is unnecessary and 
would be unduly burdensome. Xcel also states that the modification 
would not prove to be useful to neighboring systems. No such lists are 
currently developed or maintained today. Rather, the contingencies are 
reflected in the computerized models used by transmission providers for 
both transmission planning and operations. The models are regularly 
updated as new facilities are installed. If transmission operators are 
required to develop such lists, they would be so long and subject to 
constant change that they would not only be burdensome to develop and 
maintain, but also unlikely to provide useful information for other 
transmission owners.
    1143. In its opposition to releasing a list of contingencies, PG&E 
states that performing transmission planning studies is an ambiguous 
part of the duties of a transmission owner under the NERC Functional 
Model. Further clarification and refinement of the responsibilities of 
each entity under the NERC Functional Model may indicate that such 
studies are among a transmission owner's duties. Until that happens, 
however, requiring transmission owners to provide contingencies used in 
performing system operation and planning studies is inappropriate.
    1144. SoCal Edison and TVA state that the entity that should be 
responsible for providing a list of contingencies in performing 
planning and operation studies is the transmission planner, not the 
transmission owner. APPA also believes that the transmission operator 
should be one of the entities required to list contingencies used to 
perform studies, and that the transmission owner function should be 
removed as an applicable entity. APPA further notes that the 
transmission owner does no studies regarding operations or planning. A 
transmission owner merely owns transmission facilities and maintains 
those facilities. Moreover, APPA argues that existing studies performed 
by the transmission planner for the regional reliability organization 
or planning authority will include a list of contingencies.
    1145. Regarding the Commission's proposal to expand the 
applicability section of this Reliability Standard to include the 
planning authority, APPA disagrees and recites the comments of MRO, 
Reliability First and PG&E on the Staff Preliminary Assessment,\352\ 
that to require the planning authority to provide all of this 
information is duplicative and unnecessary. APPA believes that NERC, as 
the entity charged with developing standards, is best-suited to address 
all of these

[[Page 16528]]

concerns and to develop a consensus standard using its Reliability 
Standard development process.
---------------------------------------------------------------------------

    \352\ NOPR at P 663.
---------------------------------------------------------------------------

    1146. TAPS states that this standard would impose unnecessary costs 
on small systems without improving reliability if applied without the 
limitation of NERC's bulk electric system definition and NERC's June 
registry criteria. TAPS opines that modeling will be complicated by the 
incorporation of low voltage or radial transmission facilities or small 
generators that have no material impact on bulk transmission system 
reliability, without improving the results. TAPS further argues that 
NERC and the Regional Entities--not the Commission--should determine 
the level of modeling required for reliability.
ii. Commission Determination
    1147. The Commission approves MOD-010-0. In addition, the 
Commission requires the ERO to modify MOD-010-0 as described below.
    1148. As an initial matter, the Commission disagrees that MOD-010-0 
cannot be implemented until MOD-011-0 is modified. We have directed 
that data collection and reporting procedures not be interrupted while 
MOD-011-0 is being modified. Therefore it is possible to implement MOD-
010-0. Failure to have the data needed for the steady-state analysis 
would halt regional reliability assessment processes and hinder 
planners from accurately predicting future system conditions, which 
would be detrimental to system reliability. We therefore direct the ERO 
to use its authority pursuant to Sec.  39.2(d) of our regulations to 
require users, owners and operators to provide to the Regional Entity 
the information related to data gathering, data maintenance, 
reliability assessments and other process-type functions. As we discuss 
below in the section on MOD-011-0, we direct the ERO to develop a Work 
Plan that will facilitate ongoing collection of the steady-state 
modeling and simulation data set forth in MOD-011-0, and submit a 
compliance filing with that Work Plan.
    1149. Supported by many commenters, we adopt the NOPR proposal to 
direct the ERO to modify MOD-010-0 to require filing of all of the 
contingencies that are used in performing steady-state system operation 
and planning studies. We believe that access to such information will 
enable planners to accurately study the effects of contingencies 
occurring in neighboring systems on their own systems, which will 
benefit reliability. Because of the lack of information on contingency 
outages and the automatic actions that result from these contingencies, 
planners have not been able to analyze neighboring conditions 
accurately, thereby potentially jeopardizing reliability on their own 
and surrounding systems. This requirement will make transmission 
planning data more transparent, consistent with Order No. 890 requiring 
greater openness of the transmission planning process.
    1150. With respect to TANC's recommendation to modify the standard 
to require utilities to provide lists of all contingencies they use to 
operate and plan their systems (N-1, N-2, multiple), we clarify that 
our requirement specifies contingency files used for all operations and 
planning. We do not limit the provision of contingency information to 
single, double or multiple outages. Utilities must provide lists of all 
the contingencies they use in operations and planning, provided in 
their original format, regardless of how this data is organized.
    1151. In response to MidAmerican, NERC and TANC's concerns that the 
contingency lists could be used as a ``cook-book,'' our expectation is 
that utility planners that use these files will have sufficient 
experience to use them appropriately. We expect that most utility 
planners are already familiar with their neighbors' system topologies, 
and have the means, such as bus abbreviation directories and switching 
diagrams, to identify facilities listed in contingency files.
    1152. We agree with FirstEnergy's comments regarding the importance 
of using existing data collection systems so as to not impose any 
additional costs on entities. They may file the contingency files in 
the electronic format in which they were created, along with any 
necessary decoding instructions. We therefore disagree with PG&E, TAPS 
and Xcel that this Reliability Standard will be unduly burdensome since 
it only requires the provision of files that must be developed during 
the utility's usual planning and operations study process.
    1153. Consistent with California Cogeneration, Northern Indiana and 
MidAmerican's concerns, we determine that those data that a company 
considers confidential, commercially-sensitive or security-sensitive 
should be released in accordance with the CEII process or subject to 
confidentiality agreements. We direct the ERO to address 
confidentiality issues and modify the Reliability Standard as necessary 
through its Reliability Standards development process.
    1154. We disagree with commenters that generators or small entities 
that do not have a material impact on grid reliability should be 
automatically exempt from providing the data required by this 
Reliability Standard. The Commission believes that all entities that 
are required to register under the registration process that we have 
approved must provide data requested by the ERO or the Regional Entity.
    1155. We agree with APPA, SoCal Edison and TVA that the functional 
entity responsible for providing the list of contingencies in 
performing planning studies should be the transmission planner, instead 
of the transmission owner, as proposed in the NOPR. We also agree with 
APPA that the transmission operator should be one of the entities 
required to list contingencies used to perform operational studies. 
Transmission operators are usually responsible for compiling the 
operational contingency lists for both normal and conservative 
operation. Therefore, we direct the ERO to modify MOD-010-0 to include 
transmission operators as an applicable entity.
    1156. We adopt our NOPR proposal that the planning authority should 
be included in this Reliability Standard because the planning authority 
is the entity responsible for the coordination and integration of 
transmission facilities and resource plans, as well as one of the 
entities responsible for the integrity and consistency of the data. We 
disagree with APPA that it is duplicative and unnecessary to require 
the planning authority to provide all of this information. However, we 
direct the ERO, as the entity charged with developing Reliability 
Standards, to address all of these concerns and to develop a consensus 
standard using its Reliability Standard development process.
    1157. Accordingly, the Commission approves MOD-010-0 as mandatory 
and enforceable. In addition, the Commission directs the ERO to develop 
a modification to MOD-010-0 through the Reliability Standards 
development process that: (1) Adds a new requirement in MOD-010-1 for 
transmission planners to provide the contingency lists they use in 
performing system operation and planning studies, contained in the 
electronic format in which they were created, along with any necessary 
decoding instructions and (2) expands the applicability section to 
include transmission operators and the planning authority. We also 
direct the ERO to address confidentiality and small entity issues 
through the Reliability Standards development process.

[[Page 16529]]

m. Maintenance and Distribution of Steady-State Data Requirements and 
Reporting Procedures (MOD-011-0)
    1158. The purpose of MOD-011-0 is to establish consistent data 
requirements, reporting procedures and system models for use in 
reliability analysis. This Reliability Standard requires the regional 
reliability organizations to develop comprehensive steady-state data 
requirements and reporting procedures needed to model and analyze the 
steady-state conditions for each Interconnection.
    1159. In the NOPR, the Commission identified MOD-011-0 as a fill-
in-the-blank standard that requires each regional reliability 
organization to develop comprehensive steady-state data requirements 
and reporting procedures needed to model and analyze the steady-state 
conditions for each Interconnection. The NOPR stated that because the 
regional methodologies had not been submitted, the Commission would not 
propose to approve or remand MOD-011-0 until the ERO submits the 
additional information. In addition, the NOPR suggested that the 
planning authority plays a significant role in integration of data and 
thus should be included in the applicability section of MOD-011-0.
i. Comments
    1160. APPA agrees with the Commission that this standard is a fill-
in-the-blank standard, is not sufficient as currently drafted and 
should not be approved as a mandatory reliability standard until NERC 
and the Regional Entities develop the necessary methodologies and the 
Commission approves them.
    1161. TANC supports replacing the term regional reliability 
organization with an entity from the NERC Functional Model.
ii. Commission Determination
    1162. The Commission will not approve or remand MOD-011-0 until the 
ERO submits additional information. The Commission directs the ERO to 
modify MOD-011-0 as discussed below.
    1163. We reiterate our position stated in the NOPR that the 
planning authority should be included in this Reliability Standard 
because the planning authority is the entity responsible for the 
coordination and integration of transmission facilities and resource 
planning, as well as one of the entities responsible for the integrity 
and consistency of the data. Therefore, we direct the ERO to add the 
planning authority to the applicability section of this Reliability 
Standard.
    1164. In response to concerns raised in MOD-010-0 about 
implementing MOD-010-0 without the data to be collected when MOD-011-0 
is modified, we direct the ERO to develop a Work Plan that will 
facilitate ongoing collection of the steady-state modeling and 
simulation data specified in MOD-011-0.
    1165. Accordingly, the Commission neither accepts nor remands MOD-
011-0 until the ERO submits additional information. Because the 
regional procedures have not been submitted to the Commission, it is 
not possible to determine at this time whether MOD-011-0 satisfies the 
statutory requirement that a proposed Reliability Standard be ``just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest.'' In the interim, compliance with MOD-011-0 should 
continue on a voluntary basis, and the Commission considers compliance 
with the Reliability Standard to be a matter of good utility practice. 
We direct the ERO to modify the Reliability Standard through the 
Reliability Standards development process to expand the applicability 
section to include the planning authority. Additionally, we direct the 
ERO to develop a Work Plan and submit a compliance filing that will 
facilitate ongoing collection of the steady-state modeling and 
simulation data specified in MOD-011-0.
n. Dynamics Data for Modeling and Simulation of the Interconnected 
Transmission System (MOD-012-0)
    1166. The purpose of MOD-012-0 is to establish consistent data 
requirements, reporting procedures and system models for use in 
reliability analysis. MOD-012-0 requires transmission owners, 
transmission planners, generator owners and resource planners to 
provide dynamic system modeling and simulation data, such as equipment 
characteristics and system data, to the regional reliability 
organization, NERC and other specified entities.
    1167. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-012-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-012-
0 that: (1) Adds a new requirement for transmission owners to provide 
the list of faults or disturbances they use in performing dynamics 
system modeling analysis for system operation and planning and (2) 
expands the applicability section to include the planning authority.
i. Comments
    1168. APPA and PG&E agree that the Commission should approve MOD-
012-0 as a mandatory and enforceable Reliability Standard. However, 
PG&E requests the Commission to approve this standard without any 
modifications. In addition, APPA states that the Commission's proposed 
directives to NERC to revise this standard are unduly prescriptive, and 
may not in fact be the best way to revise the standard. APPA notes that 
NERC, as the technical expert body charged with developing standards, 
is the entity best suited to hear all of these concerns, and to develop 
a consensus standard using its Reliability Standards development 
process.
    1169. ISO/RTO Council and ISO-NE disagree with the Commission's 
proposal to approve this standard, and state that the MOD-012-0 
requirements refer several times to the ``data requirements and 
reporting procedures of MOD-013-0,'' which has been identified by the 
Commission as a fill-in-the-blank standard, and is pending. 
Consequently, they argue that MOD-012-0 cannot be effectively 
implemented, and responsible entities should therefore not be subject 
to compliance with an incomplete standard.
    1170. With respect to the Commission's proposal for adding a new 
requirement to this standard, FirstEnergy notes that it is appropriate 
for the Commission to require transmission owners to provide the list 
of faults or disturbances used in performing dynamics system studies. 
However, FirstEnergy cautions that such requirement should accommodate 
various electronic formats that are commonly used in industry 
simulation tools. FirstEnergy states that compliance with this 
provision should not require transmission owners to replace existing 
computer and/or software systems, and that the new standard should also 
require the regional reliability organizations (or Regional Entities) 
to coordinate the lists of faults or disturbances across wide-areas.
    1171. MidAmerican agrees that requiring transmission owners to 
provide a list of faults or disturbances to neighboring systems would 
provide for additional coordination between neighboring utilities, and 
therefore, would be an improvement to the standard.
    However, MidAmerican warns that a list of faults and disturbances 
could be

[[Page 16530]]

used in a ``cook-book'' manner to reach the wrong conclusions.\353\
---------------------------------------------------------------------------

    \353\ MidAmerican further discusses that the Commission should 
recognize that caution must be taken in assuming that no other 
faults and disturbances exist that must be studied under other 
conditions. MidAmerican states that like with MOD-010-0, ahead of 
time, there is no way to be sure exactly which faults and 
disturbances are the worst under given operating conditions. A 
single reliability standard cannot contain all the coordination 
needed to allow each system operator to fully understand all the 
reliability challenges of a neighboring system. Perhaps a better 
approach is to continue the joint operational and long-term planning 
that is currently being conducted by planning authorities, 
reliability coordinators and other regional entities with 
transmission planners, transmission owners and others to ensure that 
the interconnected network is operated and planned in a coordinated 
way.
---------------------------------------------------------------------------

    1172. Northern Indiana and MidAmerican note that such a list of 
faults and disturbances should be considered a particularly sensitive 
form of CEII since it would be a list of events that, when they occur, 
cause critical problems on the system. Northern Indiana and MidAmerican 
request the Commission to protect sensitive information through the 
NERC administrative process discussed in the TOP-005-1 Reliability 
Standard.
    1173. Xcel raises the same concern it stated about MOD-010-0 that 
the proposed modification related to a list of faults and disturbances 
is unduly burdensome and would not prove useful to neighboring systems. 
Xcel states that no such lists are currently developed or maintained 
today, but that the faults and disturbances are reflected in the 
computerized models used by transmission providers for both 
transmission planning and operations, which are regularly updated as 
new facilities are installed. Xcel cautions that the lists, as proposed 
by the Commission, would be so long and subject to constant change that 
they would not only be burdensome to develop and maintain, but also 
unlikely to provide usable information for other transmission owners.
    1174. PG&E disagrees with the Commission's proposal related to 
lists of faults and disturbances, and repeats its comments from MOD-
010-0 that this new requirement is unnecessary.
    1175. Regarding the functional entities to which this standard 
applies, APPA notes that the transmission operator and transmission 
planner, as functions required to provide information regarding 
stability studies, should be added to the list of applicable entities, 
while transmission owners should be removed from such list. Under the 
NERC Functional Model, transmission owners do not perform any studies 
related to MOD-012-0. Rather, a transmission owner merely owns 
transmission facilities and maintains them.
    1176. California Cogeneration states that this standard raises 
concerns about data collection and the cost of compliance, and 
therefore a mechanism for determining no material impact and a 
provision for exemption is essential for this standard. California 
Cogeneration also believes that it is unclear what data is included in 
``dynamics system modeling and simulation data,'' and whether 
independent generators would have such data.
ii. Commission Determination
    1177. The Commission approves MOD-012-0 as mandatory and 
enforceable. The Commission directs the ERO to modify MOD-012-0 as 
discussed below.
    1178. As an initial matter, the Commission disagrees that MOD-012-0 
cannot be implemented until MOD-013-1 is modified. We have directed 
that data collection and reporting procedures not be interrupted while 
MOD-013-1 is being revised, therefore it is possible to implement MOD-
012-0. Failure to provide the data needed for dynamics system modeling 
and simulation would halt regional reliability assessment processes and 
impede planners from accurately predicting future system conditions, 
which would be detrimental to system reliability. We therefore direct 
the ERO to use its authority pursuant to Sec.  39.2(d) of our 
regulations to require users, owners and operators to provide to the 
Regional Entities the information related to data gathering, data 
maintenance, reliability assessments and other process type functions. 
As we will discuss in the next section on MOD-013-1, we require the ERO 
to develop a Work Plan and submit a compliance filing that will 
facilitate ongoing collection of the dynamics system modeling and 
simulation data specified by the deferred MOD-013-1 Reliability 
Standard, which is necessary for implementation of MOD-012-0.
    1179. Supported by several commenters, we adopt the NOPR proposal 
and direct the ERO to modify MOD-012-0 by adding a new requirement to 
provide a list of the faults and disturbances used in performing 
dynamics system studies for system operation and planning. We believe 
that access to such information will enable planners to accurately 
study the effects of disturbances occurring in neighboring systems on 
their own systems, which will benefit reliability. This requirement 
will also make transmission planning data more transparent, consistent 
with Order No. 890, which calls for greater openness of the 
transmission planning process on a regional basis.
    1180. In response to MidAmerican's concern that fault and 
disturbance information could be used as a ``cook-book,'' our 
expectation is that utility planners who use this data have sufficient 
experience to use it and interpret the results correctly. We expect 
that most utility planners are already familiar with their neighbors' 
system topologies, and will be capable of identifying facilities on 
fault and disturbance lists.
    1181. We agree with FirstEnergy's concerns regarding the importance 
of using existing data collection systems so as to not impose any 
additional costs on entities. They may file the fault and disturbance 
information in the electronic format in which they were created, along 
with any necessary decoding instructions. Compliance with this 
provision should not require transmission planners to replace existing 
computer and/or software systems. Therefore, we disagree with PG&E and 
Xcel that this standard modification will be unduly burdensome.
    1182. Consistent with California Cogeneration, Northern Indiana and 
MidAmerican's concerns, we determine that the data that a company 
considers confidential, market-sensitive or security-sensitive should 
be released in accordance with the CEII process or subject to 
confidentiality agreements. We direct the ERO to address 
confidentiality issues and modify the standard as necessary through its 
Reliability Standards development process.
    1183. We disagree with commenters that generators or small entities 
that do not have a material impact on grid reliability should be 
automatically exempt from providing the data required by this 
Reliability Standard. The Commission believes that all entities that 
are required to register under the registration process that we have 
approved must provide data requested by the ERO or the Regional Entity.
    1184. We agree with APPA that the functional entity responsible for 
providing the fault and disturbance list should be the transmission 
planner, instead of the transmission owner, as proposed in the NOPR. We 
also agree with APPA that the transmission operator should be added to 
the list of applicable entities in the Reliability Standards 
development process. Therefore, we direct the ERO to modify

[[Page 16531]]

MOD-012-0 to require the transmission planner to provide fault and 
disturbance lists.
    1185. We adopt our NOPR proposal that planning authorities should 
be included in this Reliability Standard because the planning authority 
is the entity responsible for the coordination and integration of 
transmission facilities and resource plans, as well as one of the 
entities responsible for the integrity and consistency of the data. We 
therefore direct the ERO to add the planning authority to the list of 
applicable entities.
    1186. Accordingly, the Commission approves MOD-012-0 as mandatory 
and enforceable. In addition, the Commission directs the ERO to develop 
a modification to MOD-012-0 through the Reliability Standards 
development process that: (1) Adds a new requirement for transmission 
planners to provide the list of faults and disturbances they use in 
performing dynamic stability analysis in the electronic format in which 
they were created, along with any necessary decoding instructions and 
(2) expands the applicability section to include transmission 
operators, planning authorities and transmission planners. We expect 
the ERO to address confidentiality issues and modify the Reliability 
Standard as necessary through the Reliability Standards development 
process.
o. Maintenance and Distribution of Dynamics Data Requirements and 
Reporting Procedures (MOD-013-1)
    1187. MOD-013-1 requires the regional reliability organizations 
within an Interconnection to develop comprehensive dynamics data 
requirements and reporting procedures needed to model and analyze the 
dynamic behavior and response of each Interconnection. More 
specifically, the regional reliability organization, in coordination 
with its transmission owners, transmission planners, generator owners 
and resource planners within an Interconnection, is required to: (1) 
Participate in development of documentation for their Interconnection 
data requirements and reporting procedures; (2) participate in the 
review of those data requirements and reporting procedures at least 
every five years and (3) make the data requirements and reporting 
procedures available to NERC and other specified entities upon request.
    1188. In the NOPR, the Commission identified MOD-013-1 as a fill-
in-the-blank standard that requires each regional reliability 
organization within an Interconnection to develop comprehensive 
dynamics data requirements and reporting procedures needed to model and 
analyze the dynamic behavior and response for each of the three NERC 
Interconnections. The NOPR stated that because the regional 
methodologies had not been submitted, the Commission would not propose 
to approve or remand MOD-013-1 until the ERO submits additional 
information. In addition, in the NOPR we agreed that the Reliability 
Standard should apply to the planning authority.
    1189. In the NOPR, the Commission expressed a concern regarding the 
1990 cut-off date,\354\ and shared PG&E's concern that the difficulty 
in obtaining unit-specific data is not limited to the age, but may also 
be due to other factors such as unit configuration. The Commission 
requested comment whether it is reasonable to permit entities to 
estimate dynamics data if they are unable to obtain unit specific data 
for any reason. The Commission believes that to achieve the goal of 
this Reliability Standard of having the ability to accurately model and 
analyze the dynamic behavior and response of each Interconnection, it 
is necessary to have accurate data. Inaccurate data can lead to 
unrealistic simulations and inappropriate actions by responsible 
entities which may jeopardize the reliability of the Bulk-Power System.
---------------------------------------------------------------------------

    \354\ Requirement R1.1.1 allows for the use of estimated or 
typical manufacturer's data on pre-1990 units to model dynamic 
behavior when unit-specific data is unavailable.
---------------------------------------------------------------------------

i. Comments
    1190. APPA agrees with the Commission that MOD-013-1 is a fill-in-
the-blank standard, is not sufficient as currently drafted, and should 
not be approved as a mandatory Reliability Standard until NERC and the 
regional reliability organizations/Regional Entities develop the 
necessary regional methodologies and the Commission approves them.
    1191. In response to the Commission's request for comments on 
whether it is reasonable to permit entities to estimate dynamics data 
if they are unable to obtain unit specific data for any reason, many 
commenters responded that it is reasonable to allow estimation of 
dynamics data for older units where data is not available.\355\ The 
Small Entities Forum expects that the Reliability Standard ultimately 
will include requirements that such estimates be based on sound 
engineering principles and be subject to technical review and approval 
of any estimates at the regional level.
---------------------------------------------------------------------------

    \355\ EEI, LPPC, MidAmerican, Small Entities Forum and TVA.
---------------------------------------------------------------------------

    1192. MidAmerican explains that there may be safety or system 
conditions and/or the loss of records that do not permit gathering 
unit-specific information, and that in such cases, computations and 
engineering reports of estimated capability should be sufficient. 
MidAmerican also requests that if there is a farm of similar generation 
units (such as wind turbines) or synchronous condensers located in the 
same general area, providing unit-specific information for a number of 
identical units is not necessary. Instead, MidAmerican proposes that 
information about a sample of the identical units (such as two) should 
be sufficient to provide enough unit-specific information to be 
representative of the farm. MidAmerican also notes that if units are 
located in a part of the system that does not typically demonstrate 
instability, the value of unit-specific data is reduced, and that there 
are a number of such circumstances in which provision of unit-specific 
data should not be required.
    1193. International Transmission, stating that the age of the unit 
alone may not be the only reason why unit-specific data might be 
unavailable, cautions that there should be a requirement in every case 
that unit data actually be sought for all generating units before 
estimates of dynamics data are used. International Transmission 
believes that achieving the most accurate possible picture of the 
dynamic behavior of the Interconnection requires the use of actual 
data, and that, at a minimum, entities should be required to document 
the steps taken to obtain unit-specific data.
    1194. APPA, however, expresses its concern regarding the 
difficulties in obtaining accurate unit-specific data to model dynamic 
behavior. APPA recommends to NERC that the regional reliability 
organizations/Regional Entities and the reliability coordinators review 
this type of data on a case-by-case basis to test it for accuracy and 
to determine whether estimated data will produce outputs from the 
models within acceptable limits. International Transmission confirms 
that testing is easily accomplished, and provides up-to-date dynamics 
data reflective of the natural degradation of generating units over 
their lifetimes. However, International Transmission says that this 
effort could be tied to the Generator Model Validation Reliability 
Standards (MOD-024-1 and MOD-025-1).
    1195. TANC agrees with the Commission that the standard requirement 
is arbitrary in imposing the

[[Page 16532]]

1990 cut-off with regard to modeling dynamic behavior. TANC believes 
that this requirement allows for the use of estimated or typical 
manufacturer's data on pre-1990 units to model dynamic behavior when 
unit-specific data is unavailable. TANC notes that difficulty in 
obtaining unit specific data is not limited to the age of the unit but 
also unit configuration. TANC therefore recommends that the 1990 cut-
off be removed from the proposed Reliability Standard because there is 
no justifiable basis for the arbitrary cut-off and that the Reliability 
Standard be revised to allow the generally-accepted use of estimated or 
typical manufacturer data where unit-specific data is impractical to 
obtain. TVA agrees that the 1990 cut-off date is unnecessary.
    1196. In contrast to those who support rejecting the 1990 cut-off 
requirement, FirstEnergy states that unit-specific data should be 
required for all units installed after 1990. EEI confirms that unit-
specific information should be available for most units placed in 
service since 1990.
ii. Commission Determination
    1197. The Commission will not approve or remand MOD-013-1 until the 
ERO submits additional information. The Commission directs the ERO to 
modify MOD-013-1 through the Reliability Standards development process 
as discussed below.
    1198. We agree with many commenters and direct the ERO to modify 
the Reliability Standard to permit entities to estimate dynamics data 
if they are unable to obtain unit-specific data for any reason, not 
just for units constructed prior to 1990. Achieving the most accurate 
possible picture of the dynamic behavior of the Interconnection 
requires the use of actual data. We disagree with FirstEnergy and EEI 
and reject the 1990 cut-off date, because the age of the unit alone may 
not be the only reason why unit-specific data is unavailable. We agree 
with the Small Entities Forum that the Reliability Standard should 
include Requirements that such estimates be based on sound engineering 
principles and be subject to technical review and approval of any 
estimates at the regional level. That said, the Commission directs that 
this Reliability Standard be modified to require that the results of 
these dynamics models be compared with actual disturbance data to 
verify the accuracy of the models.
    1199. With respect to small units installed in wind farms, we agree 
with MidAmerican that data for one unit to represent all identical 
units at wind farms is acceptable. The Commission understands that this 
is the current approach with any generator that is manufactured in 
quantity such as multiple generators used in combined cycle plants.
    1200. We adopt our NOPR proposal and direct the ERO to expand the 
applicability section in this Reliability Standard to include planning 
authorities because they are the entities responsible for the 
coordination and integration of transmission facilities and resource 
plans, as well as one of the entities responsible for the integrity and 
consistency of the data.
    1201. Accordingly, the Commission neither accepts nor remands MOD-
013-1 until the ERO submits additional information. Because the 
regional procedures have not been submitted to the Commission, it is 
not possible to determine at this time whether MOD-013-1 satisfies the 
statutory requirement that a proposed Reliability Standard be ``just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest.'' In the interim, compliance with MOD-013-1 should 
continue on a voluntary basis, and the Commission considers compliance 
with the Reliability Standard to be a matter of good utility practice. 
Although the Commission does not approve or remand MOD-013-1, we direct 
the ERO to modify it through the Reliability Standards development 
process to: (1) Permit entities to estimate dynamics data if they are 
unable to obtain unit specific data for any reason; (2) require 
verification of the dynamic models with actual disturbance data and (3) 
expand the applicability section to include the planning authority, 
transmission operator and transmission planner. As discussed above in 
MOD-012-0, we direct the ERO to develop a Work Plan that will 
facilitate ongoing collection of the dynamics system modeling and 
simulation data specified in MOD-013-1, and submit a compliance filing 
containing this Work Plan to the Commission.
p. Development of Steady-State System Models (MOD-014-0)
    1202. MOD-014-0 requires the regional reliability organizations 
within each Interconnection to coordinate and jointly develop and 
maintain a library of solved Interconnection-specific steady-state 
models. These models are to include near- and long-term planning 
horizons representing system conditions for various demand levels. The 
models are to be updated annually.
    1203. In the NOPR, the Commission identified MOD-014-0 as a fill-
in-the-blank standard that requires the regional reliability 
organizations within an Interconnection to develop, coordinate and 
maintain a library of solved Interconnection-specific steady-state 
models. The NOPR stated that because the regional procedures had not 
been submitted, the Commission would not propose to approve or remand 
MOD-014-0 until the ERO submits the additional information. In 
addition, in the NOPR the Commission stated its belief that the 
Reliability Standard should be modified to include a requirement to 
verify that steady-state models are accurate.
    1204. In the NOPR, the Commission expressed concern about creating 
a duplicate effort if both the transmission owner and the regional 
reliability organization separately develop the steady-state base cases 
required for the FERC Form 715 filing and for MOD-014-0. The NOPR 
suggested that the Reliability Standard contain a requirement 
specifying the time period and planning years be identical to those 
found in FERC Form 715.\356\ Further, the Commission requested comments 
on any incompatibility between requirements under FERC Form 715 and 
MOD-014-0.
---------------------------------------------------------------------------

    \356\ FERC Form 715 is available at http://www.ferc.gov/docs-filing/eforms.asp#715.
---------------------------------------------------------------------------

i. Comments
    1205. APPA agrees with the Commission that MOD-014-0, a fill-in-
the-blank standard, is not sufficient as currently drafted, and should 
not be approved as a mandatory Reliability Standard until NERC and the 
regional reliability organizations/Regional Entities develop the 
necessary regional methodologies and the Commission approves them.
    1206. NRC suggests that a periodic verification against field data 
needs to be included in this Reliability Standard.
    1207. Regarding the Commission's request for comments on any 
incompatibility between requirements under FERC Form 715 and MOD-014-0, 
International Transmission states that the language in MOD-014-0 would 
allow the regional reliability organization and the transmission owner 
to develop separate base cases. International Transmission notes that 
its experience with current practice suggests, however, that this is 
not a significant concern. Transmission owners now develop the 
information for inclusion in a regional base case, and the regional 
base case is rolled up into a FERC Form 715 filing by a regional 
entity. International Transmission expects that this process would 
continue in the future.

[[Page 16533]]

    1208. MISO believes that FERC should revisit the need for 
transmission owners to have base case information available for 
replication. MISO states that the current Interconnection trend is for 
transmission owners to work together more closely in developing large 
assessments based on a large model, and that these large assessments 
are better guides to the overall capability of the transmission grid to 
move power. MISO believes that these assessments should be filed as 
part of FERC Form 715.
    1209. Although Northern Indiana does not see any duplication or 
incompatibility with FERC Form 715, Northern Indiana is concerned that 
the proposed Reliability Standard envisions the use of steady-state 
models and benchmarking for long-term planning. Northern Indiana 
believes that benchmarking of planning models should be directed 
towards validation of line constraints and general comparison of 
modeled to actual load levels. Northern Indiana suggests that this 
could be accomplished through validation processes that would first 
evaluate the data used to model the transformers and the lines and 
determine that such data is correct, and then compare the loads in 
total against the actual loads, followed by an examination of 
individual load points on a system.
ii. Commission Determination
    1210. The Commission will not approve or remand MOD-014-0 until the 
ERO submits additional information. Because the regional procedures 
have not been submitted to the Commission, it is not possible to 
determine at this time whether MOD-014-0 satisfies the statutory 
requirement that a proposed Reliability Standard be ``just, reasonable, 
not unduly discriminatory or preferential, and in the public 
interest.'' The Commission directs the ERO to modify MOD-014-0 as 
discussed below.
    1211. We maintain our position set forth in the NOPR that analysis 
of the Interconnection system behavior requires the use of accurate 
steady-state models. Therefore, we direct the ERO to modify the 
Reliability Standard to include a requirement that the models be 
validated against actual system responses. We understand that NERC is 
incorporating recommendations from the Blackout Report \357\ and 
developing models for the Eastern Interconnection.
---------------------------------------------------------------------------

    \357\ Recommendation Number 24 of the Blackout Report at 160.
---------------------------------------------------------------------------

    1212. Further, the maximum discrepancy between the model results 
and the actual system response should be specified in the Reliability 
Standard. The Commission believes that the maximum discrepancy between 
the actual system performance and the model should be small enough that 
decisions made by planning entities based on output from the model 
would be consistent with the decisions of operating entities based on 
actual system response. We direct the ERO to modify MOD-014-0 through 
the Reliability Standards development process to require that actual 
system events be simulated and if the model output is not within the 
accuracy required, the model shall be modified to achieve the necessary 
accuracy.
    1213. We believe that steady-state model validation should not be 
interrupted while MOD-014-0 is being modified. The lack of accurate 
models needed for the simulations would halt regional reliability 
assessment processes and hinder planners from accurately predicting 
future system conditions, which would be detrimental to system 
reliability. We therefore direct the ERO to use its authority pursuant 
to Sec.  39.2(d) of our regulations to require users, owners and 
operators to provide the validated models to regional reliability 
organizations. We direct the ERO to develop a Work Plan that will 
facilitate ongoing validation of steady-state models and submit a 
compliance filing containing the Work Plan with the Commission.
    1214. Consistent with many commenters' responses, we find changes 
to FERC Form 715 are not necessary at this time, because there is no 
conflict between data gathering and model construction with the FERC 
Form 715 process.
    1215. The Commission neither accepts nor remands MOD-014-0. Because 
the regional procedures have not been submitted to the Commission, it 
is not possible to determine at this time whether MOD-014-0 satisfies 
the statutory requirement that a proposed Reliability Standard be 
``just, reasonable, not unduly discriminatory or preferential, and in 
the public interest.'' In the interim, compliance with MOD-014-0 should 
continue on a voluntary basis, and the Commission considers compliance 
with the Reliability Standard to be a matter of good utility practice. 
We direct the ERO to: (1) modify the Reliability Standard through the 
Reliability Standards development process to require actual system 
events be simulated and model output validated against actual system 
responses and (2) develop a Work Plan and submit a compliance filing 
that will enable validation of the steady-state models while MOD-014-0 
is being modified.
q. Development of Dynamics System Models (MOD-015-0)
    1216. MOD-015-0 requires the regional reliability organizations 
within each Interconnection to coordinate and jointly develop and 
maintain a library of initialized (with no faults and disturbances) 
Interconnection-specific dynamics system models. These models represent 
near-term years and the years chosen from the longer-term planning 
horizon.
    1217. In the NOPR, the Commission identified MOD-015-0 as a fill-
in-the-blank standard that requires the regional reliability 
organizations within an Interconnection to develop, coordinate and 
maintain a library of initialized Interconnection-specific dynamics 
system models. The NOPR stated that because the regional procedures had 
not been submitted, the Commission would not propose to approve or 
remand MOD-015-0 until the ERO submits the additional information. In 
addition, the Commission stated that MOD-015-0 should include a 
requirement to verify accuracy of dynamics system models.
i. Comments
    1218. APPA agrees that MOD-015-0 is a fill-in-the-blank standard, 
is not sufficient as currently drafted and should not be approved as a 
mandatory reliability standard until NERC and the regional reliability 
organizations/Regional Entities develop the necessary regional 
methodologies and the Commission approves them.
    1219. EEI agrees with the Commission's proposal that a new 
requirement for verification of the accuracy of dynamics system models 
should be a part of this Reliability Standard. In addition, EEI states 
that the validation of models is a valid concern, but that any 
requirement in this area should be carefully considered, and that any 
requirement should be related to using the models to replicate events 
that occur on the system instead of developing separate testing 
procedures to verify the models. EEI believes that it would not be 
reasonable to subject generation units to artificial disturbances to 
validate the models. NRC recommends periodic verification against field 
data. APPA notes that if NERC modifies MOD-015-0 as APPA anticipates, a 
requirement to verify the accuracy of the dynamics system model would 
be included and the Regional Entity would be the compliance monitor.

[[Page 16534]]

ii. Commission Determination
    1220. The Commission will not approve or remand MOD-015-0 until the 
ERO submits additional information. Because the regional procedures 
have not been submitted to the Commission, it is not possible to 
determine at this time whether MOD-015-0 satisfies the statutory 
requirement that a proposed Reliability Standard be ``just, reasonable, 
not unduly discriminatory or preferential, and in the public 
interest.'' The Commission directs the ERO to modify MOD-015-0 through 
the Reliability Standards development process as discussed below.
    1221. We maintain our position set forth in the NOPR that the 
analysis of Interconnection system behavior requires the use of 
accurate dynamics system models. Therefore, we direct the ERO to modify 
the Reliability Standard to include a requirement that the models be 
validated against actual system responses. We agree with EEI and NRC 
and confirm our position that a requirement to verify that dynamics 
system models are accurate should be a part of this Reliability 
Standard. We agree with EEI that this new requirement should be related 
to using the models to replicate events that occur on the system 
instead of developing separate testing procedures to verify the models. 
We direct the ERO to modify the standard to require actual system 
events be simulated and dynamics system model output be validated 
against actual system responses.
    1222. We believe that dynamics system model validation should not 
be interrupted while MOD-015-0 is in the modification process. The lack 
of accurate models needed for the simulations would halt regional 
reliability assessment processes and hinder planners from accurately 
predicting future system conditions, which would be detrimental to 
system reliability. We therefore direct the ERO to use its authority 
pursuant to Sec.  39.2(d) of our regulations to require users, owners 
and operators to provide to the Regional Entity the validated dynamics 
system models while MOD-015-0 is being modified. We require the ERO to 
develop a Work Plan that will enable continual validation of dynamics 
system models and submit a compliance filing with the Commission.
    1223. The Commission neither accepts nor remands MOD-015-0 until 
the ERO submits additional information. Because the regional procedures 
have not been submitted to the Commission, it is not possible to 
determine at this time whether MOD-015-0 satisfies the statutory 
requirement that a proposed Reliability Standard be ``just, reasonable, 
not unduly discriminatory or preferential, and in the public 
interest.'' In the interim, compliance with MOD-015-0 should continue 
on a voluntary basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice. We direct 
the ERO to: (1) Modify the Reliability Standard through the Reliability 
Standards development process to require verification of the accuracy 
of dynamics system models and (2) develop a Work Plan and submit a 
compliance filing that will facilitate ongoing verification of the 
accuracy of dynamics system models while MOD-015-0 is being modified.
r. Documentation of Data Reporting Requirements for Actual and Forecast 
Demands, Net Energy for Load and Controllable Demand-Side Management 
(MOD-016-1)
    1224. The purpose of MOD-016-1 is to ensure that past and 
forecasted demand data is available for validation of past events and 
future system assessments. MOD-016-1 requires the planning authority 
and the regional reliability organization to have documentation 
identifying the scope and details of the actual and forecast demand and 
load data, and controllable DSM data to be reported for system modeling 
and reliability analysis.
    1225. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-016-1 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-016-
1 that expands the applicability section to include the transmission 
planner.
i. Comments
    1226. APPA agrees that MOD-016-1 is sufficient for approval as a 
mandatory and enforceable reliability standard.
    1227. In contrast, ISO/RTO Council and ISO-NE do not support 
adoption of this standard because it is contingent on standards that 
are pending approval by the Commission based on their characterization 
as applying only to regional reliability organizations, or because they 
have been categorized as fill-in-the-blank standards.\358\ ISO/RTO 
Council and ISO-NE agree that as a result, MOD-016-1 cannot be 
effectively implemented.
---------------------------------------------------------------------------

    \358\ TPL-005-0, TPL-006-0, MOD-011-0, MOD-013-0, MOD-014-0 and 
MOD-015-0.
---------------------------------------------------------------------------

    1228. APPA and FirstEnergy agree with the Commission's proposal to 
direct NERC to add the transmission planner function to the 
applicability section of the standard, although they argue that NERC, 
as the standards-setting entity, should make the decision.
    1229. TAPS does not oppose the proposed applicability of MOD-016-1, 
but opposes regional interpretations that apply the standard more 
broadly. TAPS criticizes SERC's supplement to MOD-016-1 that makes the 
standard applicable to LSEs, even though LSEs do not have the ability 
to identify the scope and details of the data required to be reported 
for system modeling and reliability analyses. TAPS contends that there 
are no physical differences that make SERC LSEs more capable in this 
regard than LSEs in other regions. TAPS recommends that the Commission 
clarify that it expects standards to be applied in a consistent and 
uniform manner as written, and will look closely at regional variations 
not justified by physical differences.
    1230. In contrast to APPA, FirstEnergy and TAPS, EEI believes that 
the standard assigns appropriate responsibility, and that the 
transmission planner should not be added to the applicability section 
of this standard. According to EEI, the transmission planner has no 
specific responsibilities for ensuring data integrity in day-to-day 
practice. EEI understands that data integrity falls within the daily 
responsibilities of data management functions, such as metering. EEI 
states that the NERC Functional Model does not describe technical 
functions at this level of detail. EEI notes, as it also notes in its 
comments on the TPL standards, that load-related DSM data of the type 
and specificity stated in the NOPR, such as load control of customer-
owned appliances, is related to distribution system and operations 
planning, and not to transmission system planning.
ii. Commission Determination
    1231. The Commission approves MOD-016-1 as mandatory and 
enforceable. In addition, the Commission directs the ERO to modify MOD-
016-1 as discussed below.
    1232. As an initial matter, we disagree that MOD-016-1 cannot be 
implemented until other unapproved standards are modified. As 
previously stated, we are requiring the ERO to provide a Work Plan and 
compliance filing regarding collection of information specified under 
standards that are deferred, and believe there should be no 
difficulties complying with this Reliability Standard. We reiterate 
that continual collection of data is necessary to maintain system 
reliability, and approval of MOD-016-1 will help to achieve this 
objective.
    1233. Supported by many commenters, the Commission directs

[[Page 16535]]

the ERO to modify MOD-016-1 and expand the applicability section to 
include the transmission planner, on the basis that under the NERC 
Functional Model the transmission planner is responsible for collecting 
system modeling data, including actual and forecast load, to evaluate 
transmission expansion plans. We disagree with EEI that this 
Reliability Standard should not be applied to the transmission planner 
because load-related data for controllable DSM is not only needed for 
distribution and transmission operations, but is also necessary for the 
transmission planner to take controllable DSM into account in planning 
the transmission system. Requirement R1.1 relates to data submittal, 
and requires data to be consistent with that supplied for the TPL-005 
and TPL-006 standards, which clearly apply to transmission planners. We 
approve the ERO's definition in the glossary of DSM as ``all activities 
or programs undertaken by a Load-Serving Entity or its customers to 
influence the amount or timing of electricity they use.'' Only 
activities or programs that meet the ERO definition, with the 
modification directed below, may be treated as DSM for purposes of the 
Reliability Standards. Recognizing the potential role that industrial 
customers who do not take service through an LSE and load aggregators, 
for example, may play in meeting the Reliability Standards, we direct 
the ERO to modify the definition of DSM. Specifically, we direct the 
ERO to add to its definition of DSM ``any other entities'' that 
undertake activities or programs to influence the amount or timing of 
electricity they use without violating other Reliability Standard 
Requirement.
    1234. In response to TAPS's criticism of SERC's desire to expand 
its regional standards relative to actual and forecast load to include 
LSEs, we clarify that we can only act on the standards before us. We do 
not make a decision on SERC's standards in this rule. We therefore 
recommend that TAPS raise this issue in the Reliability Standards 
development process.
    1235. The Commission approves Reliability Standard MOD-016-1 as 
mandatory and enforceable and directs the ERO to develop a modification 
to MOD-016-0 through the Reliability Standards development process to 
include the transmission planner in the applicability section.
s. Aggregated Actual and Forecast Demands and Net Energy for Load (MOD-
017-0)
    1236. The purpose of MOD-017-0 is to ensure that past and 
forecasted demand data is available for past event validation and 
future system assessment. MOD-017-0 requires LSEs, planning authorities 
and resource planners to annually provide aggregated information on: 
(1) Integrated hourly demands; (2) actual monthly and annual peak 
demand (MW) and net load energy (GWh) for the prior year; (3) monthly 
peak demand forecasts and net load energy for the next two years and 
(4) annual peak demand forecasts (summer and winter) and annual net 
load energy for at least five and up to ten years into the future.
    1237. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-017-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-017-
0 that includes new requirements for: (1) Reporting of temperature and 
humidity along with peak loads and (2) reporting of the accuracy, error 
and bias of load forecasts compared to actual loads while taking 
temperature and humidity variations into account.
i. Comments
    1238. APPA agrees that the Commission should approve MOD-017-0 as 
mandatory and enforceable.
    1239. In contrast to APPA, ISO-NE does not support approval of this 
standard because MOD-017-0 depends on MOD-016-0, which further depends 
on various unapproved standards. ISO-NE believes that this makes MOD-
017-0 dependent on unapproved standards, and that consequently, MOD-
017-0 cannot be effectively implemented. Similarly, ISO/RTO Council 
states that if the Commission does not approve MOD-016-0, then MOD-017-
0 will refer to an unapproved standard.
    1240. Although MidAmerican does not oppose the Commission's 
proposal regarding reporting of temperature and humidity along with 
peak loads, it finds it of only limited value. MidAmerican notes that 
there are typically other explanatory variables, such as economic 
variables, that are needed to understand the relationship between 
system load and temperature and humidity. In addition, the relationship 
and the importance of temperatures are different for every utility, 
which limits the effectiveness of standardization. FirstEnergy suggests 
that NERC should allow for a transition period for entities that 
currently do not track temperature and humidity along with peak load.
    1241. Xcel states that in many areas of the country, humidity is 
not a weather-indicator for peak load. Xcel therefore suggests that 
instead of including a reporting requirement for humidity, the standard 
be revised to include a more generic term, such as ``peak producing 
weather conditions.'' Alcoa requests that the Commission clarify that 
these requirements would only apply to load that varies with 
temperature and humidity.\359\
---------------------------------------------------------------------------

    \359\ Alcoa states that because its smelting load (the vast 
majority of its load) does not vary in accordance with temperature 
and humidity, comparing Alcoa's load forecasts to actual loads 
taking this information into account would be burdensome without 
being useful.
---------------------------------------------------------------------------

    1242. Regarding the Commission's proposal for reporting of the 
accuracy, error and bias of load forecasts compared to actual loads 
while taking temperature and humidity variations into account, APPA 
disagrees that the Commission should direct NERC to modify MOD-017-0 to 
include these requirements. APPA argues that requiring the type and 
granularity of forecast information and data the Commission proposes 
would not necessarily increase the reliability of load forecasts. APPA 
believes that it should be up to NERC, as the expert standards-setting 
entity, to decide whether such information would yield enough useful 
data to make it worth mandating.
    1243. TAPS is concerned that the NOPR's recommendation for 
reporting the accuracy, error and bias of load forecasts compared to 
actual loads may be interpreted to mean that measuring compliance is a 
function of forecast accuracy. TAPS contends that reliance on 
percentage-based deviations as a measurement of compliance is 
inappropriate when applied to very small entities because an error that 
in absolute terms is too small to affect the Bulk-Power System might be 
a significant percentage of the entity's load.
    1244. EEI notes that the direction of the NOPR proposal seems to 
suggest an expansion of the current reporting processes required under 
the Energy Information Administration section 411 process. EEI suggests 
that such a proposal should consider whether the section 411 process 
itself requires change or provides for an adequate level of reporting, 
and the extent to which an explicit NERC process requirement could 
distract or confuse industry participants.
    1245. FirstEnergy states that the transmission planner should be 
added to the list of applicable entities for this standard. FirstEnergy 
also states that it may be reasonable to interpret or apply this 
Reliability Standard in a manner to permit an affected entity that is a 
subsidiary in a utility holding company corporate structure to satisfy 
its

[[Page 16536]]

reporting requirements by means of a corporate affiliate. Adopting this 
interpretation or application would promote efficiency and decrease 
confusion in circumstances where several utility subsidiaries in the 
same corporate family are subject to this Reliability Standard.
    1246. MISO recommends that the Commission direct NERC to change the 
requirement of this standard so that aggregated actual hourly demand 
data (at the balancing authority level) are to be provided within 30 
calendar days of a request from NERC. MISO believes that load 
aggregated at this level should be sufficient for the modeling 
activities associated with system reliability. MISO understands that 
hourly data is collected by those utilities that have balancing 
authority responsibilities, and that these utilities can report 
aggregated hourly loads for their responsibility area within 30 days. 
MISO notes that some balancing authority utilities provide energy 
services to smaller municipal or distribution cooperative utilities 
where the metering system records only the peak demand and total energy 
supplied over approximately 30 days. MISO cautions that the balancing 
authority will usually have hourly data for demand and energy within a 
segment of the network, but may have no hourly metering on a specific 
customer served by that segment.
ii. Commission Determination
    1247. The Commission approves MOD-017-0 as mandatory and 
enforceable. In addition, the Commission directs the ERO to modify MOD-
017-0 as discussed below.
    1248. As an initial matter, we disagree that MOD-017-0 cannot be 
implemented because it is dependent on MOD-016-0, which further depends 
on various unapproved standards. As previously stated, we direct the 
ERO to provide a Work Plan and compliance filing regarding the 
collection of information specified under standards that are deferred, 
and believe there should be no difficulty complying with this 
Reliability Standard. We reiterate that ongoing collection of data is 
necessary to maintain system reliability, and approval of MOD-017-0 
will help achieve this goal.
    1249. As a general matter, the Commission is required to insure 
that the Reliability Standards are sufficient to adequately protect 
Bulk-Power System reliability.\360\ One of the main drivers in 
achieving Reliable Operation is to accurately predict the firm 
transactions and native load that must be served. Understanding the 
accuracy, error and bias of the forecast and taking action to minimize 
them would improve the Reliability Standards and achieve the goal.
---------------------------------------------------------------------------

    \360\ Order No. 672 at P 329.
---------------------------------------------------------------------------

    1250. The Commission also directs the ERO to modify the Reliability 
Standad to require reporting of temperature and humidity along with 
peak load because actual load must be weather normalized for meaningful 
comparison with forecasted values.\361\ In response to MidAmerican's 
observation that it sees little value in collecting this data, we 
believe that collecting it will allow all load data to be weather-
normalized, which will provide greater confidence when comparing data 
accuracy, which ultimately will enhance reliability. As a result, we 
reject Xcel's proposal that the standard be revised to include only the 
generic term ``peak producing weather conditions'' because it is too 
generic for a mandatory Reliability Standard.
---------------------------------------------------------------------------

    \361\ See Brattle Group Report on PJM Load Forecast Model, 
available at http://www.pjm.com/planning/res-adequacy/load-forecast.html.
---------------------------------------------------------------------------

    1251. We also reject Alcoa's proposal that the reporting of 
temperature and humidity along with peak loads should apply only to 
load that varies with temperature and humidity because it essentially 
is a request for an exemption from the requirements of the Reliability 
Standard and should therefore be directed to the ERO as part of the 
Reliability Standards development process. We agree, however, with APPA 
that certain types of load are not sensitive to temperature and 
humidity. We therefore find that the ERO should address Alcoa's 
concerns in its Reliability Standards development process.
    1252. The Commission adopts the NOPR proposal directing the ERO to 
modify the Reliability Standard to require reporting of the accuracy, 
error and bias of load forecasts compared to actual loads with due 
regard to temperature and humidity variations. This requirement will 
measure the closeness of the load forecast to the actual value. We 
understand that load forecasting is a primary factor in achieving 
Reliable Operation. Underestimating load growth can result in 
insufficient or inadequate generation and transmission facilities, 
causing unreliability in real-time operations. Measuring the accuracy, 
error and bias of load forecasts is important information for system 
planners to include in their studies, and also improves load forecasts 
themselves.
    1253. The Commission agrees with APPA that accuracy, error and bias 
of load forecasts alone will not increase the reliability of load 
forecasts, and, as a result, will not affect system reliability. 
Understanding of the differences without action based on that 
understanding would not change anything. Therefore, we direct the ERO 
to add a Requirement that addresses correcting forecasts based on prior 
inaccuracies, errors and bias.
    1254. Regarding TAPS's concern that accuracy of reporting may be 
used as a compliance Measure, we clarify that the compliance Measures 
for this Reliability Standard do not measure accuracy as a compliance 
Measure. Any change in the Measures would be arrived at in the 
Reliability Standards development process.
    1255. The Commission acknowledges EEI's concern that a requirement 
for additional information may impose an expansion of existing Energy 
Information Administration section 411 reporting requirements.\362\ We 
believe, however, that the ERO can ensure that the additional reporting 
of temperature and humidity along with peak loads does not conflict 
with or jeopardize the Energy Information Administration section 411 
reporting process.
---------------------------------------------------------------------------

    \362\ Form EIA-411, ``Coordinated Bulk Power Supply Program 
Report'' collects information about regional electric supply and 
demand projections for a five-year advance period as well as 
information on the transmission system and supporting facilities. 
See http://www.eia.doe.gov/cneaf/electricity/page/forms.html.
---------------------------------------------------------------------------

    1256. We agree with FirstEnergy that transmission planners should 
be added as reporting entities, and direct the ERO to modify the 
standard accordingly. We agree that in the NERC Functional Model, the 
transmission planner is responsible for collecting system modeling data 
including actual and forecast demands to evaluate transmission 
expansion plans.
    1257. The Commission disagrees in general with MISO's 
recommendation to allow some exceptions to the requirement to provide 
hourly demand data. However, the metering for some customer classes may 
not be designed to provide certain types of data. The Commission 
therefore directs the ERO to consider MISO's concerns in the 
Reliability Standards development process.
    1258. The Commission approves Reliability Standard MOD-017-0 as 
mandatory and enforceable. In addition, the Commission directs the ERO 
to develop a modification to MOD-017-0 through the Reliability 
Standards development process that includes requirements for: (1) 
Reporting of temperature and humidity along with the peak loads; (2) 
reporting of accuracy,

[[Page 16537]]

error and bias of load forecasts compared to actual loads taking 
temperature and humidity variations into account; (3) addressing 
methods to correct forecasts to minimize prior inaccuracies, errors and 
bias and (4) including the transmission planner in the applicability 
section.
t. Treatment of Nonmember Demand Data and Uncertainties in the 
Forecasts of Demand and Energy for Load (MOD-018-0)
    1259. The purpose of MOD-018-0 is to ensure that past and 
forecasted demand data are available for past event validation and 
future system assessment. MOD-018-0 requires LSEs, planning 
authorities, transmission planners and resource planners to submit load 
data reports that: (1) Indicate whether the demand data includes the 
regional reliability organization's non-members' demands and (2) 
addresses how assumptions, methods and uncertainties are treated.
    1260. In the NOPR, the Commission proposed to approve MOD-018-0 as 
mandatory and enforceable.
i. Comments
    1261. APPA agrees that MOD-018-0 is sufficient for approval as a 
mandatory and enforceable reliability standard.
    1262. In contrast to APPA, ISO/RTO Council and ISO-NE view MOD-018-
0 as dependent upon fill-in-the-blank NERC standards, and as such, 
argue that the Commission should refrain from approving the Reliability 
Standard at this time. ISO-NE states that approval of this standard 
would create dependency of MOD-018-0 on other unapproved standards. 
Consequently, ISO-NE contends that MOD-018-0 cannot be effectively 
implemented.
    1263. TAPS reiterates a similar concern it expressed with regard to 
MOD-017-0. TAPS notes that uncertainty in a small entity's forecast is 
insignificant. TAPS recommends that load forecast uncertainty should be 
addressed at an aggregate level on a regional basis (as is often done 
in the establishment of reserve obligations).
ii. Commission Determination
    1264. The Commission approves MOD-018-0 as mandatory and 
enforceable.
    1265. As an initial matter, we disagree that MOD-018-0 cannot be 
implemented because it is dependent on various unapproved standards. As 
previously stated, we direct the ERO to provide a Work Plan and 
compliance filing regarding the collection of information specified for 
standards that are deferred, and believe there should be no 
difficulties complying with this Reliability Standard. We reiterate 
that ongoing collection of data is necessary to maintain system 
reliability, and approval of MOD-018-0 will help to achieve this goal.
    1266. Regarding TAPS's concern that small entities should not be 
required to comply with MOD-018-0 because their forecasts are not 
significant for system reliability purposes, the Commission directs the 
ERO to address this matter in the Reliability Standards development 
process.
u. Reporting of Interruptible Demands and Direct Control Load 
Management (MOD-019-0)
    1267. The purpose of MOD-019-0 is to ensure that past and 
forecasted demand data is available for past event validation and 
future system assessment. The Reliability Standard requires that LSEs, 
planning authorities, transmission planners and resource planners 
annually provide their forecasts of interruptible demands and direct 
control load management to NERC, the regional reliability organization 
and other entities as specified in MOD-016-1, Requirement R1. The data 
should contain the forecasts for at least five years, and up to ten 
years.
    1268. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-019-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-019-
0 that includes new requirements for reporting of the accuracy, error 
and bias of controllable load \363\ forecasts.
---------------------------------------------------------------------------

    \363\ While MOD-019-0 and MOD-020-0 use two separate terms, 
interruptible load and direct control load management, the NOPR uses 
``controllable load'' to refer to both of them.
---------------------------------------------------------------------------

i. Comments
    1269. APPA agrees that MOD-019-0 should be approved as mandatory 
and enforceable. However, APPA states that the proper entity to decide 
whether the recommended changes to the standards should be made is 
NERC, through Reliability Standards development process.
    1270. The ISO/RTO Council and ISO-NE note that MOD-019-0 is 
dependent, through MOD-016, on various unapproved standards. 
Consequently, they contend that MOD-019-0 cannot be effectively 
implemented.
    1271. APPA proposes that NERC consider modifying MOD-019-0 to 
include new requirements for reporting on the accuracy, error and bias 
of controllable load forecasts. APPA further believes that NERC should 
consider adding requirements that would require resource planners to 
analyze differences between actual and forecasted demands for the five 
years of actual controllable load required in MOD-019-0 and identify 
what corrective actions were taken to improve controllable load 
forecasting for the 10-year planning horizon.
    1272. EEI and FirstEnergy state that determining the precise 
availability and capability of direct load control is a difficult 
management and customer relations exercise, and therefore, this 
requirement should not be included in the Reliability Standard. EEI 
states that, unlike other technical requirements for generation 
resources to be tested for various capabilities and limits under 
different types of stresses, there are no similar requirements for load 
control equipment. Elsewhere in these comments, EEI supports explicit 
recognition that load control should be recognized on the same terms as 
generation resources for setting reserve requirements. However, EEI 
cautions against imposing requirements to verify load control devices 
and interruptible loads, because the practical complexities of 
conducting such testing and verification, including customer 
notification, the need to plan, manage, and coordinate testing with 
critical commercial and industrial customer activities, and the need to 
conduct such tests at times of peak load, make this an extremely 
difficult operational challenge.
    1273. International Transmission notes that many load control 
applications are not individually metered, which means impact can only 
be estimated within a LSE's service territory. International 
Transmission believes that accurate reporting may not be feasible.
    1274. TAPS raises concern that the Commission's recommendation in 
the NOPR may be interpreted to make forecast accuracy a component of 
Reliability Standards compliance. TAPS cautions that reliance on 
percentage-based deviations as a measurement of compliance is 
inappropriate when applied to very small entities because an error that 
in absolute terms is too small to affect the Bulk-Power System might be 
a significant percentage of the entity's load. The percentage deviation 
from a forecasted peak of a small (e.g., 10 MW) entity will almost 
always be significantly higher than the percentage deviation of a large 
(more than 10,000 MW) entity, but the smaller system's deviation will 
have little if any impact on the bulk transmission system. In other 
contexts, the Commission has recognized that reliance solely on

[[Page 16538]]

percentage deviations as compliance measures can produce discriminatory 
results, and has applied MW minimums to minimize the discrimination 
that would otherwise result.
ii. Commission Determination
    1275. The Commission approves MOD-019-0 as mandatory and 
enforceable. In addition, the Commission directs the ERO to modify MOD-
019-0 as discussed below.
    1276. As an initial matter, we disagree that MOD-019-0 cannot be 
implemented because it is dependent on MOD-016-0, which further depends 
on various unapproved standards. As previously stated, we direct the 
ERO to provide a Work Plan and compliance filing regarding the 
collection of information specified under related standards that are 
deferred, and believe there should be no difficulties complying with 
this Reliability Standard. We reiterate that ongoing collection of data 
is necessary to maintain system reliability, and approval of MOD-019-0 
will help to achieve this goal. We therefore direct the ERO to use its 
authority pursuant to Sec.  39.2(d) of our regulations to require 
users, owners and operators to provide to the Regional Entity 
information related to forecasts of interruptible demands and direct 
control load management.
    1277. The Commission adopts the NOPR proposal directing the ERO to 
modify this standard to require reporting of the accuracy, error and 
bias of controllable load forecasts. This requirement will enable 
planners to get a more reliable picture of the amount of controllable 
load that is actually available, therefore allowing planners to conduct 
more accurate system reliability assessments. The Commission finds that 
controllable load can be as reliable as other resources, and therefore 
should also be subject to the same reporting requirements. Although we 
recognize that verifying load control devices and interruptible loads 
may be complex, we do not believe that it is overly so. Further, we 
believe that the ERO, through its Reliability Standards development 
process can develop innovative solutions to the Commission's concern. 
We also note that EEI is concerned about such testing at times of peak 
load. We clarify that we are not requiring the testing to be conducted 
at peak load conditions. Consequently, we reject the proposals of EEI, 
FirstEnergy and International Transmission to discard the requirement 
for reporting of the accuracy, error and bias of controllable load 
forecasts.
    1278. We direct the ERO to include APPA's proposal in the 
Reliability Standards development process to add a new requirement to 
MOD-019-0 that would oblige resource planners to analyze differences 
between actual and forecasted demands for the five years of actual 
controllable load and identify what corrective actions should be taken 
to improve controllable load forecasting for the 10-year planning 
horizon.
    1279. Regarding TAPS' concern that reporting accuracy could be used 
as a compliance Measure, we clarify that compliance Measures for this 
Reliability Standard do not include accuracy as a compliance measure. 
Any change in this policy would be arrived at in the ERO Reliability 
Standards development process.
    1280. Accordingly, the Commission approves MOD-019-0 as mandatory 
and enforceable. In addition, the Commission directs the ERO to develop 
a modification to MOD-019-0 through the Reliability Standards 
development process to require: (1) Reporting of the accuracy, error 
and bias of controllable load forecasts and (2) analyzing differences 
between actual and forecasted demands for the five years of actual 
controllable load and identify what corrective actions should be taken 
to improve controllable load forecasting for the 10-year planning 
horizon.
v. Providing Interruptible Demand and Direct Control Load Management 
Data to System Operators and Reliability Coordinators (MOD-020-0)
    1281. The purpose of MOD-020-0 is to ensure that past and 
forecasted demand data are available for validation of past events and 
future system assessment. The Reliability Standard requires that each 
LSE, planning authority, transmission planner and resource planner 
identify its amount of: (1) Interruptible demand and (2) direct control 
load management to transmission operators, balancing authorities and 
reliability coordinators upon request.
    1282. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-020-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-020-
0 that includes a new requirement concerning the reporting of the 
accuracy, error and bias of controllable load forecasts in its 
Reliability Standards development process.
i. Comments
    1283. APPA supports approval of MOD-020-0 as mandatory and 
enforceable, as proposed by the Commission. APPA does not oppose NERC's 
consideration of possible changes to MOD-020-0 regarding the reporting 
of the accuracy, error and bias of controllable load forecasts.
    1284. EEI and FirstEnergy state that for practical reasons, 
determining the precise availability and capability of direct load 
control is a difficult management and customer relations exercise. 
Unlike other technical requirements for generation resources to be 
tested for various capabilities and limits under different types of 
stresses, there are no similar requirements for load control equipment. 
The practical complexities of conducting such testing and verification, 
including customer notification, the need to plan, manage and 
coordinate testing with critical commercial and industrial customer 
activities, and the need to conduct such tests at times of peak load 
make this an extremely difficult operational challenge.
    1285. LPPC opposes the Commission's proposal for modification to 
report the accuracy of load forecasts. LPPC points out that load 
reduction forecasts are imprecise by nature, and, consequently, some 
utilities do not undertake them. LPPC also notes that interruptible 
loads are often on one-year contracts and, in some regions, instances 
of entities actually exercising load reduction are rare; in these 
areas, system operators often do not separately forecast interruptible 
load reductions, and reporting on the accuracy of forecasts on 
interruptible load reductions, even if interruptible load forecasts 
were done, is of little value. LPPC states that in other areas, such as 
New York, interruptible load reductions are more predictable, because 
many large loads have signed interruptible load contracts and have a 
history of exercising load reductions. LPPC notes that system operators 
in areas similar to New York have sufficient data so that forecasting 
for interruptible loads is a useful exercise, and as a result, a 
requirement to report on the accuracy of forecasts in these regions 
would be of some value, but not elsewhere. Consequently, LPPC 
recommends that the requirement should be region-specific and should 
only apply to entities that separately forecast interruptible loads. 
LPPC further notes that energy efficiency programs are often built into 
the larger assumptions in the forecast and are not separately 
forecasted.
    1286. TAPS is concerned that the Commission's recommendation in the 
NOPR may be interpreted to make forecast accuracy a component of 
Reliability Standards compliance.

[[Page 16539]]

However, it asserts that reliance on percentage-based deviations as a 
measurement of compliance is inappropriate when applied to very small 
entities because an error that in absolute terms is too small to affect 
the Bulk-Power System might be a significant percentage of the entity's 
load. The percentage deviation from a forecasted peak of a small (e.g., 
10 MW) entity will almost always be significantly higher than the 
percentage deviation of a large (more than 10,000 MW) entity, but the 
smaller system's deviation will have little if any impact on the bulk 
transmission system. In other contexts, the Commission has recognized 
that reliance solely on percentage deviations as a compliance measure 
can produce discriminatory results, and has applied MW minimums to 
minimize the discrimination that would otherwise result.
ii. Commission Determination
    1287. The Commission approves MOD-020-0 as mandatory and 
enforceable. In addition, the Commission directs the ERO to modify MOD-
020-0 as discussed below.
    1288. We adopt the proposal to direct the addition of a requirement 
for reporting of the accuracy, error and bias of controllable load 
forecasts because we believe that reporting of this information will 
provide applicable entities with advanced knowledge about the exact 
amount of available controllable load, which will improve the accuracy 
of system reliability assessments. The Commission finds that 
controllable load in some cases may be as reliable as other resources 
and therefore must also be subject to the same reporting requirements. 
We recognize that determining the precise availability and capability 
of direct load control is a difficult management and customer relations 
exercise, but we do not believe that it will be overly so. Further, we 
believe that the ERO, through its Reliability Standards development 
process can develop innovative solutions to the Commission's concern. 
Regarding LPPC's suggestion that this requirement should be region-
specific and should only apply to entities that separately forecast 
interruptible loads, we note that if a region does not forecast 
interruptible loads, this Reliability Standard does not apply.
    1289. Regarding TAPS' concern that forecast accuracy may be 
interpreted as a component of Reliability Standards compliance, we 
clarify that compliance Measures for this Reliability Standard do not 
measure accuracy as a compliance measure. Any change in this policy 
would be arrived at in the ERO Reliability Standards development 
process.
    1290. The Commission approves Reliability Standard MOD-020-0 as 
mandatory and enforceable and directs the ERO to develop a modification 
to MOD-020-0 through the Reliability Standards development process to 
require reporting of the accuracy, error and bias of controllable load 
forecasts.
w. Documentation of the Accounting Methodology for the Effects of 
Controllable Demand-Side Management in Demand and Energy Forecasts 
(MOD-021-0)
    1291. MOD-021-0 requires LSEs, transmission planners and resource 
planners to clearly document how each addresses the demand and energy 
effects of DSM programs. The standard also requires an applicable 
entity to include information detailing how DSM measures are addressed 
in the forecasts of its peak demand and annual net energy for load in 
the data reporting procedures of MOD-016-0, Requirement R1.
    1292. In the NOPR, the Commission proposed to approve Reliability 
Standard MOD-021-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to MOD-021-
0 that: (1) Includes a requirement standardizing principles on 
reporting and validation of DSM program information and (2) modifies 
the title and purpose statement to remove the word ``controllable.''
i. Comments
    1293. APPA supports the Commission's approval of MOD-021-0 as 
mandatory and enforceable.
    1294. In contrast, ISO-NE and ISO/RTO Council oppose adoption of 
this standard by the Commission. ISO-NE argues that the LSE, 
transmission planner and resource planner should each include 
information regarding how DSM measures are addressed in the forecasts 
of its peak demand and annual net energy for load in the data reporting 
procedures of MOD-016-0 R1. Therefore, they contend that, because MOD-
016-0 is dependent on various unapproved Reliability Standards, MOD-
021-0 is also dependent on unapproved Reliability Standards. 
Consequently, ISO-NE contends that MOD-021-0 cannot be effectively 
implemented.
    1295. FirstEnergy and SMA support the Commission's proposal to 
require consistent and uniform methods for reporting and validating 
demand-side information. SMA notes that this will provide more 
consistent and uniform evaluation of demand response data to facilitate 
system operator confidence in relying on such resources for various 
reliability purposes. In addition, APPA believes that NERC should 
consider adding requirements to MOD-021-0 that would provide 
information to allow resource planners to analyze the causes of 
differences between actual and forecasted demands, and to identify any 
corrective actions that should be taken to improve forecasted demand 
responses for future forecasts. APPA believes that all of these 
proposals should be submitted to NERC as the standards-setting body 
with technical expertise, and vetted through its Reliability Standards 
development process, rather than being imposed by Commission fiat.
    1296. FirstEnergy adds that MOD-019-0, MOD-020-0 and MOD-021-0 
should be combined because they all address load forecast inputs, and 
that combining these standards will eliminate any inconsistencies and 
make compliance easier and more efficient.
ii. Commission Determination
    1297. The Commission approves MOD-021-0 as mandatory and 
enforceable. In addition, the Commission directs the ERO to develop a 
modification to MOD-021-0 through the Reliability Standards development 
process as discussed below.
    1298. As an initial matter, we disagree that MOD-021-0 cannot be 
implemented because it is based on MOD-016-0, and through it on various 
unapproved standards, which creates an implementation problem. As 
previously stated, we direct the ERO to provide a Work Plan and 
compliance filing regarding collection of information specified under 
related standards that are deferred, and believe there should be no 
difficulty complying with this Reliability Standard. We reiterate that 
ongoing collection of data is necessary to maintain system reliability, 
and approval of MOD-21-0 will help to achieve this goal. Therefore, we 
direct the ERO to use its authority pursuant to Sec.  39.2(d) of our 
regulations to require users, owners and operators to provide to the 
Regional Entity the information required by this Reliability Standard.
    1299. We agree with FirstEnergy and SMA that standardization of 
principles on reporting and validating DSM program information will 
provide consistent and uniform evaluation of demand response to 
facilitate system operator confidence in relying on such resources, 
which will further increase accuracy of transmission system reliability 
assessment and consequently

[[Page 16540]]

enhance overall reliability. We direct the ERO to modify this 
Reliability Standard to allow resource planners to analyze the causes 
of differences between actual and forecasted demands, and to identify 
any corrective actions that should be taken to improve forecasted 
demand responses for future forecasts. Therefore, we adopt the NOPR 
proposal and direct the ERO to modify MOD-021-0 by adding a requirement 
for standardization of principles on reporting and validating DSM 
program information.
    1300. With respect to FirstEnergy's suggestion to combine MOD-019-
0, MOD-020-0 and MOD-021-0, we understand that the ERO intends to 
consolidate Reliability Standards and encourage FirstEnergy to make its 
suggestion in the Reliability Standards development process.
    1301. The Commission directs the ERO to modify the title and 
purpose statement to remove the word ``controllable.'' We note that no 
commenter disagrees.
    1302. The Commission approves Reliability Standard MOD-021-0 as 
mandatory and enforceable. We direct the ERO to develop a modification 
to MOD-021-0 through the Reliability Standards development process to 
(1) add a Requirement standardizing principles on reporting and 
validation of DSM program information; (2) allow resource planners to 
analyze the causes of differences between actual and forecasted 
demands, and to identify any corrective actions that should be taken to 
improve forecasted demand responses for future forecasts and (3) modify 
the title and purpose statement to remove the word ``controllable.''
x. Verification of Generator Gross and Net Real Power Capability (MOD-
024-1)
    1303. The purpose of MOD-024-1 is to ensure that accurate 
information on generation gross and net real power capability is used 
for reliability assessments. The Reliability Standard requires the 
regional reliability organization to establish and maintain procedures 
to address verification of generator gross and net real power 
capability. It also requires a generator owner to follow its regional 
reliability organization's procedure for verifying and reporting gross 
and net real power generating capability.
    1304. In the NOPR, the Commission identified MOD-024-1 as a fill-
in-the-blank standard that requires the regional reliability 
organization to establish and maintain procedures to address 
verification of generator gross and net real power capability. The 
Commission stated that because the regional procedures had not been 
submitted, it would not propose to approve or remand MOD-024-1 until 
the ERO submits the additional information. In addition, the Commission 
expressed concern that the Reliability Standard is not sufficiently 
clear because it does not define test conditions, e.g., ambient 
temperature, river water temperature or methodologies for calculating 
de-rating factors for conditions such as higher ambient temperatures 
than the test temperature. Further, the NOPR stated that Requirement R2 
provides that the ``regional reliability organization shall provide 
generator gross and net real power capability verification within 30 
calendar days of approval'' and noted that it is not clear what 
approval is required and when the 30-day period starts.
i. Comments
    1305. APPA agrees that MOD-024-1 is a fill-in-the-blank standard, 
is not sufficient as currently drafted, and should not be approved as a 
mandatory Reliability Standard until NERC and the regional reliability 
organizations/Regional Entities develop the necessary regional 
methodologies and the Commission approves them.
    1306. APPA also states that the results of field-testing will 
enable NERC to refine this Reliability Standard in an appropriate 
manner. APPA further believes that NERC should consider modifying this 
Reliability Standard to provide requirements for this information on an 
Interconnection-wide basis, in the same manner that IRO-006-2 sets the 
requirement for transmission loading relief in each Interconnection.
    1307. Northern Indiana urges the Commission to reconsider the 
proposed changes at this time in favor of continuation of the 
currently-effective Reliability Standard. Northern Indiana states that 
the NOPR's suggestion that there should be greater specificity and 
definition of test conditions could potentially create reliability 
issues, rather than protect against them. Northern Indiana explains 
that certain types of testing, and their preparation, can be 
accomplished more quickly than others, with test duration varying from 
several minutes to several days.\364\ The problem is compounded if a 
test takes some time to complete, and all neighboring generating owners 
were required to comply at the same time. The end result would be a 
lack of regulating capability in a region.
---------------------------------------------------------------------------

    \364\ Northern Indiana states that the longer the duration, the 
more stressed the units--and the system--during these testing 
intervals. For example, Commission staff recommends the use of 
ambient air temperature and river water temperature as triggering 
tests to verify generator gross and net real power capability. 
However, temperature-driven test triggers would result in several 
neighboring systems in the same region undergoing tests at the same 
time in order to meet the test criteria. For example, a temperature 
trigger of 90 degrees Fahrenheit for a net demonstrated capacity 
test could result in all neighboring generating owners taking their 
units off of automatic generator control to reach maximum net 
demonstrated capacity for the test. By taking units off automatic 
generator control, the generating owners' regulating capabilities 
are lost.
---------------------------------------------------------------------------

    1308. Constellation encourages the Commission and NERC to take 
extra care in distinguishing between those requirements in each 
Reliability Standard that are core requirements as opposed to 
supporting information, explanatory statements or administrative 
processes. For example, Constellation points out that in MOD-024-1, 
NERC proposes that a verification process be made into a Reliability 
Standard with full enforceability. Although Constellation agrees that 
the verification process spelled out in this Reliability Standard is 
important and should be performed by the industry, the Reliability 
Standard, alone, exclusively provides for an administrative process 
and, therefore, if not strictly complied with, does not necessarily 
foreshadow an immediate, real-time reliability problem on the bulk 
electric system. Constellation is concerned that the Levels of Non-
Compliance associated with MOD-024-1 and MOD-025-1 are based on 
arbitrary percentages that have little to do with the impact a failure 
to perform would have on reliability. Constellation believes that these 
problems ultimately will reduce the effectiveness of the Reliability 
Standards. Consequently, Constellation requests that the Commission 
recognize these concerns and direct NERC to take them into 
consideration during the Reliability Standards development process.
ii. Commission Determination
    1309. The Commission will not approve or remand MOD-024-1 until the 
ERO submits additional information. In order to continue verifying and 
reporting gross and net real power generating capability needed for 
reliability assessment and future plans, we direct the ERO to develop a 
Work Plan and submit a compliance filing.
    1310. The Commission remains concerned that the Reliability 
Standard is not sufficiently clear because it does not define the test 
conditions and methodologies for calculating de-rating

[[Page 16541]]

factors. The Commission does not agree with APPA that NERC should 
consider modifying this Reliability Standard to provide requirements 
for this information on an Interconnection-wide basis, in the same 
manner that IRO-006-3 sets the requirements for transmission loading 
relief in each Interconnection. We believe, however, that while the 
overall methodology for verification of generator gross and net real 
power capability should be the same, test conditions (such as ambient 
temperature, river water temperature, etc.) can vary.
    1311. In the NOPR, the Commission stated that the Reliability 
Standard could be improved by defining test conditions, e.g., ambient 
temperature, river water temperature, and methodologies for calculating 
de-rating factors for conditions such as higher ambient temperatures 
than the test temperature. With the test information and methodologies, 
the generator output that can be expected to be available at forecasted 
weather conditions can be determined. The Commission agrees with 
Northern Indiana that testing all units at the same time is not 
feasible. However, the Commission did not propose simultaneous testing. 
Rather, we direct the ERO to develop appropriate requirements to 
document test conditions and the relationships between test conditions 
and generator output so that the amount of power that can be expected 
to be delivered from a generator at different conditions, such as peak 
summer conditions, can be determined. Similarly, we respond to 
Constellation that any modification of the Levels of Non-Compliance in 
this Reliability Standard should be reviewed in the ERO Reliability 
Standards development process.
    1312. We repeat our concern that Requirement R2, which specifies 
that the ``regional reliability organization shall provide generator 
gross and net real power capability verification within 30 calendar 
days of approval,'' is not clear. The requirement lacks a definition of 
what approval is required and when the 30-day period starts. Therefore, 
we direct the ERO to modify this Reliability Standard by adding 
information that will clarify this requirement.
    1313. The Commission neither accepts nor remands MOD-024-1 until 
the ERO submits additional information. Although the Commission did not 
propose any action with regard to MOD-024-1, it addressed above a 
number of concerns regarding the Reliability Standard. We therefore 
direct the ERO to use its authority pursuant to Sec.  39.2(d) of our 
regulations to require users, owners and operators to provide this 
information. In the interim, compliance with MOD-024-0 should continue 
on a voluntary basis, and the Commission considers compliance with it 
to be a matter of good utility practice.
y. Verification of Generator Gross and Net Reactive Power Capability 
(MOD-025-1)
    1314. MOD-025-1 requires the regional reliability organization to 
establish and maintain procedures to address verification of generator 
gross and net reactive power capability. The Reliability Standard also 
requires the regional reliability organization to provide its generator 
gross and net reactive power capability verification and reporting 
procedures, and any changes to those procedures, to the generator 
owners, generator operators, transmission operators, planning 
authorities and transmission planners affected by the procedure within 
30 calendar days of approval of the Reliability Standard.
    1315. In the NOPR, the Commission identified MOD-025-1 as a fill-
in-the-blank standard that requires the regional reliability 
organization to establish and maintain procedures to address 
verification of generator gross and net reactive power capability. The 
NOPR stated that because the regional procedures had not been 
submitted, the Commission would not propose to approve or remand MOD-
025-1 until the ERO submits the additional information. In addition, 
the Commission suggested that MOD-025-1 could be clearer by requiring a 
minimum reactive power (MVAR) capability throughout a unit's real power 
operating range. Further, the NOPR stated that requirement R2 provides 
that the ``regional reliability organizations shall provide generator 
gross and net real power capability verification within 30 calendar 
days of approval'' and noted that it is not clear what approval is 
required and when the 30-day period starts.
i. Comments
    1316. APPA agrees that the Commission should not approve this 
Reliability Standard until NERC and the regional reliability 
organizations/Regional Entities develop the necessary regional 
methodologies and the Commission approves them.
    1317. MidAmerican notes that the Reliability Standard will be 
clearer if minimum reactive power capability is required throughout a 
unit's real power operating range. However, making this a Requirement 
for existing units would be a hardship for units not built with the 
Requirement in mind. Therefore, MidAmerican suggests that any such 
requirement should allow existing units to be grandfathered in as they 
are currently rated so that a new minimum reactive power standard is 
only applicable to new generating units or units that are being 
significantly upgraded.
    1318. Northern Indiana cautions the Commission against the 
establishment of a minimum capability, because it could diminish a 
unit's ability to contribute to Interconnection reliability, and to 
maintain its own stability. Northern Indiana points out that all 
generators have reactive capability curves from design manufacturers, 
and these curves provide operators with a range that is considered by 
the manufacturer to be a safe operating limit. Northern Indiana 
contends that the continued use of reactive capability curves is 
superior to establishment of an MVAR capability, and that operators 
effectively use these curves to maintain unit stability, while also 
contributing to the reliability of the Interconnection. Northern 
Indiana believes that continued reliance on manufacturer reactive 
capability curves is a technically sound means to achieve the 
Reliability Standard's stated reliability goal in a manner superior to 
the establishment of MVAR capability.
    1319. Similarly to Northern Indiana, Wisconsin Electric encourages 
the Commission to withdraw this suggested modifications to NERC's 
Reliability Standard for several reasons. Wisconsin Electric believes 
that a requirement to test and verify the minimum reactive capability 
at multiple points over the operating range as part of the additional 
minimum MVAR capability requirement would be a significant and 
unnecessary burden on utilities. In Wisconsin Electric's experience, a 
reactive power test at a single operating point is sufficient and more 
practical to achieve.
    1320. SoCal Edison recommends that the Commission specifically 
state the effective date for compliance with each Reliability Standard 
in its Final Rule. SoCal Edison states that the effective date is 
critical and gives the example of MOD-025-1, with effective dates 
phased in over several years after they are adopted by the NERC board 
of trustees, and well after the date the Final Rule will be issued.
ii. Commission Determination
    1321. The Commission will not approve or remand MOD-025-1 until the 
ERO submits additional information. In order to continue verifying and 
reporting gross and net reactive power generating capability needed for 
reliability assessment and future plans,

[[Page 16542]]

we direct the ERO to develop a Work Plan as defined in the Common 
Issues section.
    1322. We disagree with commenters that verifying generator reactive 
capability is a particularly difficult issue. The capability of 
generators to produce reactive power is essential for real-time 
analysis and planning. The Reliability Standard addressing this issue 
requires a generator to verify reactive capability only at the unit's 
full MW loading. However, other than baseload units, most generating 
units rarely operate at full MW loading. It is unclear what reactive 
capability is available throughout a unit's real power (MW) operating 
range. Therefore, we believe a clearer standard would require a 
verification of MVAR capability throughout a unit's real power (MW) 
operating range. However, we share concern with several commenters that 
such a requirement for all generators may not be necessary. Therefore, 
we adjust the proposal in the NOPR and direct the ERO to modify MOD-
025-1 to require verification of reactive power capability at multiple 
points over a unit's operating range.
    1323. We maintain the concern we expressed in the NOPR that 
Requirement R2 provides that the ``regional reliability organization 
shall provide generator gross and net reactive power capability 
verification within 30 calendar days of approval'' and note that it is 
not clear what approval is required and when the 30-day period starts. 
We direct the ERO to provide clarification on this requirement.
    1324. The Commission neither accepts nor remands MOD-025-1 until 
the ERO submits additional information. Although the Commission did not 
propose any action with regard to MOD-025-1, it addresses above a 
number of concerns regarding the Reliability Standard. We direct the 
ERO to develop a Work Plan to verify and report on generator gross and 
net reactive power capability while this Reliability Standard is being 
modified and to modify this Reliability Standard through the 
Reliability Standards development process to: (1) Require verification 
of a reactive power capability at multiple points over a unit's 
operating range and (2) clarify Requirement R2 with a definition of 
what approval is needed and when the 30-day period starts.
9. PER: Personnel Performance, Training and Qualifications
    1325. The four proposed Personnel Performance, Training and 
Qualifications (PER) Reliability Standards are applicable to 
transmission operators, reliability coordinators and balancing 
authorities with the intention of ensuring the safe and reliable 
operation of the interconnected grid through the retention of suitably 
trained and qualified personnel in positions that can impact the 
reliable operation of the Bulk-Power System. The PER Reliability 
Standards address: (1) Operating personnel responsibility and 
authority; (2) operating personnel training; (3) operating personnel 
credentials and (4) reliability coordination staffing.
a. Operating Personnel Responsibility and Authority (PER-001-0)
    1326. PER-001-0 requires that transmission operator and balancing 
authority personnel have the responsibility and authority to direct 
actions in real-time. PER-001-0 also requires clear documentation that 
operating personnel have the responsibility and authority to implement 
real-time action to ensure the stable and reliable operation of the 
Bulk-Power System.
    1327. In the NOPR, the Commission proposed to approve PER-001-0 as 
mandatory and enforceable.
 i. Comments
    1328. APPA agrees that PER-001-0 is sufficient for approval as a 
mandatory and enforceable Reliability Standard.
    1329. ISO-NE supports the adoption of this Reliability Standard 
provided that the Commission does not mandate that the tasks performed 
by local control centers be included in the definition of transmission 
operators. It explains that to do so would suggest that the local 
control center has independent autonomy in operating the Bulk-Power 
System, which conflicts with the ``one set of hands on the wheel'' 
philosophy supported by Order No. 2000 and the operating agreements 
approved by the Commission to establish ISO-NE as New England's RTO.
ii. Commission Determination
    1330. The Commission agrees with the ``one set of hands on the 
wheel'' philosophy described by ISO-NE as it applies to operations of 
the Bulk-Power System and has no intention of deviating from it. 
Nothing in the Commission's proposed modifications outlined in the NOPR 
in regard to the PER Reliability Standards is intended to conflict with 
this philosophy. A generic discussion of the local control centers is 
included in the Applicability Issues section and specific implications 
to operator training are discussed in PER-002-0.\365\
---------------------------------------------------------------------------

    \365\ See Applicability Issues: Use of the NERC Functional 
Model, supra section II.C.4.
---------------------------------------------------------------------------

    1331. Accordingly, the Commission approves PER-001-0 as mandatory 
and enforceable. We find that the Reliability Standard is just, 
reasonable, not unduly discriminatory or preferential and in the public 
interest.
b. Operating Personnel Training (PER-002-0)
    1332. PER-002-0 requires that transmission operator and balancing 
authority personnel are adequately trained. The Reliability Standard: 
(1) Directs each transmission operator and balancing authority to have 
a training program for all operating personnel who occupy positions 
that either have primary responsibility, directly or indirectly, for 
the real-time operation of the Bulk-Power System or who are directly 
responsible for complying with the NERC Reliability Standards; (2) 
lists criteria that must be met by the training program and (3) 
requires that operating personnel receive at least five days of 
training in emergency operations each year using realistic simulations.
    1333. In the NOPR, the Commission proposed to approve Reliability 
Standard PER-002-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct that NERC submit a modification to PER-
002-0 that: (1) Identifies the expectations of the training for each 
job function; (2) develops training programs tailored to each job 
function with consideration of the individual training needs of the 
personnel; (3) expands the applicability to include reliability 
coordinators, generator operators, and operations planning and 
operations support staff with a direct impact on the reliable operation 
of the Bulk-Power System; (4) uses the Systematic Approach to Training 
(SAT) methodology in its development of new training programs and (5) 
includes performance metrics associated with the effectiveness of the 
training program. In addition, the Commission requested comments on the 
benefits and appropriateness of required ``hands-on'' training using 
simulators in dealing with system emergencies.
i. General Issues
(a) Comments
    1334. EEI supports the Commission's direction for personnel 
training and generally agrees with the Commission's proposal for PER-
002-0. EEI states NERC is developing a new Reliability Standard, PER-
005-0, which could be

[[Page 16543]]

filed with the Commission as early as July 2007. According to EEI, this 
new Reliability Standard will respond to the issues raised in the NOPR 
regarding PER-002-0. EEI notes that the ERO plans to retire Reliability 
Standards PER-002-0 and PER-004-1 when proposed PER-005-0 is adopted. 
It recommends that the Commission consider consolidating all training 
requirements into a single Reliability Standard to simplify the 
Reliability Standards catalog.
    1335. Additional comments received have been grouped as follows: 
Local control center personnel; applicability to generator operators; 
applicability to operations planning and operations support staff; 
implications to small systems; training performance metrics; use of SAT 
methodology; and use of simulators separately, followed by an overall 
conclusion and summary.
(b) Commission Determination
    1336. EEI's comments concerning a possible PER-005-0 are beyond the 
scope of this proceeding. The Commission will not require the ERO to 
consolidate all training requirements into a single Reliability 
Standard. We believe that such matters should be left to the discretion 
of the ERO through its Reliability Standards development process.
ii. Local Control Center Personnel
    1337. In the NOPR, the Commission noted that decisionmaking and 
implementation may be performed by separate groups in an ISO or RTO 
context, as well as other organizations that pool resources.\366\ The 
Commission proposed that all control centers and organizations that are 
necessary for the actual implementation of the decision or are needed 
for operation and maintenance made by the ISO, RTO or pooled resource 
organization should be part of the transmission or generator operator 
function. Although the NOPR discussed this matter in the context of the 
Communication (COM) Reliability Standards, the NOPR indicated that the 
proposal would apply in the training and certification context, as 
well.\367\
---------------------------------------------------------------------------

    \366\ NOPR at P 236-37.
    \367\ Id. at P 237, 779.
---------------------------------------------------------------------------

(a) Comments
    1338. EEI states that the term ``operating personnel'' as used in 
the PER group of Reliability Standards needs clarification because it 
may be interpreted to mean any person with a capability to take a 
unilateral action that can have a potentially significant effect on the 
Bulk-Power System. EEI states that the term is open to broad 
interpretation in actual practice, subject to various contracts, 
operating agreements and ISO/RTO procedures. It states, for example, a 
local control center operator may take instructions from and act on 
those instructions, whereas the ``transmission operator'' under the 
Functional Model may be viewed as a more centralized authority such as 
a larger regional system operator. EEI contends that some define local 
control center as a transmission operator, while others disagree.
    1339. ISO-NE states the scope of PER-002-0 need not be expanded 
because local control center personnel in its footprint implement tasks 
delegated to them by ISO-NE for operation of designated transmission 
facilities. NPCC argues that expanding PER-002-0 beyond the entities 
identified under the NERC Functional Model (i.e., transmission 
operators, reliability coordinators and balancing authorities) will 
require substantial cost and time but add little value. It states that 
there are no certification exams for any entities other than 
transmission operators, reliability coordinators and balancing 
authorities and to develop and implement such exams and to have the 
additional personnel certified would take several years. It also states 
that these personnel already function under the authority of NERC-
certified operators and act only at the direction of certified 
operators. It concludes that an entity that does not exercise 
operational authority should not be subject to the same requirements as 
the decisionmaker.
    1340. Northern Indiana states that it is not uncommon in the 
industry for employees who perform switching operations to be 
supervised by NERC-certified operators and that such employees are 
subject to round-the-clock review by, and communication with, their 
NERC-certified transmission operators. Similarly, SoCal Edison notes 
that large utilities can have operators strategically located 
throughout a vast service territory at switching centers with SCADA 
capability and that these operators follow the directives of one 
control center responsible for Bulk-Power System reliability. SoCal 
Edison disagrees that the operators of these switching centers, simply 
because the switching center has SCADA capability, must be NERC-
certified.
    1341. LPPC states that the training and certification requirements 
should apply only to transmission and generation personnel that are 
located in the transmission control center (i.e., responsible for real-
time Bulk-Power System operations). It argues that transmission and 
generation operation employees that are located in remote locations 
that are not directly involved in the real-time scheduling of 
transactions or Bulk-Power System monitoring and control do not need to 
be certified for real-time operations because they are not involved in 
the type of functions in which regimented training in the Reliability 
Standards would be useful. It suggests that a bright line should be 
drawn between the training of actual system operators and the training 
for operators of generation plants that are not responsible for 
scheduling. LPPC also states that the Commission should clarify the 
scope of training that the transmission control center real-time 
operations personnel should receive.
    1342. Entergy asserts that the training program should be tailored 
to the functions local control center operators, generator operators 
and operations planning staff perform that impact the reliable 
operation of the Bulk-Power System for both normal and emergency 
operations.
(b) Commission Determination
    1343. In our discussion above regarding the Functional Model, we 
emphasized our concern that there should be no unintentional gaps or 
redundancies in responsibility for compliance with the Requirements of 
Reliability Standards. This concern arises particularly in the context 
of RTOs, ISOs and other pooled resources that may have separate 
divisions performing decisionmaking functions and implementing 
functions within the transmission operator classification. The topic of 
training is one such area of concern. While PER-002-0 applies to 
transmission operators, it is important for reliability that personnel 
involved in both decisionmaking and implementation receive proper 
training.
    1344. Clearly, in a region where an RTO or ISO performs the 
transmission operator function, its personnel with primary 
responsibility for real-time operations must receive formal training 
pursuant to PER-002-0. In addition, personnel who are responsible for 
implementing instructions at a local control center also affect the 
reliability of the Bulk Power System. These entities may take 
independent action under certain circumstances, for example, to protect 
assets, personnel safety and during system restorations. Whether the 
RTO or the local control center is ultimately responsible for 
compliance is a separate issue addressed above, but regardless of which 
entity registers for that responsibility, these local control center

[[Page 16544]]

employees must receive formal training consistent with their roles, 
responsibilities and tasks. Thus, while we direct the ERO to develop 
modifications to PER-002-0 to include formal training for local control 
center personnel, that training should be tailored to the needs of the 
positions.
    1345. As noted by SoCal Edison, there are different operating 
structures and therefore there is a need to clarify to which control 
centers we direct the Reliability Standard apply. For example, for a 
large utility within an RTO or ISO footprint there may be one 
centrally-located control center whose function is to supervise several 
distributed control centers, each with remote monitoring and control 
capability. In this type of structure, the personnel of the centrally-
located control center should receive formal training in accordance 
with the Reliability Standard. Personnel at the distributed control 
centers also need to be trained, but the responsibility for this 
training is outside the scope of the Reliability Standard.\368\
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    \368\ The Commission expects the entity registered as the 
transmission operator to ensure that these personnel are competent 
for the tasks that they perform.
---------------------------------------------------------------------------

    1346. Another organizational structure, typically representative of 
relatively smaller entities, consists of a single control center that 
implements operating instructions from its transmission operator, e.g., 
an RTO, ISO or pooled resource. Similar to the discussion above, 
operators at these control centers also may take independent action to 
protect assets, safety and system restoration. Such control center 
personnel must also receive formal training pursuant to PER-002-0.
    1347. Consistent with the comments of SoCal Edison and Northern 
Indiana, the Commission understands that it is common practice to have 
traveling operators located in the local control centers who carry out 
field switching operations and station inspections at the direction of 
the local control center operators. These personnel are not involved 
with the transmission operator at the ISO or RTO or at organizations 
with pooled resources, and as such, should not be subject to 
Reliability Standard PER-002-0.
    1348. The Commission disagrees with those commenters who contend 
that, because operators at local control centers take direction from 
NERC-certified operators at the ISO or RTO, they do not need to be 
addressed by the training requirements of PER-002-0. Rather, as 
discussed above, these operators maintain authority to act 
independently to carry out tasks that require real-time operation of 
the Bulk-Power System including protecting assets, protecting personnel 
safety, adhering to regulatory requirements and establishing stable 
islands during system restoration.
    1349. Several commenters express concern about requiring local 
control center operators to become fully trained to the same extent as 
transmission operators, balancing authorities and reliability 
coordinators. This is not the Commission's intent. As we stated in the 
NOPR, the proposed modifications do not imply a ``one-size-fits-all'' 
approach but rather ensure the creation of training programs that are 
structured and tailored to the different functions and needs of the 
personnel involved.\369\ Therefore the Commission agrees with Entergy 
that the training program should be tailored to the functions local 
control center operators, generator operators and operations planning 
staff perform that impact the reliable operation of the Bulk-Power 
System for both normal and emergency operations.
---------------------------------------------------------------------------

    \369\ See NOPR at P 773, 775.
---------------------------------------------------------------------------

iii. Applicability to Generator Operators
    1350. The Commission proposed in the NOPR a modification to PER-
002-0 to include real-time operations personnel from reliability 
coordinators, generator operators, operations planning and operations 
support staff in training programs with a time-phased effective 
date.\370\
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    \370\ Id. at P 772.
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(a) Comments
    1351. PG&E and FirstEnergy support the Commission's goal of 
ensuring appropriate training for generator operators. FirstEnergy, 
however, believes that there is some confusion between the Functional 
Model and the Reliability Standard requirements concerning the 
generator operator classification. FirstEnergy explains that, in some 
contexts, ``generator operator'' refers to operations personnel who are 
centrally-located at a generation control center (i.e., fleet 
operators) while in other contexts it refers to generator operators 
located at the generation plant (i.e., unit operator). Further, 
according to FirstEnergy, the NERC glossary defines ``generator 
operator'' as the entity that operates generating unit(s) and performs 
the functions of supplying energy and interconnected operations 
services. FirstEnergy requests that the Commission direct NERC to 
revise the Reliability Standard to recognize this distinction.
    1352. Other commenters, including Xcel, California PUC and Entergy, 
state that the Reliability Standard should not apply to generator 
operators. Xcel argues that generator operators take their direction 
from transmission operators, balancing authorities and reliability 
coordinators, which limits their ability to exercise independent action 
impacting the reliability of the Bulk-Power System. Entergy argues that 
expanding the applicability to generator operators would provide little 
benefit to those personnel in the performance of their own functions, 
and could distract them from those functions. It also argues that such 
training would be extremely costly and would divert necessary resources 
from more important reliability objectives.
    1353. California PUC states that the requirement to include power 
plant operators in the applicability of this Reliability Standard 
exceeds anything contemplated in the regulation of the Bulk-Power 
System under previous NERC guidelines and what is authorized by 
statute. It contends that impacts of generator operator actions on the 
Bulk-Power System are of a much smaller magnitude and consequence than 
those of system operators. Further, it states that other authorities, 
such as balancing authorities and state governments, may have acted in 
regard to training of power plant operators and, therefore, the 
Commission should not act where other authorities have already done so. 
In a similar vein, the Nevada Companies state that the activities of 
generating station operations personnel are limited to the confines of 
the specific generating station. Knowledge of or exposure to 
interconnected grid operating principles is simply not applicable to 
the tasks normally performed at the generating stations.
    1354. Reliant states that the proposed modification fails to 
clarify how generator operators are to satisfy the training program 
requirement or the scope of generator operator personnel that must be 
trained. It states that the proposed modification could be interpreted 
to require generator operators to train the plant operator as well as 
the dispatcher in the generator operator's local control center. 
Reliant believes, however, that plant operators should not be subject 
to the Reliability Standard's training program requirement because 
personnel employed in plant operating positions are trained in the 
operation of plant equipment and take direction with respect to the 
operation of the plant from management personnel as well as from the 
local control center. Accordingly, it reasons that, because

[[Page 16545]]

these employees take direction with respect to plant operations from 
elsewhere, they do not have primary responsibility for the real-time 
operation of the Bulk-Power System and should not be responsible for 
complying with Reliability Standards. Reliant suggests that PER-002-0 
should specifically target generator operator personnel that develop 
dispatch instructions and the Reliability Standard should be modified 
to accommodate generator operator entities that are members of ISOs and 
RTOs with established NERC-approved certification programs. However, it 
should exclude those personnel who simply take direction on plant 
operations.
    1355. Dynegy, MISO and Wisconsin Electric state that these 
Reliability Standards should not be extended to all real-time operation 
positions of a generator operator. They state that many real-time 
operation positions are staffed by long-tenured union personnel who 
routinely operate generating units and take directions from a 
centralized generation control center or the local RTO/ISO. They 
analogize this type of certification and training requirement with 
requiring the outside field force of a transmission operator, including 
positions that operate and switch electric transmission lines pursuant 
to instructions from a centralized transmission control group, to be 
NERC-certified. Dynegy and MISO support a more limited extension of 
these Reliability Standards to real-time operation personnel located in 
a centralized generation control center that interfaces with the plants 
and the local RTO/ISO but not to personnel at the plant level.
    1356. Some commenters address the appropriate scope of training for 
generator operators. For example, MidAmerican states that experience 
and knowledge necessary for transmission operators may go well beyond 
what is needed for generation operations. It contends that a NERC-
approved training course specific to these functions would be an 
appropriate alternative. Entergy comments that, if training of 
generator operator personnel is required, it should focus on the 
functions generator operators must perform, not on the functions that 
others perform. SDG&E states that training for generator operators and 
others who may directly impact the reliable operations of the Bulk-
Power System need not be identical to or as extensive as that required 
of transmission system operators, but should be tailored in scope, 
contents and duration so as to be appropriate to the personnel and the 
object of promoting system reliability.
    1357. FirstEnergy states that there are no universal certification 
or training programs for generator operators; therefore a reasonable 
transition period should be established to allow time for generator 
operators to comply with this Reliability Standard. It also states that 
nuclear units are already subject to NRC training requirements and that 
compliance with NRC requirements should satisfy this Reliability 
Standard.
    1358. APPA, Process Electricity Committee and TAPS are concerned 
that, unless a size limitation is included for the generator operators, 
a substantial number of generator operator personnel will have to be 
enrolled in training programs. They argue that while a generator plays 
an important role in the reliable operations of the bulk electric 
system, the generator operator takes commands from the transmission 
operator, balancing authority or reliability coordinator. TAPS opposes 
the expanded applicability, especially in the case of small systems, 
because it believes that the requirement would be costly with no 
benefits to reliability.
    1359. Process Electricity Committee is concerned about the effect 
of the expanded requirements on end users who have on-site generation. 
It argues that the training requirements would present an added cost 
for end users with no apparent added benefit and that, in the long 
term, end users may be discouraged from developing on-site generation, 
which in turn would leave industrial electricity users more vulnerable 
to failures elsewhere on the energy grid.
(b) Commission Determination
    1360. The Commission explained in the NOPR that transmission 
operators and balancing authorities are not the only entities that have 
operating personnel in positions that directly impact the reliable 
operation of the Bulk-Power System; and included generator operators 
among those that have such an impact.\371\ Xcel and others oppose 
extending the applicability of PER-002-0 to generator operators, 
because they take directions from balancing authorities and others, 
which limits their ability to impact reliability. Although a generator 
may be given direction from the balancing authority, it is essential 
that generator operator personnel have appropriate training to 
understand those instructions, particularly in an emergency situation 
in which instructions may be succinct and require immediate action. 
Further, if communication is lost, the generator operator personnel 
should have had sufficient training to take appropriate action to 
ensure reliability of the Bulk-Power System. Thus, we direct the ERO to 
develop a modification to make PER-002-0 applicable to generator 
operators.
---------------------------------------------------------------------------

    \371\ NOPR at P 771.
---------------------------------------------------------------------------

    1361. We agree with FirstEnergy and others that some clarification 
is required regarding which generator operator personnel should be 
subject to formal training under the Reliability Standard. As noted 
above, a generator operator typically receives instructions from a 
balancing authority. Some generator operators are structured in such a 
way that they have a centrally-located dispatch center that receives 
direction and then develops specific dispatch instructions for plant 
operators under their control. For example, a balancing authority may 
direct a centrally-located dispatch center to deliver 300 MW to the 
grid, and the dispatch center would determine the best way to deliver 
that generation from its portfolio of units. In this type of structure, 
it is the personnel of the centrally-located dispatch center that must 
receive formal training in accordance with the Reliability Standard. 
Plant operators located at the generator plant site also need to be 
trained but the responsibility for this training is outside the scope 
of the Reliability Standard.\372\
---------------------------------------------------------------------------

    \372\ The Commission expects the entity registered as the 
generator operator to ensure that plant operators are competent for 
the tasks that they perform.
---------------------------------------------------------------------------

    1362. Other generator operators may be structured in such a way 
that the dispatch center and the single generation plant are at the 
same site. In this structure as well, some personnel will perform 
dispatch activities while others are designated as plant operators. 
Again, it is the dispatch personnel that must receive formal training 
in accordance with the Reliability Standard. Plant operators also need 
to be trained but the responsibility for this training is outside the 
scope of the Reliability Standard.
    1363. We disagree with Nevada Companies, Xcel and others that 
assert that generator operator training will provide limited benefit. 
Rather, we conclude that, with the above focused direction regarding 
the applicability of the Reliability Standard to generator operator 
personnel, the benefits to the Bulk-Power System will be maximized and 
the cost of formal training limited. Further, our direction addresses 
California PUC's concerns regarding application to plant operators. In 
any event, the existence of local training requirements in some regions 
does not supplant the need for uniform training requirements for all 
generator operators

[[Page 16546]]

developed in a Reliability Standard with continent-wide applicability.
    1364. Further, the Commission agrees with MidAmerican, SDG&E and 
others that the experience and knowledge required by transmission 
operators about Bulk-Power System operations goes well beyond what is 
needed by generation operators; therefore, training for generator 
operators need not be as extensive as that required for transmission 
operators. Accordingly, the training requirements developed by the ERO 
should be tailored in their scope, content and duration so as to be 
appropriate to generation operations personnel and the objective of 
promoting system reliability. Thus, in addition to modifying the 
Reliability Standard to identify generator operators as applicable 
entities, we direct the ERO to develop specific Requirements addressing 
the scope, content and duration appropriate for generator operator 
personnel.
    1365. FirstEnergy states that nuclear plant operators are already 
subject to NRC training requirements and thus suggests that compliance 
with NRC requirements should satisfy this Reliability Standard. 
FirstEnergy does not identify the content of the NRC training 
requirements, and the Commission is unaware whether the NRC training 
requirements adequately address the interaction between a nuclear power 
plant and the Bulk-Power System. Accordingly, without drawing any 
conclusion on the matter, the Commission directs that the ERO consider 
FirstEnergy's comments in the Reliability Standards development 
process.
    1366. Commenters' concerns regarding the need for a size limitation 
on generator operators should be satisfied by our determination that 
the applicability of particular entities should be determined based on 
the ERO compliance registry criteria, which APPA and TAPS support. We 
believe that limiting the applicability of Reliability Standards to 
NERC's definition of bulk electric system will alleviate much of 
Process Electricity Committee's concern regarding the effect of the 
expanded requirements on end users who have on-site generation. For 
larger end users who have on-site generation, the Commission believes 
that there is an added benefit to including them in the Reliability 
Standards because they sell into the market and should be treated on a 
similar basis as any other generator of a similar size.
iv. Applicability to Operations Planning and Operations Support Staff
    1367. As mentioned above, the Commission proposed in the NOPR to 
direct the ERO to develop a modification to PER-002-0 to require 
training of operations planning and operations support staff of 
transmission operators and balancing authorities who have a direct 
impact on the reliable operation of the Bulk-Power System.
(a) Comments
    1368. Several commenters, including EEI and APPA, oppose the 
proposed applicability of the Reliability Standard to operations 
planning and operations support staff. Other commenters contend that 
the Commission's proposal is ambiguous and should be clarified.
    1369. EEI states that the extension of the applicability to 
``operations support personnel'' could result in a dramatic expansion 
of industry training requirements with uncertain benefits to system 
reliability. It requests that the Commission reconsider this proposal 
or provide some additional clarity on the definition of the term. APPA 
also expresses concern about expanding the applicability to operations 
planning and operations support staff, especially if the Commission 
adopts its proposed interpretation of the bulk electric system because 
this would become quite onerous for small utilities. Wisconsin Electric 
states that the Commission's proposal does not address how to identify 
the operations planning and operations support personnel who would be 
subject to the Reliability Standard and how to develop compliance 
measures for them. It contends that the proposed modification is 
ambiguous and should not be implemented.
    1370. Avista states that individuals who are responsible for 
assessing a company's compliance with the Reliability Standards may 
simply have an administrative and coordination role, but have no direct 
responsibility for reliable operations of the Bulk-Power System. It 
argues that such individuals, while operations support staff, should 
not be subject to the proposed Reliability Standard. It therefore 
requests that the Commission clarify that personnel subject to the 
Reliability Standard may include operations planning and operations 
support staff.
    1371. Entergy believes it is unnecessary to require all staff 
supporting the transmission operator to be trained in the transmission 
operator's Reliability Standards responsibilities. It states that as 
long as the supporting personnel work under the direction of a NERC-
certified transmission operator, there is no need for duplicative 
training for supporting personnel. Entergy comments that, if such 
training is required, it should focus on the functions operations 
planning and operations support staff must perform, not on the 
functions that others perform.
    1372. Northern Indiana states that expanding application of the 
Reliability Standard to operations support staff ``with a direct impact 
on the reliable operation of the Bulk-Power System'' is ambiguous. It 
states that NERC surveyed certified operators for its job function 
analysis related to this Reliability Standard with results due at the 
end of January 2007. Northern Indiana recommends that the results of 
this survey be considered in the development and clarification of this 
proposed Reliability Standard. Further, Northern Indiana is concerned 
about which specific job functions will be addressed and which will be 
exempt, and about what ``direct'' versus ``indirect'' impact means.
(b) Commission Determination
    1373. The Commission directs the ERO to develop a modification to 
PER-002-0 that extends applicability to the operations planning and 
operations support staff of transmission operators and balancing 
authorities, as clarified below. Most commenters express concern about 
extending the applicability of the Reliability Standard because they 
believe ``operations planning'' and ``operations support'' are not 
well-defined and could encompass a significant number of operations 
personnel. In the NOPR, the Commission stated that the Reliability 
Standard should apply to operations planning and operations support 
staff that have a direct impact on the reliable operation of the Bulk-
Power System.\373\ We clarify that these personnel include those who 
carry out outage coordination and assessments in accordance with 
Reliability Standards IRO-004-1 and TOP-002-2, and those who determine 
SOLs and IROLs or operating nomograms in accordance with Reliability 
Standards IRO-005-1 and TOP-004-0. The Commission directs the ERO to 
include in PER-002-0, personnel who carry out the above functions.
---------------------------------------------------------------------------

    \373\ NOPR at P 780.
---------------------------------------------------------------------------

    1374. In addition, the Commission is aware that the personnel 
responsible for ensuring that critical reliability applications of the 
EMS, such as state estimator, contingency analysis and alarm processing 
packages, are available, up-to-date in terms of system

[[Page 16547]]

data and produce useable results can also have an impact on the 
Reliable Operation of the Bulk-Power System. Because these employees' 
impact on Reliable Operation is not as clear, we direct the ERO to 
consider, through the Reliability Standards development process, 
whether personnel that perform these additional functions should be 
included in mandatory training pursuant to PER-002-0.
    1375. APPA and EEI oppose the proposed extension of the Reliability 
Standard to operations planning and operations support staff, claiming 
that it could dramatically expand industry training requirements with 
uncertain benefits to system reliability. Our clarification above 
adequately addresses these concerns because we have identified a 
specific set of such personnel that have a direct impact on reliable 
operations. With the above clarification, our directive is not as 
expansive as EEI and APPA contemplate, and is more clearly connected 
with Bulk-Power System reliability. Further, since the Commission is 
not adopting the proposed interpretation of the ERO's definition of 
bulk electric system, as discussed in the Applicability section above, 
the directed modification to PER-002-0 should not be onerous to small 
entities as suggested by APPA.
    1376. Several commenters express concern that the operations 
planning and operations support staffs will be required to be trained 
on the transmission operators' responsibilities. The Commission 
clarifies that this is not the case. Training programs for operations 
planning and operations support staff must be tailored to the needs of 
the function, the tasks performed and personnel involved.
v. Training Performance Metrics
    1377. In the NOPR, we noted the assertion by ISO/RTO Council that 
there is no definition for ``adequately trained operating personnel.'' 
ISO/RTO Council suggested adoption of performance metrics to ensure 
that training results in competent operating personnel.\374\ The 
Commission agreed and proposed to require that the ERO modify PER-002-0 
to include performance metrics to assess the effectiveness of the 
training program. The Commission also stated that such performance 
metrics are not a substitute for an SAT developed training program.
---------------------------------------------------------------------------

    \374\ Id. at P 776.
---------------------------------------------------------------------------

(a) Comments
    1378. Xcel does not agree that performance metrics should be 
included as part of this Reliability Standard. While it believes 
performance metrics are generally useful, it states that in this case 
it would be difficult to develop the appropriate metrics. MidAmerican 
believes that the proposed performance metrics are not essential to 
ensuring the appropriateness of training because the Reliability 
Standard already requires NERC approval of all training activities, and 
specifically requires training in certain areas.
    1379. MISO and Wisconsin Electric state that it is unclear how a 
Reliability Standard to measure the effectiveness of a training program 
would apply to an organization that contracts for training services, 
and that there are many training requirements found in other 
Reliability Standards covering the topics and amount of training. They 
argue that the proposed modification is overly-prescriptive and 
deviates from a fundamental training concept that training should be 
tailored to the organization and to the individual.
(b) Commission Conclusion
    1380. Xcel, MISO and MidAmerican state that performance metrics to 
assess the effectiveness of training programs are unnecessary. The 
Commission believes that, if quantifiable performance metrics can be 
developed to gauge the effectiveness of a Reliability Standard, these 
performance metrics should be developed, tracked and used to 
continually improve an applicable entity's performance and the 
Reliability Standard itself. The Commission directs the ERO to explore 
the feasibility of developing meaningful performance metrics for 
assessing the effectiveness of training programs, and if feasible, to 
develop such metrics for the Reliability Standard as part of the 
Reliability Standards development process.
vi. Use of Systematic Approach to Training (SAT) Methodology
    1381. In the NOPR, the Commission required the ERO to use the SAT 
methodology in identifying the requirements for a training program 
because SAT is a proven approach to: identify the tasks and associated 
skills and knowledge necessary to accomplish those tasks; determine the 
competency levels of each operator to carryout those tasks; determine 
the competency gaps; and design, implement and evaluate a training plan 
to address each operator's competency.\375\
---------------------------------------------------------------------------

    \375\ Id. at P 775.
---------------------------------------------------------------------------

(a) Comments
    1382. ISO-NE states that the use of SAT methodology should not be 
mandated and that responsible entities under this Reliability Standard 
should be allowed the flexibility to use the most appropriate training 
methodology available. Northern Indiana requests clarification on about 
our proposal on the use of SAT methodology.
(b) Commission Determination
    1383. The Commission understands that the new operator training 
Reliability Standard PER-005-1-0 currently under development by the ERO 
would endorse the use of SAT. In response to ISO-NE, training based on 
SAT is a proven approach to identify the skills and knowledge necessary 
to accomplish particular tasks, evaluate each operator's competency to 
carry out those tasks, determine any competency competency gaps, and 
design, implement and evaluate a training plan to address such gaps. 
Since SAT is the most appropriate training methodology available, we 
believe this addresses ISO-NE's comments. Northern Indiana requests 
clarification about the details of our proposal for SAT methodology. 
The Commission has not directed how the SAT methodology should be 
implemented, but we expect it to be developed through the Reliability 
Standards development process. We encourage Northern Indiana to become 
involved in the process. Thus, we adopt the NOPR proposal to direct 
that the ERO develop a modification to PER-002-2 (or a new Reliability 
Standard) that uses the SAT methodology.
vii. Use of Simulators for Training
    1384. The Commission explained in the NOPR that Requirement R4 of 
the Reliability Standard requires training in emergency operations 
using realistic simulations of system emergencies and noted that there 
are various options available for providing operator training simulator 
capability, including contracting for this service from others who have 
developed the capability. The Commission requested comments on the 
benefits and appropriateness of required ``hands-on'' training using 
simulators in dealing with system emergencies.\376\
---------------------------------------------------------------------------

    \376\ Id. at P 778.
---------------------------------------------------------------------------

(a) Comments
    1385. While most commenters recognize the benefits of simulator 
training, they differ on whether simulator training should be 
mandatory.
    1386. NERC comments that there can be significant value gained by 
training operating personnel for emergencies under realistic conditions 
using training simulators and requests that comments on this matter be 
directed to the

[[Page 16548]]

Reliability Standards development process for consideration. APPA 
believes that significant reliability benefits could result from the 
use of simulators by reliability coordinators, transmission operators 
and balancing authorities that have operational control over a 
significant portion of load and resources. It does not believe, 
however, that requiring simulator training for smaller entities that do 
not have operational control over facilities that manage SOLs and IROLs 
would be an effective use of resources. APPA supports NERC's 
investigating the benefits of simulator training but recommends that 
any training requirements closely consider the costs and benefits of 
simulator training.
    1387. SoCal Edison and MISO state that, although simulators are 
valuable training tools, not all entities should be compelled to have 
simulators. MISO comments that simulators will become even more 
critical in the coming years as experienced operators, with first-hand 
knowledge of their respective systems, retire. Recognizing that not 
every company can or should build a simulator because of the resources 
simulators require, MISO suggests that the Reliability Standards codify 
a requirement for operators of companies that do not own a simulator to 
have access to a training simulator. MISO states that while simulators 
are valuable training resources, focusing emergency training solely on 
full-scale simulators may lead to problems when unforeseen situations 
arise. It reasons that generic, low-cost simulators that teach concepts 
are a valuable training resource for developing skills transferable to 
events that do not follow a script.
    1388. SDG&E states that simulators would enhance the overall 
training experience but cautions that simulators that accurately model 
individual systems are resource-consuming while less resource-
consuming, generic simulators may not mirror the trainee's actual 
system. As such, it believes that the use of simulators should be 
encouraged but not mandated. Similarly, International Transmission 
contends that simulators are a useful tool in the training of operators 
and support personnel. However it cautions that simulators are not the 
only means to provide realistic simulation-based training. It argues 
that because alternative simulation-based training means are available 
and because dedicated training simulators are very expensive, the use 
of dedicated training simulators should not be required under the 
Reliability Standards.
    1389. Otter Tail states that full-scale simulators are effective 
but costly to develop and labor intensive to maintain. It recommends 
that full-scale simulators should be an option but not a requirement 
for small entities. It proposes instead that the Commission allow small 
entities to continue to use training aids such as generic operator 
training simulators, EXCEL-based interactive training tools and table-
top training exercises. Likewise, Alcoa also does not believe that 
simulators are necessary to provide operating personnel with training 
for system emergencies. It supports alternative training methods, such 
as table-top exercises or realistic simulated exercises that take into 
account the physical and electrical characteristics of the trainee's 
system. Further, it believes that costs associated with simulators 
would not be justified by the impact on reliability.
    1390. Xcel states that to the extent that Reliability Standard PER-
002-0 is applicable to generator operators, the industry should be able 
to develop its own ways of administering training instead of being 
required to develop simulators.
(b) Commission Determination
    1391. Most commenters including NERC agree that hands-on training 
using simulators can add significant value to training for emergencies. 
Yet, we share the commenters' concerns regarding the high cost to 
develop and maintain full-scale simulators and take these concerns into 
consideration. The Commission finds that significant reliability 
benefits may be derived from requiring simulator training for 
reliability coordinators, transmission operators and balancing 
authorities that have operational control over a significant portion of 
load and generation.
    1392. This does not mean that these entities must develop and 
maintain full-scale simulators but rather they should have access to 
training on simulators. Further, because the cost is likely to outweigh 
the reliability benefits for small entities, the Commission agrees with 
Alcoa and Otter Tail that small entities should continue to use 
training aids such as generic operator training simulators and 
realistic table-top exercises. Accordingly, the Commission directs the 
ERO to develop a requirement for the use of simulators dependent on the 
entity's role and size, as discussed above.
viii. Summary of Commission Determination
    1393. The Commission notes that no commenters specifically 
addressed the proposed modifications directing the ERO to expand the 
Applicability section to include reliability coordinators, and to 
identify the expectations of the training for each job function and 
develop training programs tailored to each job function with 
consideration of the individual training needs of the personnel. 
However, in responding to the proposals to expand the applicability of 
the Reliability Standard, many commenters acknowledged the need to have 
clear training expectations and training programs tailored to specific 
job functions. The Commission finds that these two modifications will 
enhance the training by focusing on expectations and tailoring the 
training to specific job functions; therefore, the Commission adopts 
these modifications to the Reliability Standard.
    1394. Accordingly, the Commission approves Reliability Standard 
PER-002-0. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to PER-002-0 through the Reliability Standards 
development process that: (1) Identifies the expectations of the 
training for each job function; (2) develops training programs tailored 
to each job function with consideration of the individual training 
needs of the personnel; (3) expands the Applicability section to 
include (a) reliability coordinators, (b) local transmission control 
center operator personnel (as specified in the above discussion), (c) 
generator operators centrally-located at a generation control center 
with a direct impact on the reliable operation of the Bulk-Power System 
and (d) operations planning and operations support staff who carry out 
outage planning and assessments and those who develop SOLs, IROLs or 
operating nomograms for real-time operations; (4) uses the Systematic 
Approach to Training (SAT) methodology in its development of new 
training programs and (5) includes the use of simulators by reliability 
coordinators, transmission operators and balancing authorities that 
have operational control over a significant portion of load and 
generation.
    1395. Further, the Commission directs the ERO to determine whether 
it is feasible to develop meaningful performance metrics associated 
with the effectiveness of a training program required by PER-002-0 and, 
if so, develop such performance metrics. The Commission also directs 
the ERO to consider through the Reliability Standards development 
process, whether personnel that support EMS applications as discussed 
above should be included in mandatory training pursuant to the 
Reliability Standard.

[[Page 16549]]

c. Operating Personnel Credentials (PER-003-0)
    1396. PER-003-0 requires transmission operators, balancing 
authorities and reliability coordinators to have NERC-certified staff 
for all operating positions that have a primary responsibility for 
real-time operations or are directly responsible for complying with the 
Reliability Standards. NERC grants certification to operating personnel 
through a separate program documented in the NERC System Operator 
Certification Manual and administered by an independent personnel 
certification governance committee.
    1397. In the NOPR, the Commission proposed to approve Reliability 
Standard PER-003-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to PER-003-
0 that: (1) Includes generator operators as applicable entities; (2) 
specifies the minimum competencies that must be demonstrated to become 
and remain a certified operator; and (3) identifies the minimum 
competencies operating personnel must demonstrate to be certified.
i. Comments
    1398. In addressing this Reliability Standard, many commenters made 
the same arguments they made in connection with the operator training 
Requirements set forth in Reliability Standard PER-002-0. Comments 
specifically relevant to operator certification are reproduced here for 
completeness.
    1399. EEI, FirstEnergy and PG&E agree that the Reliability Standard 
should apply to generator operators. FirstEnergy believes that the 
Functional Model and the Reliability Standards development process 
should be used to clarify any confusion about which generator operator 
and transmission operator functions are addressed under this 
Reliability Standard. To further reduce confusion and the need for 
potentially duplicative training, EEI and PG&E comment that operators 
should not be required to maintain multiple certifications. SDG&E 
states that new certification obligations for generator operators must 
be tailored to the needs of the function and should reflect the limited 
opportunities of generator operators to have an impact on system 
reliability. Thus, it argues that generator operators should not be 
subject to the same certification requirements as transmission 
operators. MidAmerican echoes this point and adds that minimum 
competencies are currently adequately demonstrated by the completion of 
NERC-approved annual certification tests. MidAmerican believes that 
applicable tests should be tailored to specific job duties to ensure 
effectiveness and Reliability Standard compliance.
    1400. Dynegy, MISO, Reliant and Wisconsin Electric are concerned 
about extension of this Reliability Standard to generator operators if 
it results in every power plant control room being staffed by NERC-
certified operators. Dynegy supports a limited extension of the 
Reliability Standard to real-time operational personnel located in a 
centralized generation control center that interfaces with the plants 
and the local RTO/ISO. Reliant believes that, under certain 
circumstances, the dispatcher in the generator operator's local control 
center should not be subject to NERC certification requirements. It 
explains that, for example, in PJM the dispatcher in a generator 
operator local control center is a PJM-certified generation dispatcher 
and that, like the employees in plant operating positions, these 
dispatchers do not take unilateral action but instead act only upon 
PJM's instructions.
    1401. LPPC states that certification requirements for real-time 
operations Reliability Standards should only be required for 
transmission and generation personnel that are located in the 
transmission control center (i.e., responsible for real-time Bulk-Power 
System operations). It argues that transmission and generation 
operation employees that are located in remote locations that are not 
directly involved in the real-time scheduling of transactions or Bulk-
Power System monitoring and control do not need to be certified for 
real-time operations Reliability Standards because they are not 
involved in the type of functions in which regimented training in the 
Reliability Standards would be useful. LPPC states that requiring 
certification would be an inefficient result and would distract these 
personnel from their own highly-specialized tasks.
    1402. Although APPA states that PER-003-0 is sufficient for 
approval as a mandatory and enforceable Reliability Standard, it 
opposes the proposed modification to make generator operators subject 
to the Reliability Standard. Alcoa, Entergy, Northern Indiana and Xcel 
also oppose subjecting generator operators to the Reliability Standard. 
Given that there is no size limitation limiting applicability for 
generator operators, APPA asks the Commission to reconsider the 
proposed modification and, instead, allow the applicability of PER-003-
0 to generator operators to be considered through the Reliability 
Standards development process. Alcoa disagrees with the proposed 
modification because generator operators take direction from a NERC-
certified transmission operator, balancing authority or reliability 
coordinator and do not operate independently of those entities. 
Similarly, Xcel states generator operators have limited ability to take 
independent action that affects Bulk-Power System reliability. It also 
states that it is not clear whether ``generator operator'' means plant 
operator or the transmission operator responsible for generation.
    1403. Northern Indiana and SoCal Edison oppose a certification 
requirement for all real-time operating positions in a transmission 
control center that performs switching operations via SCADA for the 
Bulk-Power System, because these personnel are supervised by NERC-
certified operators. Northern Indiana states that the costs would far 
outweigh the reliability benefits, if any, that would result from such 
a certification requirement. SoCal Edison recommends that PER-003-0 
apply to operators who have the authority and are empowered to exercise 
independent judgment, and who take or direct actions to secure Bulk-
Power System reliability. It recommends that operators who switch Bulk-
Power System facilities when their actions are approved and overseen by 
certified operators should be excluded.
    1404. APPA states that if it is required to send its employees for 
NERC training and certification, it would risk losing those employees 
to larger utilities that can afford to pay more, simply because those 
employees would have acquired a desirable occupational credential. It 
argues that given the substantial workforce issues facing public power 
systems in the next few years, imposing unneeded certification 
requirements could exacerbate an already challenging labor force 
situation.
    1405. Northern Indiana adds that because some of these employees 
are members of labor unions and subject to existing collective 
bargaining agreements, it would have to renegotiate these agreements to 
provide for the certification of these employees, and to provide for 
the hiring of relief staff necessary to permit these employees to 
maintain their certification.
    1406. PG&E states that, once the certification requirements are 
developed by NERC and approved by the Commission, sufficient time must 
be permitted for generator operators to attain the necessary 
certification. It argues that time will be needed to

[[Page 16550]]

develop the process, create appropriate documentation and perform 
training for appropriate personnel. PG&E contends that generator 
operators should not be penalized for failing to achieve certification 
if they do not have a reasonable period of time to implement the 
training programs.
    1407. EEI believes that the ERO's Reliability Standards development 
process should be used to sort out the applicability issues. It states 
that using this process will allow for sufficient clarity to reduce the 
risk of confusion and thus prevent the need for interpretations that 
could change over time. EEI believes this is especially important with 
this PER class of Reliability Standards because operators should have 
unambiguous guidance on what they are expected to do. It states that 
the Reliability Standards should be written so that operating personnel 
clearly understand their roles and responsibilities, and whether or not 
a specific certification is required. EEI also states that operators 
should not be required to maintain multiple certifications.
ii. Commission Determination
    1408. Northern Indiana and APPA raise persuasive arguments 
regarding labor relations and labor retention issues that may arise if 
generator operators are required to be NERC-certified. The Commission 
understands theses concerns and is persuaded not to require generator 
operators or transmission operators at local control centers to be 
NERC-certified at this time. In addition, the Commission understands 
that there are some long tenured unionized transmission operators who 
are very capable operators but who are unable to secure certification. 
This is not a new problem and has been addressed in various collective 
bargaining negotiations through grandfathering such capable operators 
who are unable to become certified. However, the Commission directs 
that if grandfathering is implemented, the entity must attest that the 
operators are competent. The Commission directs the ERO to consider 
grandfathering certification requirements for these personnel so that 
the industry can retain the knowledge and skill of these long-tenured 
operators. Personnel that are subject to such grandfathering still must 
comply with applicable training requirements pursuant to PER-002-0.
    1409. No comments were received on the proposed modifications to 
direct the ERO to modify the Reliability Standard to specify the 
minimum competencies that must be demonstrated to become and remain a 
certified operator and to identify the minimum competencies operating 
personnel must demonstrate to be certified. The Commission finds that 
these modifications improve the Reliability Standard by focusing on 
necessary competencies. Accordingly, the Commission directs the ERO to 
develop these modifications to the Reliability Standard.
    1410. We find that the Reliability Standard serves an important 
reliability goal in requiring applicable entities to staff all 
operating positions that have a primary responsibility for real-time 
operations or are directly responsible for complying with the 
Reliability Standards with NERC-certified staff. Accordingly, the 
Commission approves Reliability Standard PER-003-0. In addition, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission directs the ERO to develop a modification 
to PER-003-0 through the Reliability Standards development process 
that: (1) Specifies the minimum competencies that must be demonstrated 
to become and remain a certified operator and (2) identifies the 
minimum competencies operating personnel must demonstrate to be 
certified. The Commission also directs the ERO to consider 
grandfathering certification requirements for transmission operator 
personnel in the Reliability Standards development process.
d. Reliability Coordination--Staffing (PER-004-1)
    1411. PER-004-1 ensures that reliability coordinator personnel are 
adequately trained, NERC-certified and staffed 24-hours a day, seven 
days a week, with properly trained and certified individuals.\377\ 
Further, reliability coordinator operating personnel must have a 
comprehensive understanding of the area of the Bulk-Power System for 
which they are responsible.
---------------------------------------------------------------------------

    \377\ In its November 15, 2006, filing, NERC submitted PER-004-
1, which supercedes the Version 0 Reliability Standard. PER-004-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, PER-004-1.
---------------------------------------------------------------------------

    1412. In the NOPR, the Commission proposed to approve Reliability 
Standard PER-004-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
the Commission proposed to direct NERC to submit a modification to PER-
004-0 that: (1) Includes formal training requirements for reliability 
coordinators similar to those addressed under the personnel training 
Reliability Standard PER-002-0; (2) includes requirements pertaining to 
personnel credentials for reliability coordinators similar to those in 
PER-003-0 and (3) includes Measures and Levels of Non-Compliance that 
address staffing requirements and the requirement for five days of 
emergency training.
i. Comments
    1413. APPA notes that the revised Reliability Standard PER-004-1 
filed by NERC on November 15, 2006 partially fulfills the directive to 
include Measures and Levels of Non-Compliance. It states that NERC 
should be directed to include Measures and Levels of Non-Compliance 
related to all Requirements.
    1414. FirstEnergy seeks revisions to the terms ``shall have a 
comprehensive understanding'' and ``shall have extensive knowledge.'' 
It states that it will be difficult for entities to demonstrate 
compliance with these terms. In addition, FirstEnergy suggests that the 
reliability coordinator staffing requirements should be located in the 
IRO Reliability Standards.
    1415. Xcel states that emergency training requirements should be 
expressed in hour increments rather than days to allow for flexibility 
in scheduling training and coordinating with rotating shift schedules.
ii. Commission Determination
    1416. No comments were received on the proposed modifications to 
include formal training requirements for reliability coordinators 
similar to those addressed under the personnel training Reliability 
Standard PER-002-0 and to include requirements pertaining to personnel 
credentials for reliability coordinators similar to those in PER-003-0. 
The Commission finds that these modifications will improve the 
Reliability Standard because they include training requirements for the 
reliability coordinator who has the highest level of authority to 
assure Reliable Operation of the Bulk-Power System. Accordingly, the 
Commission directs the ERO to develop modifications to the Reliability 
Standard that address these matters.
    1417. With regard to APPA's comments, consistent with our 
discussion above regarding Measures and Levels of Non-Compliance, we 
leave it to the discretion of the ERO whether it is necessary that each 
Requirement of this Reliability Standard have a corresponding Measure.
    1418. We find that the Reliability Standard adequately addresses 
reliability coordinator staffing. Accordingly, the Commission approves 
Reliability Standard PER-004-1. In

[[Page 16551]]

addition, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of 
our regulations, the Commission directs the ERO to develop a 
modification through the Reliability Standards development process to 
PER-004-1 that: (1) Includes formal training requirements for 
reliability coordinators similar to those addressed under the personnel 
training Reliability Standard PER-002-0 and (2) includes requirements 
pertaining to personnel credentials for reliability coordinators 
similar to those in PER-003-0. Further, we direct the ERO to consider 
the suggestions of FirstEnergy and Xcel in the Reliability Standards 
development process.
10. PRC: Protection and Control
    1419. Protection and Control systems (PRC) on Bulk-Power System 
elements are an integral part of reliable grid operation. Protection 
systems are designed to detect and isolate faulty elements on a system, 
thereby limiting the severity and spread of system disturbances, and 
preventing possible damage to protected elements. The function, 
settings and limitations of a protection system are critical in 
establishing SOLs and IROLs. The PRC Reliability Standards apply to 
transmission operators, transmission owners, generator operators, 
generator owners, distribution providers and regional reliability 
organizations and cover a wide range of topics related to the 
protection and control of power systems.
a. System Protection Coordination (PRC-001-1)
    1420. PRC-001-1 \378\ ensures that protection systems are 
coordinated among operating entities by requiring transmission and 
generator operators to notify appropriate entities of relay or 
equipment failures that could affect system reliability. In addition, 
transmission and generator operators must coordinate with appropriate 
entities when new protection systems are installed, or when existing 
protection systems are modified.
---------------------------------------------------------------------------

    \378\ In its November 15, 2006, filing, NERC submitted PRC-001-
1, which supercedes the Version 0 Reliability Standard. PRC-001-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, PRC-001-1.
---------------------------------------------------------------------------

    1421. In the NOPR, the Commission proposed to approve PRC-001-0 as 
mandatory and enforceable. In addition, the Commission proposed to 
direct NERC to submit modifications to PRC-001-0 (proposed directives) 
that included: (1) Measures and Levels of Non-Compliance; (2) a 
requirement that transmission and generator operators be informed 
immediately upon the detection of failures in relays or protection 
system elements on the Bulk-Power System that would threaten reliable 
operation, so that these entities could carry out appropriate 
corrective control actions consistent with those used in mitigating 
IROL violations and (3) clarifying that, after being informed of 
failures in relays or protection system elements on the Bulk-Power 
System, transmission operators or generator operators carry out 
corrective control actions that return a system to a stable state as 
soon as possible, but no longer than 30 minutes after receiving a 
notice of failure.
i. Comments
    1422. While Constellation supports the Commission's proposed 
directives because they represent additional steps to achieving 
reliability of the Bulk-Power System and eliminating undue 
discrimination, MISO questions the need for the Commission's proposals. 
MISO notes that virtually all protection schemes have backups. MISO 
asks whether the Commission wants facilities to be removed from service 
if one of the redundant relaying packages has a problem, or whether 
some other action should be taken besides such removal.
    1423. With regard to the NOPR's direction to the ERO to include 
Measures and Levels of Non-Compliance, APPA states that the new 
Measures only partially address the Requirements, and in some cases, 
reference non-existent Requirements. For example, rather than 
referencing Requirement R5.1, new Measure M1 incorrectly refers to non-
existent Requirement R8.1. Similarly, rather than referencing 
Requirement R5.2, new Measure M2 incorrectly refers to non-existent 
Requirement R8.2.
    1424. APPA states that while it agrees that PRC-001-1 is sufficient 
for approval, since the new Measures only partially address the 
Requirements, and in some cases refer to non-existent Requirements, no 
penalties should be levied for violations of Requirements that have no 
accompanying Measures.
    1425. WIRAB states that the Requirements, Measures and Levels of 
Non-Compliance do not provide guidance for the length of time--
currently stated as ``as soon as possible''--permitted for corrective 
actions.
    1426. APPA disagrees with the Commission's second and third 
directives to NERC. APPA states that the BAL and IRO Reliability 
Standards already have specific standards to notify affected entities 
and provide directions for recovery time. APPA acknowledges that in the 
NOPR, we stated that ``the Reliability Standards on mitigating IROL 
violations are not specific enough and system operators or field 
protection and control personnel would not be alerted about failures of 
relays and protection systems on critical elements.'' APPA, however, 
states that: ``If this is the Commission's view, then it should 
instruct NERC to re-examine the interaction between these two sets of 
standards [IROL and SOL and proposed PRCs] on remand, and to develop 
the most efficient solution to this problem. The Commission should not 
itself undertake to resolve this problem by issuing directives for 
specific revisions to PRC-001-1, especially if the result might be to 
have local level personnel countermanding the instruction of RC 
personnel at a time when the system is unstable.'' APPA asserts that 
the Commission should modify its proposed directives to allow NERC, as 
technical expert, to address the problems in the Reliability Standard 
that the Commission has identified.
    1427. Dynegy states that in many situations, depending on the 
particular relay or protection system failure, an operator may not be 
able to complete corrective control actions that return the system to a 
stable state within 30 minutes, including troubleshooting of relays or 
restoring any tripped facilities. Dynegy find that a 30-minute time 
period may thus be overly rigid and punitive. Wisconsin Electric also 
requests further clarification of the 30-minute time limit to carry out 
corrective actions after a relay failure. It has additional concerns 
about older relays (e.g., electromechanical relays) since it is 
impossible to know when and whether these older relays have failed. 
Wisconsin Electric also states that the NOPR is not clear about which 
relays threaten reliable system operation.
    1428. Northern Indiana states that the NOPR appears to require 
immediate corrective actions whenever failures on relays or protection 
systems are detected, without regard to whether the specific failure 
detected reduces system reliability. It seeks the Commission's 
clarification that we do not intend to question a certified 
transmission operator's expertise in assessing whether a particular 
relay or protection system failure reduces system reliability.
    1429. California PUC contends that imposing a time restriction for 
returning a system to a stable state may cause more harm than good 
since additional information and options may be available as time 
elapses. It repeats its suggestion from its earlier comments on

[[Page 16552]]

the Staff Preliminary Assessment and proposes the following alternative 
language: ``Transmission or generation operators shall carry out 
corrective control actions, i.e., returning the system to a stable 
state that respects system requirements as soon as possible, and no 
longer than 30 minutes, except where a longer response time is 
feasible, or where a longer response is demonstrated to produce a 
better ultimate solution without unacceptable interim risk.''
    1430. A number of commenters raise concerns that the proposal would 
be unnecessarily burdensome on generator operators. For example, 
Progress Electricity Committee asserts that the Commission's proposal 
to require generator operators to return the system to a stable state 
as soon as possible and within no longer than 30 minutes may be too 
burdensome for non-energy company users with on-site generation. 
California Cogeneration asserts that PRC-001-1 as a whole may impose 
unreasonable burdens on generators with no material impact on the grid, 
because most such generators will have no knowledge of the protection 
systems on the grid.
    1431. Allegheny states that since generator operators do not have 
the same resources as transmission operators for taking corrective 
actions, the Commission's third proposed directive should be modified 
to apply only to transmission operators. Allegheny states that while a 
transmission operator can direct a generator operator to take specific 
actions, the reverse is not the case.
    1432. FirstEnergy contends that Requirement R2.1 essentially 
requires generator operators to report all protective relay or 
equipment failures, since generator operators may not be able to tell 
which failures will reduce system reliability. FirstEnergy suggests 
that R2.1 should be revised to require generator operators to report 
all equipment failures or outages. FirstEnergy further suggests that 
PRC-001-1 be revised to provide that if a company performs reasonable 
testing procedures, undiscoverable equipment failures will not be 
violations of R2.1.
    1433. MidAmerican states that the term ``immediately'' in the 
Commission's second directive is ambiguous and unenforceable. It 
suggests a 30-minute time limit.
ii. Commission Determination
    1434. The Commission approves PRC-001-1 as mandatory and 
enforceable. We also direct NERC to develop a modification to PRC-001-1 
through the Reliability Standards development process, as discussed 
below.
    1435. The Commission observes that, collectively, the comments 
raise three general questions: (1) Whether relay or equipment failures 
reduce system reliability and, if so, in what circumstances; (2) what 
are ``corrective actions'' required to return a system to a secure 
operating state and (3) when is returning a system to a secure 
operating state ``as soon as possible.'' \379\ The Commission will 
discuss each question in turn.
---------------------------------------------------------------------------

    \379\ PRC-001-1 Requirement R2.2 provides: ``If a protective 
relay or equipment failure reduces system reliability, the 
Transmission Operator shall notify its Reliability Coordinator and 
affected Transmission Operators and Balancing Authorities. The 
Transmission Operator shall take corrective action as soon as 
possible.''
---------------------------------------------------------------------------

(a) Whether Relay or Equipment Failures Reduce System Reliability and, 
if So, in What Circumstances?
    1436. Protection systems on Bulk-Power System elements are an 
integral part of reliable operations. They are designed to detect and 
isolate faulty elements on a power system, thereby limiting the 
severity and spread of disturbances and preventing possible damage to 
protected elements. If a protection system can no longer perform as 
designed because of a failure of its relays, system reliability is 
reduced or threatened. In deriving SOLs and IROLs, moreover, the 
functions, settings, and limitations of protection systems are 
recognized and integrated. Systems are only reliable when protection 
systems perform as designed. This is what PRC-001-1 means in linking a 
reduction in system reliability with a protection relay failure or 
other equipment failure.
    1437. With respect to MISO's comment that virtually all protection 
systems have backups and therefore the Commission's proposals are not 
necessary, unless the backup protection has the same design goals and 
capabilities as the primary protection, a relay failure in the primary 
protection may still threaten system reliability. Further, we note that 
while the PRC Reliability Standards do not specifically require 
protection systems consisting of redundant and independent protection 
groups for each critical element in the Bulk-Power System, such 
requirements are included as one potential solution in the TPL 
Reliability Standards.\380\
---------------------------------------------------------------------------

    \380\ If delayed clearing results in reliability criteria 
violations, one solution can be the use of redundant relay systems. 
TPL-002-0 Table 1, footnote e.
---------------------------------------------------------------------------

    1438. Finally, MISO's question seems to imply that if there are 
redundant relaying packages providing redundant protection, and a 
problem develops with only one of those redundant packages, system 
reliability is not threatened, and therefore, there is no need to take 
corrective control actions within 30 minutes. We agree with MISO's 
conclusion for this scenario.
    1439. In the case, however, of a system element protected by a 
single protection system with a failed relay that threatens system 
reliability, that scenario would require the use of appropriate 
operating solutions including removing a system element from service. 
Another possible solution is to operate a system at a lower SOL or IROL 
that recognizes the degraded protection performance.
(b) What Are Corrective Actions?
    1440. Corrective actions taken by transmission operators to return 
a system to a secure operating state when a protective relay or 
equipment failure reduces system reliability normally refer to 
``operator control actions'', consisting of operator actions such as 
removing the facility without protection from service, generation 
redispatch, transmission re-configuration, etc. Corrective action must 
be completed as soon as possible, but no longer than 30 minutes after a 
notice of protection system failure. Failure to complete corrective 
action within 30 minutes will be considered a violation of the relevant 
IROL or TOP Reliability Standards. In contrast, troubleshooting or 
replacing failed relays or equipment are performed by field maintenance 
personnel and normally take hours or even days to complete. These 
actions are not normally considered corrective actions in the context 
of real-time operation of the Bulk-Power System.
    1441. We believe that ``[t]he transmission operator shall take 
corrective action as soon as possible'' refers to transmission 
operators taking operator control actions. It does not refer to 
troubleshooting, repairing or replacing failed relays or equipment, 
etc., since these time-consuming corrective actions would prolong the 
risk of cascading failures to the Bulk-Power System.
    1442. Dynegy, Wisconsin Electric and Northern Indiana are concerned 
that the time required to troubleshoot, repair or replace failed relays 
and equipment would be substantially longer than the 30 minutes set 
forth in the Commission's proposed directive. We believe we have 
alleviated this concern in our discussion, above. In addition, in 
response to Northern Indiana, we clarify that the responsibility for 
assessing whether a particular relay or protective system failure 
reduces system reliability remains with transmission operators. We 
direct the ERO to clarify the term

[[Page 16553]]

``corrective action'' consistent with this discussion when it modifies 
PRC-001-1 in the Reliability Standards development process.
    1443. We agree with Allegheny that generator operators do not have 
the same ability as transmission operators to take corrective control 
actions on the Bulk-Power System, and we will modify our third 
directive as set forth below. We believe this also addresses Progress 
Electricity Committee and California Cogeneration's similar concerns.
(c) When Is ``As Soon as Possible''?
    1444. As explained above, the requirement for system operators to 
take corrective control action when protective relay or equipment 
failure reduces system reliability should be treated the same as the 
requirement for returning a system to a secure and reliable state after 
an IROL violation, i.e., as soon as possible, but no longer than 30 
minutes after a violation. A longer time limit would place an entity in 
violation of relevant IROL or TOP Reliability Standards.
    1445. The Commission directs the ERO to consider FirstEnergy and 
California PUC's comments about the maximum time for corrective action 
in the ERO Reliability Standards development process.
    1446. In response to MidAmerican's request that we clarify the term 
``immediately'' in our proposed second directive, we direct the ERO, in 
the Reliability Standards development process, to determine the 
appropriate amount of time after the detection of relay failures, in 
which relevant transmission operators must be informed of such 
failures.
    1447. We agree with APPA that the added Measures and Levels of Non-
Compliance incorrectly reference non-existent requirements. We direct 
the ERO to revise the references accordingly.
    1448. We disagree with APPA that BAL and IRO Reliability Standards 
already address matters contained in PRC-001-1, because BAL and IRO are 
not related to relay and equipment failures, which are specifically 
addressed in PRC-001-1.
    1449. We disagree with APPA's assertion that ``the Reliability 
Standards on mitigating IROL violations are not specific enough and 
system operators or field protection and control personnel would not be 
alerted about failure of relays and protection systems on critical 
elements.'' The time allowed for mitigating actual IROL violations is 
very clear: as soon as possible and within 30 minutes. We clarify that 
our concern is not about ``field protection and control personnel not 
being alerted about failure of relays and protection systems on 
critical elements.'' Our focus, rather, is that upon detection of 
failure of relays and protection systems on critical elements, field 
personnel must report the failures promptly to the transmission 
operators so that corrective operator control actions can be taken as 
soon as possible and within 30 minutes. Finally, with respect to APPA's 
contention that our proposed directives would result in local-level 
personnel undermining or not following the instructions of reliability 
coordinator personnel at a time when the system is unstable, we do not 
understand how local level personnel, who have no operating control of 
a transmission operator's system or a reliability coordinator's system 
could do so.
    1450. The Commission approves Reliability Standard PRC-001-1 as 
mandatory and enforceable. In addition, the Commission directs the ERO 
to develop modifications to PRC-001-1 through the Reliability Standards 
development process that: (1) Correct the references for Requirements 
and (2) include a requirement that upon the detection of failures in 
relays or protection system elements on the Bulk-Power System that 
threaten reliable operation, relevant transmission operators must be 
informed promptly, but within a specified period of time that is 
developed in the Reliability Standards development process, whereas 
generator operators must also promptly inform their transmission 
operators and (3) clarifies that, after being informed of failures in 
relays or protection system elements that threaten reliability of the 
Bulk-Power System, transmission operators must carry out corrective 
control actions, i.e., return a system to a stable state that respects 
system requirements as soon as possible and no longer than 30 minutes 
after they receive notice of the failure.
b. Define Regional Disturbance Monitoring and Reporting Requirements 
(PRC-002-1)
    1451. PRC-002-1 ensures that each regional reliability organization 
establishes requirements to install Disturbance Monitoring Equipment 
(DME) and report disturbance data to facilitate analyses of events and 
verify system models.
    1452. In the NOPR, the Commission identified PRC-002-1 as a fill-
in-the-blank standard. The NOPR stated that because the regional 
requirements for installing DME had not been submitted, the Commission 
would not approve or remand PRC-002-1 until the ERO submitted the 
additional information.
i. Comments
    1453. APPA agrees with the Commission's proposed course of action. 
It states that there are significant and substantive differences 
between regional procedures due to the characteristics of various 
regional grids. Further it suggests that NERC and the Regional Entities 
consider whether they can attain greater consistency on an 
Interconnection-wide basis in addressing the completion of this 
Reliability Standard.
    1454. Alcoa suggests that the ERO--instead of a Regional Entity--
should define the requirements for DME and the type of report it 
generates. The requirements and equipment specifications should be 
consistent throughout North America. In addition, Alcoa suggests that 
the criteria for installation of such equipment should include the 
necessary monitoring and recording that contribute to analysis and 
enhance reliability.
    1455. Otter Tail suggests that PRC-002-1 should be developed on an 
Interconnection-wide basis to ensure consistency and promote 
reliability of the Bulk-Power System.
ii. Commission Determination
    1456. For the reasons stated in the NOPR, the Commission will not 
approve or remand PRC-002-1.
    1457. We agree with APPA, Alcoa and Otter Tail that the ERO should 
consider whether greater consistency can be achieved in this 
Reliability Standard. In Order No. 672, the Commission also encouraged 
greater uniformity in the development of Reliability Standards.\381\ 
Consistent with that goal, the Commission directs the ERO to consider 
APPA, Alcoa and Otter Tail's suggestions in the Reliability Standards 
development process as it modifies PRC-002-1 to provide missing 
information needed for the Commission to act on this Reliability 
Standard.
---------------------------------------------------------------------------

    \381\ Order No. 672 at P 292.
---------------------------------------------------------------------------

c. Regional Procedure for Analysis of Misoperations of Transmission and 
Generation Protection Systems (PRC-003-1)
    1458. PRC-003-1 ensures that all transmission and generation 
protection system misoperations are analyzed, and corrective action 
plans are developed. Misoperations occur when a protection system 
operates when it should not or does not operate when it should. This 
Reliability Standard requires each regional reliability organization to 
develop a procedure to monitor and review misoperations of protection

[[Page 16554]]

systems and to develop and document corrective actions.
    1459. In the NOPR, the Commission identified PRC-003-1 as a fill-
in-the-blank standard. The NOPR stated that because the regional 
procedures had not been submitted, the Commission proposed not to 
approve or remand PRC-003-1 until the ERO submitted the additional 
information.
i. Comments
    1460. APPA agrees with the Commission's proposed course of action. 
It states that there are significant and substantive differences 
between regional procedures due to the characteristics of various 
regional grids and industry structures. Further it suggests that NERC 
and the Regional Entities consider whether they can attain greater 
consistency on an Interconnection-wide basis in completing this 
Reliability Standard.
ii. Commission Determination
    1461. For the reasons stated in the NOPR, the Commission will not 
approve or remand PRC-003-1.
    1462. We agree with APPA that the ERO should consider whether 
greater consistency can be achieved in this Reliability Standard. In 
Order No. 672, the Commission also encouraged greater uniformity in the 
development of Reliability Standards.\382\ Consistent with that goal, 
the Commission directs the ERO to consider APPA's suggestions in the 
Reliability Standards development process as it modifies PRC-003-1 to 
provide missing information needed for the Commission to act on this 
Reliability Standard.
---------------------------------------------------------------------------

    \382\ Id. at P 292.
---------------------------------------------------------------------------

d. Analysis and Reporting of Transmission Protection System 
Misoperations (PRC-004-1)
    1463. PRC-004-1 ensures that all transmission and generation 
protection system misoperations affecting the reliability of the Bulk-
Power System are analyzed and mitigated by requiring transmission 
owners, generator owners and distribution providers that own a 
transmission protection system to analyze and document protection 
system misoperations. These entities must also develop corrective 
action plans in accordance with the regional reliability organization's 
procedures.
    1464. In the NOPR, the Commission proposed to approve PRC-004-1 as 
mandatory and enforceable.
i. Comments
    1465. APPA agrees that PRC-004-1 is sufficient for approval as a 
mandatory and enforceable Reliability Standard.
    1466. ISO-NE and ISO/RTO Council oppose the Commission's proposed 
approval of PRC-004-1 because it relies on PRC-003-1, a fill-in-the-
blank standard, which the Commission does not propose to approve or 
remand until the ERO submits additional information.
    1467. ISO-NE further requests the Commission to direct NERC to 
modify PRC-004-1 to include LSEs and transmission operators in the 
applicability section. It states that based on current practice in the 
ISO-NE balancing area, transmission operators, transmission owners, 
LSEs and distribution providers may individually or jointly own and 
operate a protection system. It therefore suggests that transmission 
operators and LSEs should also be included in the applicability 
section. ISO-NE provides the same suggestion with regard to PRC-005-1, 
PRC-008-0, PRC-011-0, PRC-015-0, PRC-016-0, PRC-017-0 and PRC-021-1.
 ii. Commission Determination
    1468. The Commission approves Reliability Standard PRC-004-1 as 
mandatory and enforceable.
    1469. We are not persuaded by ISO-NE and ISO/RTO Council's 
assertion that PRC-004-1 should not be approved because it refers to 
PRC-003-1, which is a fill-in-the-blank standard. In part, we neither 
approve nor remand PRC-003-1 because it applies to a regional 
reliability organization, and we are not persuaded that a regional 
reliability organization's compliance with a Reliability Standard can 
be enforced as NERC proposes.\383\ This is not the case with PRC-004-1, 
which applies to transmission owners, distribution providers, and 
generator owners. Since PRC-004-1 is an existing Reliability Standard 
that has been followed on a voluntary basis, transmission owners, 
distribution providers and generator owners are on notice of 
requirements related to misoperations of transmission and generation 
protection systems. As stated in the Common Issues section, a reference 
to an unapproved Reliability Standard may be considered in an 
enforcement action, but is not a reason to delay approving and 
enforcing this Reliability Standard.
---------------------------------------------------------------------------

    \383\ NOPR at P 56-57.
---------------------------------------------------------------------------

    1470. We direct the ERO to consider ISO-NE's suggestion that LSEs 
and transmission operators should be included in the applicability 
section, in the Reliability Standards development process as it 
modifies PRC-004-1.\384\ Further, as the ERO reviews this Reliability 
Standard in its five-year cycle of review, the Regional Entity, rather 
the regional reliability organization, should develop the procedures 
for corrective action plans.
---------------------------------------------------------------------------

    \384\ The same suggestion and therefore same Commission response 
also applies to PRC-005-1, PRC-008-0, PRC-011-0, PRC-015-0, PRC-016-
0, PRC-017-0 and PRC-021-1.
---------------------------------------------------------------------------

e. Transmission and Generation Protection System Maintenance and 
Testing (PRC-005-1)
    1471. PRC-005-1 ensures that all transmission and generation 
protection systems affecting the reliability of the Bulk-Power System 
are maintained and tested by requiring the transmission owners, 
distribution providers, and generator owners to develop, document, and 
implement a protection system maintenance program that may be reviewed 
by the regional reliability organization.
    1472. In the NOPR, the Commission proposed to approve PRC-005-1 as 
mandatory and enforceable. In addition, the Commission proposed to 
direct NERC to submit a modification to PRC-005-1 that includes a 
requirement that maintenance and testing of a protection system must be 
carried out within a maximum allowable interval that is appropriate to 
the type of the protection system and its impact on the reliability of 
the Bulk-Power System.
i. Comments
    1473. FirstEnergy states that NERC should establish a maximum 
maintenance interval for protection system equipment, and a national 
limitation taking into account both relay type and functional versus 
calibration testing. Entergy does not object to the development of 
maximum allowable maintenance intervals provided that they are 
developed in NERC's Reliability Standards development process.
    1474. FirstEnergy and ISO-NE suggest that PRC-005-1, PRC-008-0, 
PRC-011-0 and PRC-017-0 should be combined into a single Reliability 
Standard relating to the maintenance of protection and control 
equipment.
ii. Commission Determination
    1475. For the reasons stated in the NOPR, the Commission approves 
Reliability Standard PRC-005-1 as mandatory and enforceable.
    1476. In addition, for the reasons discussed in the NOPR, the 
Commission directs the ERO to develop a modification to PRC-005-1 
through the

[[Page 16555]]

Reliability Standards development process that includes a requirement 
that maintenance and testing of a protection system must be carried out 
within a maximum allowable interval that is appropriate to the type of 
the protection system and its impact on the reliability of the Bulk-
Power System. We further direct the ERO to consider FirstEnergy's and 
ISO-NE's suggestion to combine PRC-005-1, PRC-008-0, PRC-011-0 and PRC-
017-0 into a single Reliability Standard through the Reliability 
Standards development process.
f. Development and Documentation of Regional UFLS Programs (PRC-006-0)
    1477. PRC-006-0 ensures the development of a regional UFLS \385\ 
program that will be used as a last resort to preserve the Bulk-Power 
System during a major system failure that could cause system frequency 
to collapse. PRC-006-0 requires the regional reliability organization 
to develop, coordinate, document and assess UFLS program design and 
effectiveness at least every five years.
---------------------------------------------------------------------------

    \385\ Underfrequency load shedding.
---------------------------------------------------------------------------

    1478. In the NOPR, the Commission identified PRC-006-0 as a fill-
in-the-blank standard. The NOPR stated that because the regional 
procedures had not been submitted, the Commission would not propose to 
approve or remand PRC-006-0 until the ERO submits the additional 
information. The Commission commends the ERO and regions' initiative, 
outlined in the Reliability Standards Work Plan, in adopting an 
integrated and coordinated approach to protection for generators, 
transmission lines and UFLS and UVLS \386\ programs as part of its work 
on fill-in-the-blank Reliability Standards.\387\
---------------------------------------------------------------------------

    \386\ Undervoltage load shedding.
    \387\ NOPR at P 367.
---------------------------------------------------------------------------

i. Comments
    1479. APPA agrees with the Commission's proposed course of action. 
It suggests that in completing this Reliability Standard, NERC should 
strive for greater consistency on an Interconnection-wide basis through 
the use of ``base procedures'' for each Interconnection.
ii. Commission Determination
    1480. For the reasons stated in the NOPR, the Commission will not 
approve or remand PRC-006-0.
    1481. The Commission understands that UFLS, when properly 
coordinated with the dynamic response of the Bulk-Power System, is one 
of the safety nets that safeguards the system from cascading events, 
assuming it is properly coordinated with the dynamic response of the 
system. Until this Reliability Standard is submitted to the Commission 
for approval, we do not expect any lapse in the compliance with this 
Reliability Standard. As we stated in the NOPR, it is important that 
the existing regional reliability organizations continue to fulfill 
their current roles during this time of transition. The Commission 
expects that this function will pass from the regional reliability 
organization to the Regional Entity after they are approved.
g. Assuring Consistency With Regional UFLS Program Requirements (PRC-
007-0)
    1482. PRC-007-0 requires transmission owners, transmission 
operators, LSEs and distribution providers to provide, and annually 
update, their underfrequency data to facilitate the regional 
reliability organization's maintenance of the UFLS program database.
    1483. In the NOPR, the Commission proposed to approve PRC-007-0 as 
mandatory and enforceable.
i. Comments
    1484. APPA agrees that PRC-007-0 is sufficient for approval as a 
mandatory and enforceable Reliability Standard. However, it states that 
actual enforcement cannot take place until PRC-006-0 becomes effective. 
ISO-NE and ISO/RTO Council state that PRC-007-0 should not be approved 
because it refers to PRC-006-0, which we are not approving or remanding 
at this time.
ii. Commission Determination
    1485. For the reasons stated in the NOPR, the Commission approves 
Reliability Standard PRC-007-0 as mandatory and enforceable.
    1486. We are not persuaded by APPA, ISO/RTO Council and ISO-NE that 
PRC-007-0 cannot be acted on because it relies on PRC-006-0. We 
proposed to not approve or remand PRC-006-0 partly because it applies 
to a regional reliability organization. The Commission was not 
persuaded that a regional reliability organization's compliance with a 
Reliability Standard can be enforced as NERC proposed.\388\ That is not 
the case with PRC-007-0, which applies to transmission owners, 
transmission operators, distribution providers and LSEs. Since PRC-007-
0 is an existing Reliability Standard that has been followed on a 
voluntary basis, transmission owners, transmission operators, 
distribution providers and LSEs are generally aware of its 
requirements. As stated in the Common Issues section, a reference to an 
unapproved Reliability Standard may be considered in an enforcement 
action, but is not a reason to delay approving and enforcing this 
Reliability Standard. The Commission expects that the data will be sent 
to the Regional Entities (instead of the regional reliability 
organizations) after they are approved.
---------------------------------------------------------------------------

    \388\ NOPR at P 56-57.
---------------------------------------------------------------------------

h. Underfrequency Load Shedding Equipment Maintenance Programs (PRC-
008-0)
    1487. PRC-008-0 requires transmission owners and distribution 
providers to implement UFLS equipment maintenance and testing programs 
and provide program results to the regional reliability organization.
    1488. In the NOPR, the Commission proposed to approve Reliability 
Standard PRC-008-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to PRC-008-
0 that includes a requirement that maintenance and testing of UFLS 
programs must be carried out within a maximum allowable interval 
appropriate to the relay type and the potential impact on the Bulk-
Power System.
i. Comments
    1489. Entergy states that it does not object to NERC's development 
of maximum allowable maintenance intervals for the purpose of 
evaluating protection system and control programs provided that they 
are developed in NERC's Reliability Standards development process. 
FirstEnergy states that NERC should establish a maximum maintenance 
interval for protection system equipment and a ``national limitation 
taking into account both relay type and functional versus calibration 
testing.''
    1490. ISO-NE and ISO/RTO Council contend that the Commission should 
not approve PRC-008-0 until it approves PRC-006-0, which the Commission 
has identified as a fill-in-the-blank standard. Similarly, APPA 
contends that PRC-008-0 cannot be enforced until PRC-006-0 has become 
effective and the required regional UFLS program documentation has been 
submitted by the applicable Regional Entity. It also notes that the 
applicability of PRC-008-0 is limited to transmission owners and 
distribution providers who are required by their regional reliability 
organization to have a UFLS program.

[[Page 16556]]

ii. Commission Determination
    1491. FirstEnergy and Entergy agree with the Commission's proposed 
directive, whereas APPA suggests that the need for the proposal should 
be established first via the Reliability Standards development process.
    1492. We disagree with ISO/RTO Council and others that approval or 
enforcement of PRC-008-0 is linked to approval of PRC-006-0. PRC-008-0 
requires that a ``transmission provider or distribution provider with a 
UFLS program (as required by its Regional Reliability Organization) 
shall have a UFLS equipment and maintenance testing program in place.'' 
\389\ PRC-006-0 requires each regional reliability organization to 
develop, coordinate and document a UFLS program that includes specified 
elements. Again, we proposed to neither approve nor remand PRC-006-0 
because it applies to a regional reliability organization and the 
Commission was not persuaded that a regional reliability organization's 
compliance with a Reliability Standard can be enforced as proposed by 
NERC.\390\ That is not the case with PRC-008-0, which applies to 
transmission owners and distribution providers. Since PRC-008-0 is an 
existing Reliability Standard that has been followed on a voluntary 
basis, transmission owners and distribution providers are aware whether 
they are required to have a UFLS program in place. We approve PRC-008-0 
as mandatory and enforceable because it requires entities to have 
equipment maintenance and testing of their UFLS programs. As stated in 
the Common Issues section, a reference to an unapproved Reliability 
Standard may be considered in an enforcement action, but is not a 
reason to delay approving and enforcing this Reliability Standard. The 
Commission expects that the program results will be sent to the 
Regional Entities (instead of the regional reliability organizations) 
after they are approved.
---------------------------------------------------------------------------

    \389\ See PRC-008-0, Requirement R1.
    \390\ NOPR at P 56-57.
---------------------------------------------------------------------------

    1493. The Commission approves Reliability Standard PRC-008-0 as 
mandatory and enforceable. In addition, the Commission directs the ERO 
to develop a modification to PRC-008-0 through the Reliability 
Standards development process that includes a requirement that 
maintenance and testing of a protection system must be carried out 
within a maximum allowable interval that is appropriate to the type of 
the protection system and its impact on the reliability of the Bulk-
Power System.
i. UFLS Performance Following an Underfrequency Event (PRC-009-0)
    1494. PRC-009-0 ensures that the performance of a UFLS system is 
analyzed and documented following an underfrequency event by requiring 
the transmission owner, transmission operator, LSE and distribution 
provider to document the deployment of their UFLS systems in accordance 
with the regional reliability organization's program.
    1495. In the NOPR, the Commission proposed to approve Reliability 
Standard PRC-009-0 as mandatory and enforceable.
i. Comments
    1496. APPA agrees that PRC-009-0 is sufficient for approval as a 
mandatory and enforceable Reliability Standard. However, it states that 
actual enforcement cannot take place until pending PRC-006-0 becomes 
effective and notes that the applicability of PRC-009-0 is limited to 
entities that own or operate a UFLS program recognized by their 
regional reliability organization.
    1497. ISO-NE and ISO/RTO Council contend that the Commission should 
not approve PRC-009-0 until it approves PRC-006-0, which the Commission 
has identified as a fill-in-the-blank standard.
ii. Commission Determination
    1498. For the reasons stated in the NOPR, the Commission approves 
Reliability Standard PRC-009-0 as mandatory and enforceable.\391\
---------------------------------------------------------------------------

    \391\ NOPR at P 877-80.
---------------------------------------------------------------------------

    1499. We disagree with ISO/RTO Council and others that approval or 
enforcement of PRC-009-0 is linked to approval of PRC-006-0. PRC-009-0 
ensures that the performance of a UFLS system is analyzed and 
documented following an underfrequency event by requiring the 
transmission owner, transmission operator, LSE, and distribution 
provider to document the deployment of their UFLS operations. PRC-006-0 
requires each regional reliability organization to develop, coordinate 
and document a UFLS program that includes specified elements. We 
proposed to neither approve nor remand PRC-006-0 because it applies to 
a regional reliability organization and the Commission was not 
persuaded that a regional reliability organization's compliance with a 
Reliability Standard can be enforced as NERC proposed.\392\ That is not 
the case with PRC-009-0, which applies to transmission owners, 
transmission operators, LSEs and distribution providers with UFLS 
systems. Since PRC-009-0 is an existing Reliability Standard that has 
been followed on a voluntary basis, entities are aware whether they are 
required to have a UFLS program in place. Reporting on their UFLS 
programs therefore should not be burdensome. As stated in the Common 
Issues section, a reference to an unapproved Reliability Standard may 
be considered in an enforcement action, but is not a reason to delay 
approving and enforcing this Reliability Standard. The Commission 
expects this documentation will be sent to the Regional Entities 
(instead of the regional reliability organizations) after they are 
approved.
---------------------------------------------------------------------------

    \392\ NOPR at P 56-57.
---------------------------------------------------------------------------

j. Assessment of the Design and Effectiveness of UVLS Program (PRC-010-
0)
    1500. PRC-010-0 requires transmission owners, transmission 
operators, LSEs and distribution providers to periodically conduct and 
document an assessment of the effectiveness of their UVLS program at 
least every five years or as required by changes in system conditions. 
The assessment must be conducted with the associated transmission 
planner and planning authority.
    1501. In the NOPR, the Commission proposed to approve Reliability 
Standard PRC-010-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to PRC-010-
0 that requires that an integrated and coordinated approach be included 
in all protection systems on the Bulk-Power System, including 
generators and transmission lines, generators' low voltage ride-through 
capabilities and UFLS and UVLS programs.
    1502. The Commission commends the initiative and efforts that have 
been taken by NERC and the industry in addressing UVLS requirements as 
recommended by the Blackout Report.
i. Comments
    1503. APPA agrees that PRC-010-0 should be approved. While APPA 
agrees and that NERC should re-examine this Reliability Standard to 
determine whether a more integrated and coordinated approach should be 
included in protection systems on the Bulk-Power System, it also asks 
the Commission not to require a specific approach to UVLS and other 
protection systems. According to APPA, NERC should strive for greater 
consistency on an Interconnection-wide basis through

[[Page 16557]]

the use of a coordinated protection system for the Bulk-Power System in 
each Interconnection.
    1504. ISO-NE generally supports approval of PRC-010-0, but opposes 
the Commission's directive to modify the Reliability Standard to 
include an integrated and coordinated approach in all protection 
systems, particularly for UVLS and UFLS, programs, because such 
integration cannot be technologically accomplished.
    1505. FirstEnergy indicates that UVLS is primarily designed to 
address localized problems, and therefore requiring the universal 
coordination of UVLS across the grid does not make sense. FirstEnergy 
states that it is not clear what type of coordination would be useful 
for a UVLS program.
ii. Commission Determination
    1506. We agree with APPA's comments and reiterate that the directed 
modification should be developed in the Reliability Standards 
development process. With regard to APPA's concerns, while we direct 
the ERO to develop modifications that would require an integrated and 
coordinated approach to protection systems, we do not direct a specific 
approach to accomplish such integration and coordination. Rather, the 
ERO should develop an appropriate approach utilizing the Reliability 
Standards development process.
    1507. With regard to ISO-NE's disagreement on integration of 
various system protections ``because such integration cannot be 
technologically accomplished'', we note that the evidence collected in 
the Blackout Report indicates that ``the relay protection settings for 
the transmission lines, generators and underfrequency load shedding in 
the northeast may not be entirely appropriate and are certainly not 
coordinated and integrated to reduce the likelihood and consequence of 
a cascade--nor were they intended to do so.'' In addition, the Blackout 
Report stated that one of the common causes of major outages in North 
America is a lack of coordination on system protection. The Commission 
agrees with the protection experts who participated in the 
investigation, formulated Blackout Recommendation No. 21 and 
recommended that UVLS programs have an integrated approach.\393\
---------------------------------------------------------------------------

    \393\ ``Recommend that NERC determine the goal and principles 
needed to establish an integrated approach to relay protection for 
generators and transmission lines and the use of underfrequency and 
undervoltage load shedding programs.'' Blackout Report at 159.
---------------------------------------------------------------------------

    1508. Regarding FirstEnergy's question of whether universal 
coordination among UVLS programs that address local system problems 
makes sense, we believe that PRC-010-0's objective in requiring an 
integrated and coordinated approach is to address the possible adverse 
interactions of these protection systems among themselves and to 
determine whether they could aggravate or accelerate cascading events. 
We do not believe this Reliability Standard is aimed at universal 
coordination among UVLS programs that address local system problems.
    1509. As identified in the NOPR,\394\ NERC is continuing to develop 
an integrated and coordinated approach to protection for generators, 
transmission lines and UFLS and UVLS programs within its work on the 
fill-in-the-blank proposed Reliability Standards.
---------------------------------------------------------------------------

    \394\ NOPR P 883.
---------------------------------------------------------------------------

    1510. We appreciate MEAG's feedback to our response in the NOPR. 
For the reasons discussed in the NOPR,\395\ as well as our explanation 
above, the Commission approves Reliability Standard PRC-010-0 as 
mandatory and enforceable. In addition, the Commission directs the ERO 
to develop a modification to PRC-010-0 through the Reliability 
Standards development process that requires that an integrated and 
coordinated approach be included in all protection systems on the Bulk-
Power System, including generators and transmission lines, generators' 
low voltage ride-through capabilities, and UFLS and UVLS programs.
---------------------------------------------------------------------------

    \395\ Id. P 891-92.
---------------------------------------------------------------------------

 k. UVLS System Maintenance and Testing (PRC-011-0)
    1511. PRC-011-0 requires transmission owners and distribution 
providers to implement their UVLS equipment maintenance and testing 
programs and provide program results to regional reliability 
organizations.
    1512. In the NOPR, the Commission proposed to approve PRC-011-0 as 
mandatory and enforceable. In addition, the Commission proposed to 
direct NERC to submit a modification to PRC-011-0 that includes a 
requirement that maintenance and testing of UVLS programs must be 
carried out within a maximum allowable interval appropriate to the 
relay type and the potential impact on the Bulk-Power System.
i. Comments
    1513. APPA suggests that, instead of a Commission directive, NERC 
should be directed to consider whether this standard is needed to 
address the Commission's concern about periodic testing of UVLS 
equipment.
    1514. FirstEnergy comments that NERC should establish a maximum 
maintenance interval for protection system equipment, and a ``national 
limitation taking into account both relay type and functional versus 
calibration testing.'' Entergy states that it does not object to NERC's 
development of maximum allowable maintenance intervals for the purpose 
of evaluating protection system and control programs.
ii. Commission Determination
    1515. The Commission approves Reliability Standard PRC-011-0 as 
mandatory and enforceable. In addition, we direct the ERO to develop 
modifications to the Reliability Standard through the Reliability 
Standards development process as discussed below.
    1516. The Commission disagrees with APPA that the decision whether 
a modification is needed should be established first by the ERO in its 
Reliability Standards development process. Our direction identifies an 
appropriate goal necessary to assure the reliable operation of the 
Bulk-Power System. The details should be developed through the 
Reliability Standards development process.
    1517. The Commission believes that the proposal is presently part 
of the process. The Commission approves Reliability Standard PRC-011-0 
as mandatory and enforceable. In addition, the Commission directs the 
ERO to submit a modification to PRC-011-0 through the Reliability 
Standards development process that includes a requirement that 
maintenance and testing of a protection system must be carried out 
within a maximum allowable interval that is appropriate to the type of 
the protection system and its impact on the reliability of the Bulk-
Power System.
l. Special Protection System Review Procedure (PRC-012-0)
    1518. PRC-012-0 requires regional reliability organizations to 
ensure that all special protection systems \396\ are properly designed, 
meet performance requirements and are coordinated with other protection 
systems.
---------------------------------------------------------------------------

    \396\ A special protection system is designed to automatically 
take corrective actions to protect a particular system under both 
abnormal and predetermined conditions, excluding the coordinated 
tripping of circuit breakers to isolate faulted components, which is 
typically the purpose of other protection devices.
---------------------------------------------------------------------------

    In the NOPR, the Commission identified PRC-012-0 as a fill-in-the-
blank standard. The NOPR stated that

[[Page 16558]]

because the regional review procedures on special protection systems 
have not been submitted, the Commission would not propose to approve or 
remand PRC-012-0 until the ERO submits the additional information.
i. Comments
    1520. APPA agrees with the Commission's proposed course of action. 
It further suggests that NERC, in completing PRC-012-0, should strive 
for greater consistency on an Interconnection-wide basis through the 
use of ``base procedures'' for each Interconnection.
ii. Commission Determination
    1521. For the reasons stated in the NOPR, the Commission will not 
approve or remand PRC-012-0. The Commission urges the ERO should 
consider APPA's suggestions in the Reliability Standards development 
process.
m. Special Protection System Database (PRC-013-0)
    1522. PRC-013-0 ensures that all special protection systems are 
properly designed, meet performance requirements and are coordinated 
with other protection systems by requiring the regional reliability 
organization to maintain a database of information on special 
protection systems.
    1523. In the NOPR, the Commission identified PRC-013-0 as a fill-
in-the-blank standard. The NOPR stated that because the regional 
procedures on maintaining special protection system databases have not 
been submitted, the Commission would not approve or remand PRC-013-0 
until the ERO submits the additional information.
i. Comments
    1524. APPA agrees with the Commission's proposed course of action. 
It suggests further that in completing PRC-013-0, NERC should strive 
for greater consistency on an Interconnection-wide basis through the 
use of ``base procedures'' for each Interconnection.
ii. Commission Determination
    1525. For the reasons stated in the NOPR, the Commission will not 
approve or remand PRC-013-0. The ERO should consider APPA's suggestions 
in the Reliability Standards development process.
n. Special Protection System Assessment (PRC-014-0)
    1526. PRC-014-0 ensures that special protection systems are 
properly designed, meet performance requirements and are coordinated 
with other protection systems by requiring the regional reliability 
organization to assess and document the operation, coordination and 
compliance with NERC Reliability Standards and effectiveness of special 
protection systems at least once every five years.
    1527. In the NOPR, the Commission identified PRC-014-0 as a fill-
in-the-blank Reliability Standard. The NOPR stated that because the 
regional procedures on special protection system assessment had not 
been submitted, the Commission would not propose to approve or remand 
PRC-014-0 until the ERO submitted the additional information.
i. Comments
    1528. APPA agrees with the Commission's proposed course of action. 
It suggests further that in completing PRC-014-0, NERC should strive 
for greater consistency on an Interconnection-wide basis through the 
use of ``base procedures'' for each Interconnection.
ii. Commission Determination
    1529. For the reasons stated in the NOPR, the Commission will not 
approve or remand PRC-014-0. The ERO should consider APPA's suggestions 
in the Reliability Standards development process.
o. Special Protection System Data and Documentation (PRC-015-0)
    1530. Proposed Reliability Standard PRC-015-0 requires transmission 
owners, generator owners and distribution providers to maintain a 
listing, retain evidence of review and provide documentation of 
existing, new or functionally modified special protection systems.
    1531. In the NOPR, the Commission proposed to approve PRC-015-0 as 
mandatory and enforceable.
i. Comments
    1532. APPA agrees that PRC-015-0 is sufficient for approval as a 
mandatory Reliability Standard. However, it states that this 
Reliability Standard cannot be enforced until two pending Reliability 
Standards, PRC-012-0 and PRC-013-0, become effective. Similarly, ISO/
RTO Council and ISO-NE contend that the Commission should not approve 
PRC-15-0 until it approves PRC-012-0 and PRC-013-0, identified by the 
Commission as fill-in-the-blank standards.
ii. Commission Determination
    1533. We disagree with APPA, ISO/RTO Council and ISO-NE and 
conclude that PRC-015-0 should be approved and made enforceable on the 
effective date of this rulemaking. As mentioned above, PRC-012-0 and 
PRC-013-0 apply solely to regional reliability organizations. PRC-012 
is ``process'' oriented, as it requires the regional reliability 
organization to develop a review procedure that identifies information 
relevant to the regional reliability organization review of a special 
protection system. PRC-013-0 requires the regional reliability 
organization to maintain a database of information on special 
protection systems. PRC-015-0 requires a transmission owner, generator 
owner or distribution provider that owns a special protection system to 
maintain a list and provide data for existing and planned special 
protection systems as defined in PRC-013-0; and have evidence that the 
entity reviewed new or functionally modified special protection systems 
in accordance with the regional reliability organization procedures 
identified in PRC-012-0. As stated in the Common Issues section, a 
reference to an unapproved Reliability Standard may be considered in an 
enforcement action, but is not a reason to delay approving and 
enforcing this Reliability Standard. The Commission expects that the 
data will be sent to the Regional Entities (instead of the regional 
reliability organizations) after they are approved.
    1534. For the reasons discussed in the NOPR and above, the 
Commission concludes that Reliability Standard PRC-015-0 is just, 
reasonable, not unduly discriminatory or preferential and in the public 
interest and approves it as mandatory and enforceable.
p. Special Protection System Misoperations (PRC-016-0)
    1535. PRC-016-0 requires transmission owners, generator owners and 
distribution providers to provide the regional reliability organization 
with documentation, analyses and corrective action plans for 
misoperation of special protection systems.
    1536. In the NOPR, the Commission proposed to approve Reliability 
Standard PRC-016-0 as mandatory and enforceable. In addition, the 
Commission proposed to direct NERC to submit a modification to PRC-016-
0 that includes a requirement that maintenance and testing of these 
special protection system programs be carried out within a maximum 
allowable interval that is appropriate for the type of relays used and 
the impact of these special system protection systems on the 
reliability of the Bulk-Power System.

[[Page 16559]]

i. Comments
    1537. While APPA agrees that PRC-016-0 is sufficient for approval 
as a mandatory Reliability Standard, APPA, ISO/RTO Council and ISO-NE 
state that PRC-016-0 cannot be enforced until pending Reliability 
Standard PRC-012-0 has become effective.
    1538. FirstEnergy suggests that NERC clarify and provide guidance 
to transmission operators on the types of misoperations that have 
Interconnection-wide impacts and the types of misoperations that need 
reporting.
ii. Commission Determination
    1539. PRC-016-0 states that transmission owners, generator owners 
and distribution providers that own a special protection system must 
analyze the system operations and maintain a record of misoperations in 
accordance with the review procedure specified in PRC-012-0. As we 
explained above in the context of PRC-015-0, applicable entities are 
expected to comply with PRC-015-0, and the procedures specified in PRC-
012-0 will continue to be maintained by the regional reliability 
organizations pursuant to the ERO Rules of Procedure and the 
Commission's reliability information provision. We disagree with APPA, 
ISO/RTO Council and ISO-NE and conclude that PRC-016-0 is enforceable 
as of the effective date of this rulemaking. As stated in the Common 
Issues section, a reference to an unapproved Reliability Standard may 
be considered in an enforcement action, but is not a reason to delay 
approving and enforcing this Reliability Standard. The Commission 
expects that the plans will be sent to the Regional Entities (instead 
of the regional reliability organizations) after they are approved.
    1540. The Commission concludes that Reliability Standard PRC-016-0 
is just, reasonable, not unduly discriminatory or preferential, and in 
the public interest, and approves it as mandatory and enforceable. We 
observe that a maximum allowable interval for maintenance and testing 
of special protection systems is not relevant to PRC-016-0, where the 
primary purpose is to analyze and report all misoperations of special 
protection systems. The Commission, therefore, will not adopt the 
proposal to require the ERO to modify PRC-016-0 to include a 
requirement for a maximum allowable interval for maintenance and 
testing.
    1541. The Commission concludes that Reliability Standard PRC-016-0 
is just, reasonable, not unduly discriminatory or preferential and in 
the public interest, and approves it as mandatory and enforceable.
q. Special Protection System Maintenance and Testing (PRC-017-0)
    1542. PRC-017-0 requires transmission owners, generator owners and 
distribution providers to provide the regional reliability organization 
with documentation of special protection system maintenance, testing 
and implementation plans.
    1543. In the NOPR, the Commission proposed to approve PRC-017-0 as 
mandatory and enforceable. In addition, the Commission proposed to 
direct NERC to submit a modification to PRC-017-0 that: (1) Includes a 
requirement that maintenance and testing of these special protection 
system programs must be carried out within a maximum allowable interval 
that is appropriate to the type of relaying used and (2) identifies the 
impact of these special protection system programs on the reliability 
of the Bulk-Power System.
i. Comments
    1544. APPA agrees that PRC-017-0 is sufficient for approval as a 
mandatory and enforceable Reliability Standard. It also agrees that 
NERC and the industry should consider adoption of maximum allowable 
maintenance intervals. With respect to the Commission's second 
directive, APPA points out that the documentation of the test results 
will identify the impact of the special protection systems on the Bulk 
Electric System.
    1545. FirstEnergy states that NERC should establish a maximum 
maintenance interval for protective system equipment and a national 
limitation, taking into account both relay type and functional versus 
calibration testing. Entergy does not object to NERC's development of 
maximum allowable maintenance intervals for the purpose of evaluating 
protection system and control programs.
ii. Commission Determination
    1546. The commenters agree with the Commission's proposed directive 
on a maximum allowable interval for maintenance and testing of 
protection system equipment and we conclude that such a modification is 
beneficial. However, we agree with APPA's view on our second proposed 
directive assuming that the documentation is requested by either the 
regional reliability organization or NERC. Therefore, we will modify 
our direction to require that the documentation be routinely provided 
to the ERO or Regional Entity and not only when it is requested.
    1547. The Commission approves Reliability Standard PRC-017-0 as 
mandatory and enforceable. In addition, the Commission directs the ERO 
to develop a modification to PRC-017-0 through the Reliability 
Standards development process, that includes: (1) a requirement that 
maintenance and testing of a protection system must be carried out 
within a maximum allowable interval that is appropriate for the type of 
the protection system and (2) a requirement that documentation 
identified in Requirement R2 shall be routinely provided to the ERO or 
Regional Entity.
r. Disturbance Monitoring Equipment Installation and Data Reporting 
(PRC-018-1)
    1548. PRC-018-1 ensures that disturbance monitoring equipment is 
installed and disturbance data is reported in accordance with 
comprehensive requirements. PRC-018-1 contains several different 
effective dates for specific requirements.
    1549. In the NOPR, the Commission proposed to approve PRC-018-1 as 
mandatory and enforceable.
i. Comments
    1550. While APPA agrees that PRC-018-1 is sufficient for approval 
as a mandatory Reliability Standard, it contends that enforcement is 
not possible until PRC-002-0, a fill-in-the-blank standard, is 
effective. For the same reason, ISO/RTO Council and ISO-NE state that 
the Reliability Standard should not be approved or remanded at this 
time.
 ii. Commission Determination
    1551. The portion of PRC-018-1 that NERC proposes will become 
effective on the effective date of this Final Rule states that 
transmission owners and generator owners that own a disturbance 
monitoring system must assure that disturbance data is reported in 
accordance with PRC-002-1 to facilitate analyses of events. Applicable 
entities are expected to comply with PRC-018-1, and the procedures 
specified in PRC-002-1 will be provided pursuant to the data gathering 
provisions of the ERO's Rules of Procedure and the Commission's ability 
to obtain information pursuant to section 215 of the FPA and Part 39 of 
the Commission's regulations. Accordingly, we disagree with ISO/RTO 
Council and ISO-NE and conclude that the effective portions of PRC-018-
1 are enforceable as of the effective date of this rulemaking. As 
stated in the Common Issues section, a reference to an unapproved 
Reliability Standard may be

[[Page 16560]]

considered in an enforcement action, but is not a reason to delay 
approving and enforcing this Reliability Standard.
    1552. Accordingly, for reasons stated in the NOPR and above, the 
Commission approves Reliability Standard PRC-018-1 as mandatory and 
enforceable.
s. Undervoltage Load Shedding Program Database (PRC-020-1)
    1553. PRC-020-1 ensures that a regional database for UVLS programs 
is available for Bulk-Power System studies by requiring regional 
reliability organizations with any entities that have UVLS programs to 
maintain and annually update a database.
    1554. In the NOPR, the Commission identified PRC-020-1 as a fill-
in-the-blank standard. The NOPR stated that because the regional 
procedures on maintaining UVLS databases have not been submitted, the 
Commission would not propose to approve or remand PRC-020-0 until the 
ERO submits the additional information.
i. Comments
    1555. APPA disagrees that PRC-020-1 is a regional fill-in-the-blank 
Reliability Standard because it does not require regional procedures. 
However, APPA recognizes that PRC-020-1 requires the regional 
reliability organization to establish a database.
ii. Commission Determination
    1556. APPA is correct that the reason for not approving or 
remanding this Reliability Standard is because it applies solely to the 
regional reliability organization, and not because it is a fill-in-the-
blank standard. For this reason, the Commission will not approve or 
remand PRC-020-1.
t. Undervoltage Load Shedding Program Data (PRC-021-1)
    1557. PRC-021-1 ensures that data is supplied to support the 
regional UVLS database by requiring the transmission owner and 
distribution provider to supply data related to their systems and other 
related protection schemes to their regional reliability organization's 
database.
    1558. In the NOPR, the Commission proposed to approve PRC-021-1 as 
mandatory and enforceable.
i. Comments
    1559. APPA agrees that PRC-021-1 should be approved as a mandatory 
and enforceable Reliability Standard.
    1560. The ISO-NE and ISO/RTO Council contend that the Commission 
should refrain from approving PRC-021-1 until it approves PRC-020-1 
which the Commission has not approved or remanded.
ii. Commission Determination
    1561. For the reasons stated in the NOPR and above, the Commission 
approves PRC-021-1 as mandatory and enforceable. The referenced 
information will be provided pursuant to the data gathering provisions 
of the ERO's rules of procedure and the Commission's ability to obtain 
information pursuant to section 215 of the FPA and Part 39 of the 
Commission's regulations. As stated in the Common Issues section, a 
reference to an unapproved Reliability Standard may be considered in an 
enforcement action, but is not a reason to delay approving and 
enforcing this Reliability Standard.
u. Undervoltage Load Shedding Program Performance (PRC-022-1)
    1562. PRC-022-1 requires transmission operators, LSEs, and 
distribution providers to provide analysis, documentation and 
misoperation data on UVLS operations to the regional reliability 
organization.
    1563. In the NOPR, the Commission proposed to approve PRC-022-1 as 
mandatory and enforceable.
i. Comments
    1564. APPA agrees that PRC-022-1 should be approved as a mandatory 
and enforceable Reliability Standard.
    1565. FirstEnergy comments that Requirement R1.3 requires ``a 
simulation of the event, if deemed appropriate by the RRO'' and 
believes that the applicable entities such as transmission operators 
may not be able to simulate large system events. FirstEnergy suggests 
that Requirement R1.3 be revised to state that ``a simulation of the 
event, if deemed appropriate, and assisted by the [regional reliability 
organization].''
ii. Commission Determination
    1566. For the reasons discussed in the NOPR, the Commission 
concludes that Reliability Standard PRC-022-1 is just, reasonable, not 
unduly discriminatory or preferential, and in the public interest and 
approves it as mandatory and enforceable.
    1567. The Commission directs the ERO to consider FirstEnergy's 
suggestion in the Reliability Standards development process.
11. TOP: Transmission Operations
    1568. The eight Transmission Operations (TOP) Reliability Standards 
apply to transmission operators, generator operators and balancing 
authorities. The goal of these Reliability Standards is to ensure that 
the transmission system is operated within operating limits. 
Specifically, these Reliability Standards cover the responsibilities 
and decision-making authority for reliable operations, requirements for 
operations planning, planned outage coordination, real-time operations, 
provision of operating data, monitoring of system conditions, reporting 
of operating limit violations and actions to mitigate such violations. 
The Interconnection Reliability Operations and Coordination (IRO) group 
of Reliability Standards complement these proposed TOP Reliability 
Standards.
a. Reliability Responsibilities and Authorities (TOP-001-1)
    1569. The reliability goal of TOP-001-1 is to ensure that system 
operators have the authority to take actions and direct others to take 
action to maintain Bulk-Power System facilities within operating 
limits. TOP-001-1 requires that: (a) Transmission operating personnel 
must have the authority to direct actions in real-time; (b) the 
transmission operator, balancing authority, and generator operator must 
follow the directives of their reliability coordinator and (c) the 
balancing authority and generator operator must follow the directives 
of the transmission operator. In addition, the proposed Reliability 
Standard requires the transmission operator, balancing authority, 
generator operator, distribution provider and LSE to take emergency 
actions when directed to do so in order to keep the transmission system 
intact.
    1570. The Commission proposed in the NOPR to approve the 
Reliability Standard as mandatory and enforceable and to direct NERC to 
submit a modification to it that includes Measures and Levels of Non-
Compliance. On November 15, 2006, NERC submitted revisions to the 
Reliability Standard to include Measures and Levels of Non-
Compliance.\397\
---------------------------------------------------------------------------

    \397\ In its November 15, 2006, filing, NERC submitted TOP-001-
1, which supercedes the Version 0 Reliability Standard. TOP-001-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, TOP-001-1.
---------------------------------------------------------------------------

i. Comments
    1571. APPA notes that TOP-001-1, as revised to include Measures and 
Levels of Non-Compliance, fulfills the proposed directive in the NOPR. 
Accordingly, APPA agrees that the Commission should approve TOP-001-1 
as mandatory and enforceable.

[[Page 16561]]

    1572. California PUC asserts that TOP-001 should not be adopted 
unless the Commission provides for proper deference to existing 
authorities. It states that the requirements contained in TOP-001 are 
duplicative of what the CAISO already requires under its participating 
generator agreements.
    1573. FirstEnergy contends that TOP-001-1 contains ``reliability 
directives'' to be followed by various entities, but it has no clear 
line of authority for specified directives. This could lead to a 
generator receiving conflicting directions. FirstEnergy maintains that 
TOP-001-1 should establish a clear line of authority for issuing and 
complying with directives, but the reliability coordinator's 
instructions should govern in all instances.
    1574. In a similar vein, MEAG Power is concerned that the scope of 
``reliability directives'' contained in the Measures filed on November 
15, 2006 is unclear. For example, Measure M4 states that ``[e]ach 
Balancing Authority, Generator Operator, Distribution Provider and Load 
Serving Entity shall have and provide upon request evidence that * * * 
it complied with its Transmission Operator's reliability directives.'' 
While a directive by a transmission operator to a LSE to increase its 
planning reserve margin from 15 percent to 20 percent or reconductor a 
transmission line might be within the realm of possibilities, such 
``reliability directives'' would be inappropriate. MEAG Power therefore 
recommends an alternative definition of ``reliability directive'' that 
it believes would specify an appropriate range of directives.
    1575. MEAG Power also recommends a modification to TOP-001-1 
clarifying that an entity may be found non-compliant only if it fails 
to comply with a reliability directive issued to it by its host 
reliability coordinator. MEAG Power is concerned that the requirements 
as currently written may apply to entities outside a reliability 
coordinator's footprint.
    1576. FirstEnergy and California Cogeneration state that the 
definition of ``emergency'' is vague and should be clarified. 
FirstEnergy states TOP-001 does not specify who decides when there is 
an emergency. California Cogeneration states that under emergency 
conditions, it would be appropriate to require a QF to follow the 
directives of a reliability coordinator.\398\ But California 
Cogeneration argues that because of the broad definition of emergency, 
reliability coordinators could issue directives on a regular basis. 
California Cogeneration therefore proposes that the Reliability 
Standard clearly address which entities are exempt from such directives 
because they have no material impact on reliability.
---------------------------------------------------------------------------

    \398\ California Cogeneration notes that the curtailment of QFs 
in an emergency is allowed by 18 CFR 292.307.
---------------------------------------------------------------------------

    1577. FirstEnergy states that the term ``safety'' in Requirement R4 
should be clarified with respect to whether it means safety to the 
system/equipment, public safety or both.
    1578. Requirement R6 of TOP-001-1 requires an applicable entity to 
``render all available emergency assistance to others as requested.'' 
Regarding this provision, FirstEnergy maintains that NERC should 
clarify that all instructions should be subject to the reliability 
coordinator's direction and control to avoid causing unforeseen harm to 
other systems. Any entity requesting assistance must implement its 
emergency procedures before or in unison with assistance from other 
entities. However, FirstEnergy asserts that it is not clear how a 
responding entity will determine whether the requesting entity has 
implemented its comparable emergency procedures before the responding 
entity honors the request. FirstEnergy, therefore, states that TOP-001-
1 should require the requesting party to report on whether all of its 
emergency procedures were implemented as part of its request for 
emergency assistance.
    1579. Santa Clara states that, in some instances, notifying the 
reliability coordinator that a transmission operator is removing 
facilities from service may not be appropriate because the transmission 
owner traditionally notifies the balancing authority. Santa Clara 
therefore requests that Requirements R7.2 and R7.3 of the Reliability 
Standard be revised to provide that the transmission operator may 
notify the reliability coordinator or balancing authority.\399\
---------------------------------------------------------------------------

    \399\ Santa Clara makes a similar argument reagarding 
Requirement R3 of TOP-008-1.
---------------------------------------------------------------------------

ii. Commission Determination
    1580. The Commission approves TOP-001-1 as mandatory and 
enforceable. We address the concerns raised by commenters below.
    1581. While the Commission agrees with APPA that TOP-001-1 should 
be approved, it does not agree that the new Measures and Levels of Non-
Compliance fully address the Commission's concerns stated in the NOPR. 
The modified Reliability Standard does not contain Measures or Levels 
of Non-Compliance corresponding to Requirement 8. This Requirement 
deals with actions to restore real and reactive power balance. Given 
the importance of these matters to reliable operations, the Commission 
directs the ERO to provide Measures and Level of Non-Compliance for 
this Requirement.
    1582. We disagree with California PUC's assertion that the 
Commission should not adopt TOP-001-1 unless it commits to a policy of 
``appropriate deference'' to existing authorities. Approval of a 
continent-wide Reliability Standard should not be delayed because it 
may overlap with a local or regional program. Rather, stakeholders 
should raise related concerns in the ERO Reliability Standards 
development process. Moreover, section 215(i)(3) of the FPA provides 
that ``nothing in [section 215] shall be construed to preempt any 
authority of any State to take action to ensure the safety, adequacy, 
and reliability of electric service within that State, as long as such 
action is not inconsistent with any reliability standard.'' In any 
event, California PUC does not suggest how the Requirements in TOP-001-
1 and the provisions of CAISO's participating generator agreements will 
lead to conflicting outcomes. To the extent a potential conflict 
arises, we note that the CAISO's participating generator agreements are 
subject to Commission jurisdiction, and Sec.  39.6 of the Commission's 
regulations provides procedures for resolving conflicts between a 
requirement in a Reliability Standard and a provision of an agreement 
accepted for filing at the Commission.\400\
---------------------------------------------------------------------------

    \400\ See 18 CFR 39.6 (Conflict of a Reliability Standard with a 
Commission Order).
---------------------------------------------------------------------------

    1583. We agree with FirstEnergy that TOP-001-1 should establish a 
clear line of authority. Requirement R3 of Reliability Standard IRO-
001-0 clearly establishes the decision-making authority of the 
reliability coordinator to act and to direct actions to be taken by 
operating entities to preserve the integrity and reliability of the 
Bulk-Power System. When an entity is faced with conflicting directives, 
it must follow the reliability coordinator's directives because the 
reliability coordinator is the highest authority in matters affecting 
reliability of the Bulk-Power System. Therefore no changes are required 
to the Reliability Standard in this connection.
    1584. We agree with MEAG Power that a reliability directive to an 
LSE to increase its planning reserve to 15 percent or to reconductor 
its transmission line is outside the scope of

[[Page 16562]]

a TOP reliability directive. Reliability directives in the TOP group of 
Reliability Standards deal with operational directives and not planning 
directives.
    1585. We disagree with MEAG Power that an entity may have to comply 
with a reliability directive issued to it by a reliability coordinator 
other than its host reliability coordinator. The operating hierarchy 
embodied in the Reliability Standard gives the reliability coordinator 
responsibility and authority to issue reliability directives to its own 
transmission operators, balancing authorities and generator operators. 
These entities must comply with these directives as stated in 
Requirement R3 in TOP-001-1.\401\ An entity is only responsible for 
following directives from its host reliability coordinator unless 
authority is delegated to another reliability coordinator by the host 
reliability coordinator.
---------------------------------------------------------------------------

    \401\ The Requirement states in part that ``[e]ach Transmission 
Operator, Balancing Authority, and Generator Operator shall comply 
with reliability directives issued by the Reliability Coordinator* * 
*.''
---------------------------------------------------------------------------

    1586. We agree with FirstEnergy and California Cogeneration that 
the definition of ``emergency'' could be further clarified. We discuss 
this issue in this Final Rule in connection with Reliability Standard 
EOP-001-0 and conclude that emergency states need to be defined and 
that criteria for entering these states and authority for declaring 
them need to be specified. We therefore direct the ERO to modify the 
Reliability Standard accordingly. With respect to California 
Cogeneration's argument regarding exemptions from the requirement to 
respond to emergencies, the reliability coordinator must be in a 
position to take all necessary actions in response to an emergency and 
is in the best position to determine which entities should respond to 
its directives.
    1587. In response to FirstEnergy's request for clarification of the 
meaning of ``safety'' in the first sentence of Requirement R4, of TOP-
001-1 and whether it refers to safety to the system/equipment, public 
safety or both, the Commission notes that each term in the series set 
forth in this provision refers to a type of ``requirement.'' \402\ The 
provision clearly differentiates between the safety of persons and 
equipment requirements. Since equipment requirements are mentioned 
separately, safety must be read as referring to requirements related to 
safety of persons.
---------------------------------------------------------------------------

    \402\ Requirement R4 states: ``Each Distribution Provider * * * 
shall comply with all reliability directives * * * unless such 
actions would violate safety, equipment, regulatory or statutory 
requirements.''
---------------------------------------------------------------------------

    1588. With regard to FirstEnergy's proposal that the entity 
requesting emergency assistance be required to report that it has 
implemented all of its own emergency procedures as part of its request 
for emergency assistance, we believe that such reporting is not 
appropriate during an emergency situation. Requirement R6 of the 
Reliability Standard clearly specifies that entities must provide 
available emergency assistance provided the requesting entity has 
implemented its comparable emergency procedures. Given the nature of 
emergency situations where time is of the essence, compliance with this 
Requirement must be assessed after the fact as part of the compliance 
audit, and not during an emergency.
    1589. With respect to Santa Clara's proposal that Requirements R7.2 
and R7.3 be revised to provide that the transmission operator may 
notify the reliability coordinator or the balancing authority that it 
is removing facilities from service, the Commission directs the ERO to 
consider Santa Clara's comments in the Reliability Standards 
development process.
    1590. Accordingly, the Commission approves Reliability Standard 
TOP-001-1. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to TOP-001-1 through the Reliability Standards 
development process that: (1) Includes Measures and Levels of Non-
Compliance for Requirement R8 and (2) considers adding other Measures 
and Levels of Non-Compliance in the Reliability Standard.
b. Normal Operations Planning (TOP-002-2)
    1591. Reliability Standard TOP-002-2 requires transmission 
operators and balancing authorities to look ahead to the next hour, day 
and season, and have operating plans ready to meet any unscheduled 
changes in system configuration and generation dispatch. The 
Reliability Standard addresses the following matters: (1) Procedures to 
mitigate System Operating Limit (SOL) and Interconnection Reliability 
Operating Limit (IROL) violations; (2) verification of real and 
reactive reserve capabilities; (3) communications; (4) modeling; (5) 
information exchange and (6) data confidentiality restrictions. The 
goal of TOP-002-1 is to ensure that resources and operational plans are 
in place to enable system operators to maintain the Bulk-Power System 
in a reliable state.
    1592. In the NOPR, the Commission proposed to approve the 
Reliability Standard as mandatory and enforceable. In addition, the 
Commission proposed to direct that NERC submit a modification that: (1) 
Includes Measures and Levels of Non-Compliance; (2) deletes references 
to confidentiality agreements in Requirements R3 and R4, but addresses 
the issue separately to ensure that necessary protections are in place 
related to confidential information and (3) requires next-day analysis 
for all IROLs to identify and communicate control actions to system 
operators that can be implemented within 30 minutes following a 
contingency to return the system to a reliable operating state and 
prevent cascading outages.\403\
---------------------------------------------------------------------------

    \403\ In its November 15, 2006, filing, NERC submitted TOP-002-
2, which supercedes the earlier Reliability Standard. TOP-002-2 adds 
Measures and Levels of Non-Compliance to the Reliability Standard, 
and includes a modified Requirement R14. In this Final Rule, we 
review the November version, TOP-002-2.
---------------------------------------------------------------------------

    1593. The Commission also proposed to interpret Requirement R7 of 
the Reliability Standard as requiring that each balancing authority 
plan to meet capacity and energy reserve requirements, including 
deliverability/capability for any single contingency. Although the NERC 
glossary defines ``contingency,'' \404\ the Commission expressed 
concern in the NOPR that the phrase ``single contingency'' is open to 
interpretation, and ``deliverability'' is not defined. The Commission 
proposed in the NOPR to interpret contingency as discussed in 
connection with the TPL Reliability Standards and to interpret 
deliverability as the ability to deliver the output from generation 
resources to firm load without any reliability criteria violations for 
plausible generation dispatches.
---------------------------------------------------------------------------

    \404\ NERC defines ``contingency'' as ``the unexpected failure 
or outage of a system component, such as a generator, transmission 
line, circuit breaker, switch or other electric element.'' NERC 
Glossary at 3.
---------------------------------------------------------------------------

i. Comments
    1594. APPA states that NERC has added Measures for many but not all 
of the Requirements of TOP-002-2 and needs to develop Measures for 
Requirements R2, R3, R4, R12 and R17.
    1595. Entergy and MidAmerican support the Commission's proposal to 
delete references to confidentiality agreements from the requirements 
and state that different approaches must be explored to preserve the 
confidentiality of data. MidAmerican adds that NERC should adopt an 
administrative approach to keep the confidential information from being 
disclosed before the confidentiality provisions are

[[Page 16563]]

deleted from the requirements. LPPC asks the Commission to clarify that 
CEII remains confidential and states that without such clarification 
there is a danger that sensitive information related to the Bulk-Power 
System will become public.
    1596. FirstEnergy and Entergy express concerns regarding 
identifying all control actions in the next-day analysis for all IROLs 
to identify and communicate control actions to system operators that 
can be implemented within 30 minutes following a contingency. They 
contend that system conditions can change significantly between day-
ahead analysis and real-time operations, rendering potential control 
actions irrelevant. Therefore they state that operating entities should 
be held harmless for not having listed in advance control actions taken 
in the face of real-time contingencies resulting from unpredicted 
changing system conditions. APPA states that such requirements are not 
necessary given that system operators use state estimators and other 
tools to identify effective control actions that produce more accurate 
results than would be achieved through the proposed day-ahead analysis. 
APPA and Entergy assert that it should be left to NERC, as the 
technical expert charged with setting standards, to decide in the first 
instance whether such day-ahead analysis would be of sufficient benefit 
to justify requiring it.
    1597. MidAmerican is concerned that the Commission's proposal to 
interpret the phrase ``single contingency'' as a contingency that 
includes all multi-element pieces of the system that go out of service 
together in response to a single event is too restrictive on system 
operations. However, it also states that historically it has performed 
the studies in accordance with the Commission's proposal and will 
support that proposal in the interest of reliability. MidAmerican notes 
that where a multiple-element single contingency traverses neighboring 
systems, such contingencies must be coordinated with other systems. 
Further, it contends that the Commission's directive to have operating 
plans to meet any scheduled change in system configuration and 
generation dispatch seems burdensome if not impossible and requests 
clarification of the Commission's intent in this connection.
    1598. ISO-NE recommends that the reference to ``transmission 
service provider'' in Requirement R12 of TOP-002-2 should be replaced 
by ``transmission operator'' and/or ``transmission owner.'' \405\ It 
claims that such a change would be consistent with the definition of 
the term ``transmission service provider,'' which the NERC glossary 
defines as: ``[t]he entity that administers the transmission tariff and 
provides Transmission Service to Transmission Customers under 
applicable transmission service agreements.'' In performing this 
function, the transmission service provider provides a business service 
that entails executing contractual agreements with its customers to 
provide open access transmission service, whereas SOLs and IROLs are 
technical in nature and do not translate into transmission service 
provider functions. In contrast, transmission operators and 
transmission owners perform planning and operations functions and will 
need SOL and IROL data.
---------------------------------------------------------------------------

    \405\ Requirement R12 provides: ``The Transmission Service 
Provider shall include known SOLs and IROLs within its area and 
neighboring areas in the determination of transfer capabilities, in 
accordance with filed tariffs, and/or regional Total Transfer 
Capability and Available Transfer Capability calculation 
processes.''
---------------------------------------------------------------------------

    1599. NRC states that it is not clear whether TOP-002-2 considers 
the N-1 and the N-1-1 criteria consistent with TPL-002-0 and TPL-003-0, 
respectively. NRC is concerned about verifying that the Bulk-Power 
System will provide the necessary voltages to the auxiliary power 
system busses after a nuclear power plant trip. It suggests that 
knowledge and verification of significant generator characteristics are 
essential to this end, especially verification of real and reactive 
capabilities, automatic voltage regulator status and operating limits. 
NRC also proposes various revisions to TOP-002-2.
ii. Commission Determination
    1600. The Commission approves Reliability Standard TOP-002-2 as 
mandatory and enforceable. In addition, we direct the ERO to develop 
modifications to the Reliability Standard through the Reliability 
Standards development process as discussed below.
    1601. We are adopting our proposal regarding deletion of references 
to confidentiality agreements from the Requirements. As we explained in 
the NOPR, the effectiveness of a Reliability Standard should not be 
predicated upon the existence of a confidentiality agreement.\406\ The 
ERO should address the confidentiality provision separately to ensure 
that confidentiality of data is not compromised and CEII information 
remains confidential.
---------------------------------------------------------------------------

    \406\ NOPR at P 976.
---------------------------------------------------------------------------

    1602. As noted above, a number of commenters express concerns with 
the Commission's proposal to require a next-day analysis for all IROLs 
to identify and communicate control actions to system operators. 
Identification and communication of control actions that can be 
implemented within 30 minutes are required to ensure that system 
operators are aware of and have options available to respond to system 
conditions following the first contingency to restore the system to a 
secure state so that it can withstand the next contingency. In 
addition, the control actions identified in the next-day analysis may 
quite often be relevant, and informing the system operators of the 
control options earlier on would be helpful. While the operators may 
take other actions to preserve the system, they need to have at least 
one plan (control actions) that will preserve the system from 
cascading. We believe this addresses FirstEnergy's concern regarding 
whether compliance requires the use of only the control actions 
identified in the day-ahead analysis. In response to APPA's comment on 
the use of state estimators and other tools to identify effective 
control actions, we note that this capability will help operators in 
assessing system responses, but they will not identify the control 
actions system operators will need to take in real-time. Further, 
operators may not be aware of available control actions, or worse they 
may not have any control actions, other than firm load-shedding, 
available to adjust the system after a first contingency occurs. 
Therefore, we direct the ERO to modify Reliability Standard TOP-002-2 
to require the next-day analysis for all IROLs to identify and 
communicate control actions to system operators that can be implemented 
within 30 minutes following a contingency to return the system to a 
reliable operating state and prevent cascading outages.
    1603. With respect to NRC's comments, system operators must operate 
the system in front of them at all times to be capable of withstanding 
a critical contingency (N-1) without resulting in instability, 
uncontrolled separation or cascading failures. After this N-1 
contingency the operators must adjust the system as soon as possible 
and in no longer than 30 minutes so that the system can then withstand 
a new N-1 contingency. Further discussion of how this applies in the 
planning arena is presented in connection with the TPL group of 
Reliability Standards.

[[Page 16564]]

    1604. The Commission agrees with NRC that the minimum voltages at 
nuclear plant auxiliary power system buses should be assessed in next-
day analysis to ensure that adequate voltages can be maintained in 
accordance with the nuclear plant minimum voltage requirements. If this 
assessment projects that the minimum voltage requirements cannot be 
met, the transmission operators or balancing authorities must notify 
the nuclear power plant as soon as possible, but in no event later than 
the commencement of the next day's real-time operations. If during 
real-time operations the transmission operator cannot maintain the 
minimum voltage, pre- or post-contingency, it must inform the nuclear 
plant operator accordingly so that the appropriate corrective actions 
can be carried out by both the nuclear plant operator and the 
transmission operator. The Commission directs the ERO to modify 
Reliability Standard TOP-002-2 to address these two issues.
    1605. The Commission proposed in the NOPR that simulations must be 
consistent with the number of elements that will be removed from 
service as a result of the failure of a single element.\407\ 
MidAmerican states that it operates consistent with this proposal, in 
that it respects a single contingency as one that includes all multiple 
pieces of the elements that go out of service together in response to a 
single event. Even though MidAmerican states that the Commission's 
proposal is too restrictive on system operation, it supports the 
proposal in the interest of reliability. To do otherwise would not 
represent what actually happens in real-time operations to the 
detriment of Bulk-Power System reliability, which demonstrates the need 
to approach the issue as we propose. We discuss this issue further in 
connection with the TPL group of Reliability Standards, where we direct 
the ERO to modify the TPL Reliability Standards to simulate what 
actually happens in the physical system, including multiple element 
failures.
---------------------------------------------------------------------------

    \407\ NOPR at P 979.
---------------------------------------------------------------------------

    1606. We note with regard to MidAmerican's comment on operating 
plans to meet any scheduled change in system configuration and 
generation dispatch that we have not directed any action in this 
connection and therefore cannot provide any further clarification on 
this point. With regard to MidAmerican's comment on coordinated efforts 
with neighboring systems to deal with multiple element single 
contingencies, we note that such coordination is already required by 
IRO and TOP Reliability Standards.
    1607. Commenters did not take issue with the proposed 
interpretation of the term ``deliverability'' as ``the ability to 
deliver the output from generation resources to firm load without any 
reliability criteria violations for plausible generation dispatches.'' 
\408\ The Commission adopts this proposed interpretation. In order to 
ensure the necessary clarity, the term as used in Requirement R7 of 
TOP-002-2 should be understood in this manner.
---------------------------------------------------------------------------

    \408\ Id. at P 974.
---------------------------------------------------------------------------

    1608. With respect to the modifications to Requirement R12 of the 
Reliability Standard recommended by ISO-NE and NRC's comments on 
Measure M7 and a new Measure M11, the Commission directs the ERO to 
consider these matters in the Reliability Standards development 
process. In response to NRC's suggestion regarding periodic review of 
generators' reactive capability, we note that Reliability Standard MOD-
025-1 already requires periodic review of generators' reactive 
capability.
    1609. As we explained in the NOPR, TOP-002-2 serves an important 
purpose in ensuring that resources and operational plans are in place 
to enable system operators to maintain the Bulk-Power System in a 
reliable state. Further, the requirements set forth in the Reliability 
Standard are sufficiently clear and objective to provide guidance for 
compliance. Accordingly, the Commission approves Reliability Standard 
TOP-002-2. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to TOP-002-2 through the Reliability Standards 
development process that: (1) Deletes references to confidentiality 
agreements in Requirements R3 and R4, but addresses the issue 
separately to ensure that necessary protections are in place related to 
confidential information; (2) requires the next-day analysis for all 
IROLs to identify and communicate control actions to system operators 
that can be implemented within 30 minutes following a contingency to 
return the system to a reliable operating state and prevent cascading 
outages; (3) requires next-day analysis of minimum voltages at nuclear 
power plants auxiliary power busses and (4) requires simulation 
contingencies to match what will actually happen in the field.
c. Planned Outage Coordination (TOP-003-0)
    1610. Reliability Standard TOP-003-0 requires transmission 
operators that operate facilities greater than 100 kV, generator 
operators that operate facilities greater than 50 MW and balancing 
authorities to coordinate transmission and generator maintenance 
schedules. Where a conflict in maintenance schedule arises, the 
reliability coordinator is authorized to resolve the conflict.
    1611. The Commission proposed in the NOPR to approve Reliability 
Standard TOP-003-0 as mandatory and enforceable. The Commission also 
proposed to direct NERC to submit a modification to TOP-003-0 that: (1) 
Includes a requirement to communicate scheduled outages well in advance 
to ensure reliability and accuracy of ATC calculation and (2) makes any 
facility below the 100 kV or 50 MW thresholds that, in the opinion of 
the transmission operator, balancing authority, or reliability 
coordinator, will have a direct impact on the operation of Bulk-Power 
System subject to Requirement R1 for planned outage coordination.
    1612. In addition, the Commission noted in the NOPR that outage 
information is important to both reliable operation and to the 
calculation of ATC. This information is also needed to assure 
coordination of outages long before next day or current day operations. 
The Commission proposed that applicable scheduled outages be 
communicated to affected transmission operators and reliability 
coordinators with sufficient lead time to coordinate outages. The 
Commission then requested industry input on what constitutes sufficient 
lead time for planned outages.
i. Comments
    1613. MRO, APPA and others raise concerns requiring the proposed 
requirement to communicate scheduled outages ``well in advance.'' APPA 
cautions that TOP-003-0 was generally designed to ensure that 
transmission operators receive accurate and timely information about 
transmission and generation outages affecting ``next-day operations,'' 
rather than the longer term outage planning information. MRO states 
that requiring outage information well in advance reduces the entity's 
flexibility for other contingencies and changes. MRO also contends that 
the phrase ``well in advance'' is vague, not measurable, and may not be 
enforced fairly and consistently. FirstEnergy states that NERC should 
specify the meaning of ``well in advance'' through its Reliability 
Standards development process with industry input. MRO recommends that 
the time period for outage notification should be based on the size of 
the generating facility and voltage level of the transmission line so

[[Page 16565]]

that a larger facility has a longer lead time for outage notification.
    1614. While MISO agrees with the need for early notification of 
planned outages, it is concerned that an arbitrary lead time will cause 
entities to postpone needed maintenance to accommodate the timeline, 
thereby reducing the reliability of the Bulk-Power System.
    1615. LPPC states that business reasons often drive a longer lead 
time for outage planning to allow market participants to better 
understand the congestion and market impacts of the planned outage. 
LPPC believes that the Commission should exercise caution and avoid 
adopting a business practice as part of the Reliability Standard. 
Reliability concerns often dictate that an outage should not be planned 
and set in stone too far in advance because the circumstances may 
change. According to LPPC, the Commission should refrain from 
prescribing a lead time that would cut into an operator's flexibility, 
which is needed to respond to real-time situations.
    1616. In response to the Commission's question regarding the lead 
time for planned outages, MidAmerican states that although it believes 
that a requirement for extending the lead time will result in higher 
costs and less flexibility, a two-week advance notice for planned 
outages of 345 kV facilities and one-week advance notice for 161 and 69 
kV facilities is appropriate. TVA proposes one-week advance notice for 
all planned outages and recommends that TOP-003-0 should be modified to 
include breaker outages within the meaning of the facilities that are 
subject to advance notice for planned outages.
    1617. CAISO states that its current tariff provides for three days 
of lead time for providing outage information and that this is a 
standard practice throughout WECC. It maintains, however, that the 
three-day lead time is not sufficient for the needed review and 
coordination of outages. In fact, CAISO states that many ISOs and RTOs 
are moving toward a lead time of either 30 days or 45 days prior to the 
beginning of the outage month. CAISO contends that rather than basing 
the outage information on a certain kV level, the emphasis should be on 
facilities that may have a significant effect on congestion revenue 
rights resource adequacy.
    1618. Entergy and FirstEnergy support the proposed modification to 
include any facility below the thresholds that, in the opinion of the 
transmission operator, balancing authority, or reliability coordinator, 
will have a direct impact on the operation of the Bulk-Power System 
subject to Requirement R1 for planned outage coordination. They 
maintain that such a modification will provide the transmission 
operator much needed flexibility. APPA, on the other hand, opposes the 
proposal. APPA states that the Commission should allow the ERO in the 
first instance to consider whether to add this specific requirement to 
TOP-003-0. If the Commission is concerned that TOP-003-0 as it now 
stands might ``not include all facilities that have a significant 
impact on the operation of the Bulk-Power System,'' it should direct 
NERC to consider that issue on remand using its Reliability Standards 
development process.
    1619. Xcel notes that Requirement R4 of the Reliability Standard 
provides that each reliability coordinator should resolve any potential 
conflicts in scheduling of planned outages. Xcel argues that if a 
reliability coordinator requires an entity to move its planned outage 
to accommodate another entity's unplanned outage, the entity that 
agrees to move its planned outage to another time should receive 
compensation.
ii. Commission Determination
    1620. The Commission approves TOP-003-0 as mandatory and 
enforceable. We address the concerns raised by commenters below.
    1621. In Order No. 890, the Commission directed that information 
concerning ATC calculations be consistent and transparent.\409\ The 
timing of facility outages is one important piece of information in ATC 
calculations. In Order No. 890, the Commission directed that specific 
data be exchanged among transmission providers, including transmission 
planned and contingency outages, for the purpose of ATC modeling.\410\ 
Consistent with this determination in Order No. 890, the Commission 
directs the ERO to develop a modification to TOP-003-0 that requires 
the communication of scheduled outages to all affected entities well in 
advance to ensure reliability and accuracy of ATC calculations.\411\ We 
believe this addresses LPPC's concern regarding the interplay between 
reliability and business practices.
    1622. Several commenters raised concerns regarding the Commission's 
proposal to require outage information well in advance. Specifically, 
they argue that the term ``well in advance'' is vague, that the 
requirement would reduce flexibility and that it would cause entities 
to postpone needed maintenance work, thereby reducing reliability. In 
response to the Commission's request for comments on lead time for 
planned outages, entities provide information on current lead time 
practices indicating that lead times range from one week to 45 days. We 
direct the ERO to modify the Reliability Standard to incorporate an 
appropriate lead time for planned outages. The ERO should utilize the 
information filed by commenters in the Reliability Standards 
development process. In doing so the ERO should take into consideration 
the need for flexibility, as well the lead time required for 
coordination with other entities and outage assessments. Proper 
coordination will ensure that priority is given to needed maintenance 
work for critical facilities to ensure reliability.
---------------------------------------------------------------------------

    \409\ See Order No. 890 at P 68-69, 207-213.
    \410\ Id. at P 292.
    \411\ The Commission notes that PJM has developed an outage 
scheduling process in response to Commission directives to avoid the 
possibility of undue discrimination. http://www.pjm.com/committees/mrc/downloads/20060630-item-06-draft-manual-14b-changes.pdf. The 
outage scheduling process was developed through a stakeholder 
process and has been utilized in the entire PJM footprint for a 
number of years. PJM's outage scheduling program is one example of 
the type of program that should be implemented through the 
Reliability Standard.
---------------------------------------------------------------------------

    1623. With regard to TVA's request to include breaker outages 
within the meaning of the facilities that are subject to advance notice 
for planned outages, we direct the ERO to consider this suggestion in 
the Reliability Standards development process.
(a) Applicability
    1624. As noted above, the Commission proposed to direct the ERO to 
modify TOP-003-0 to make any facility below the thresholds that, in the 
opinion of the transmission operator, balancing authority, or 
reliability coordinator, will have a direct impact on the operation of 
Bulk-Power System subject to Requirement R1 for planned outage 
coordination.
    1625. Entergy and FirstEnergy support the proposed modification to 
include any facility below the threshold that in the opinion of the 
reliability coordinator, balancing authority or transmission operator 
will have a direct impact on the operation of the Bulk-Power System. On 
the other hand, APPA opposes this proposal and contends that the 
Commission should allow the ERO, as the expert entity charged with 
developing Reliability Standards, to consider whether to add this 
specific requirement. The Commission disagrees because registered 
entities below the thresholds currently defined in Requirement R1 of 
the Reliability Standard may have an impact on reliability and 
therefore should be required to submit data on their planned outages. 
The Commission therefore directs the ERO to modify the

[[Page 16566]]

Reliability Standard to require that any facility below the thresholds 
that, in the opinion of the transmission operator, balancing authority, 
or reliability coordinator will have a direct impact on the reliability 
of the Bulk-Power System be subject to Requirement R1 for planned 
outage coordination.
(b) Other Issues
    1626. In response to Xcel's proposal that entities that agree to 
reschedule their previously-approved planned outages to accommodate 
another entity's unplanned outage be compensated, the Commission notes 
that whereas rescheduling of the outage is a reliability matter, 
compensation is not and therefore is outside the scope of this 
proceeding.
(c) Summary of Commission Determination
    1627. Planned outage coordination is a necessary element of 
reliable operations, and TOP-003-0 promotes that goal. Accordingly, the 
Commission approves the Reliability Standard as mandatory and 
enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to TOP-003-0 through the Reliability Standards 
development process that: (1) Includes a new requirement to communicate 
longer term outages well in advance to ensure reliability and accuracy 
of ATC calculation; (2) makes any facility below the voltage thresholds 
that, in the opinion of the transmission operator, balancing authority, 
or reliability coordinator, will have a direct impact on the operation 
of Bulk-Power System, subject to Requirement R1 for planned outage 
coordination and (3) incorporates an appropriate lead time for planned 
outages as discussed above.
d. Transmission Operations (TOP-004-1)
    1628. This Reliability Standard requires transmission operators to 
operate the transmission system within SOL and IROL.\412\ The N-1 
operating criterion for the transmission system is also established in 
this Reliability Standard. It provides that operating configurations 
for which limits have not yet been determined should be treated as 
emergencies. The goal of the Reliability Standard is to maintain Bulk-
Power System facilities within limits, thereby protecting transmission, 
generation, distribution and customer equipment and preventing 
cascading failures of the interconnected grid.
    1629. The Commission proposed in the NOPR to approve the 
Reliability Standard as mandatory and enforceable. In addition, the 
Commission proposed to direct that NERC submit a modification that: (1) 
Includes Measures and Levels of Non-Compliance; (2) clarifies that the 
system should be restored as soon as possible, taking no more than 30 
minutes and (3) defines high risk conditions under which the system 
must be operated to respect multiple outages in Requirement R3. The 
Commission also proposed to direct the ERO to perform a survey of the 
prevailing operating practices and actual operating experiences 
surrounding drifting in and out of IROL limits.
    1630. Requirement R3 requires that each transmission operator 
shall, when practical, operate the system to respect multiple outages 
as specified by the regional reliability organization policy. The 
Commission noted in the NOPR that Requirement R3 does not define 
conditions under which multiple outages must be considered. The NOPR 
proposed to interpret such conditions ``to include high risk conditions 
such as hurricanes, ice storms or periods of high solar magnetic 
disturbances during which the probability of multiple outages 
approaches that of a single element outage.'' \413\
i. Comments
    1631. PG&E and APPA oppose a modification to the Reliability 
Standard that changes the requirement allowing operators to return the 
system to a reliable operating state within 30 minutes to a requirement 
that they do so as soon as possible and in no longer than 30 minutes. 
PG&E is concerned that during emergencies operators would be subject to 
uncertainty in complying with such a requirement, which could lead to 
overly hasty responses with a corresponding detrimental effect on 
reliability. PG&E states that to avoid the confusion and ambiguity from 
a subjective standard, the Commission and NERC should only clarify that 
operators should seek to return the system to a reliable operating 
state as soon as possible, but maintain the current requirement of 30 
minutes as stated in Requirement R4 of TOP-004-1. APPA states that if 
the Commission is concerned about the need to require a response time 
that is quicker than 30 minutes, it should direct the ERO to consider 
this issue as part of the Reliability Standards development process.
    1632. Entergy and MidAmerican support the Commission's proposal to 
have NERC conduct a survey and report the operating practices and 
actual experiences surrounding drifting in and out of IROL violations. 
MISO, on the other hand, opposes the survey because there are already 
requirements for reporting IROL violations elsewhere in the Reliability 
Standards. APPA proposes that the Commission should ask the ERO to 
determine if such information would improve reliable operations. If it 
is determined that such information will improve reliability, NERC 
should include this type of information in compliance violation 
reporting procedures.
    1633. LPPC and Xcel recommend that the Commission not require NERC 
to define in Requirement R3 the specific high-risk conditions under 
which the system must be operated to respect multiple outages. Xcel 
argues that it is unnecessary and impractical to attempt to define in 
advance all of the possible scenarios that will result in a high-risk 
condition. Not all high-risk conditions can be defined at any one time 
because changes in the system will introduce new high-risk conditions. 
Even if a list of high-risk conditions is developed, then, by 
definition, all other conditions not listed are excluded from 
consideration under this Reliability Standard. LPPC states that the 
proposed modification to deal with high-risk conditions is an 
unnecessarily prescriptive approach and could be detrimental to 
reliability by excluding scenarios that should be listed under this 
Requirement.
---------------------------------------------------------------------------

    \412\ In its November 15, 2006, filing, NERC submitted TOP-004-
1, which has an effective date of October 1, 2007, at which time it 
will supercede the Version 0 Reliability Standard. TOP-004-1 adds 
Measures and Levels of Non-Compliance to the Version 0 Reliability 
Standard. Because TOP-004-0 will be in effect until October 1, 2007 
and TOP-004-1 thereafter, we address both versions of the 
Reliability Standard.
    \413\ NOPR at P 997.
---------------------------------------------------------------------------

    1634. California PUC states that the Commission should not 
interpret hurricanes and ice storms as high risk conditions for 
studying multiple outages because events such as hurricanes and ice 
storms actually reduce the stress on the Bulk-Power System. This is 
because such events cause outages at the local distribution system 
level. California PUC maintains that since events such as hurricanes 
and ice storms rarely cause cascading outages, the proper approach for 
dealing with such situations is to focus on system restoration planning 
rather than including them in the contingency analysis that the 
proposed modification will require as a result of including such 
natural events within the meaning of high risk conditions.
    1635. Santa Clara states that Requirement R2 of the Reliability 
Standard should be revised to include

[[Page 16567]]

frequency monitoring in addition to the monitoring of voltage, real and 
reactive power flows.
ii. Commission Determination
    1636. The Commission approves TOP-004-0 as mandatory and 
enforceable until October 1, 2007, when TOP-004-1 will be mandatory and 
enforceable. We address the concerns raised by commenters below.
    1637. We adopt our proposal to require the ERO to clarify that the 
system should be restored as soon as possible, taking no more than 30 
minutes. Requirement R4 of TOP-004-1 (as well as the Version 0 
standard) provides that if a transmission operator enters an unknown 
state, i.e., any state for which valid operating limits have not been 
determined, operations should be restored to respect proven reliable 
power system limits within 30 minutes. However, as we stated in the 
NOPR, this language may be interpreted as a grace period to the 
detriment of reliability.\414\ The Commission, therefore, directs that 
the ERO develop a modification to Requirement R4 providing that the 
system should be restored to respect proven reliable power system 
limits as soon as possible and in no longer than 30 minutes. In 
response to PG&E's point that the phrase ``as soon as possible'' would 
add confusion, we note that Measure M1 in TOP-004-1 would measure 
performance against the 30-minute period specified in Requirement R4.
---------------------------------------------------------------------------

    \414\ See NOPR at P 995.
---------------------------------------------------------------------------

    1638. Entergy and MidAmerican support our proposal to direct the 
ERO to conduct a survey and report the operating practices and actual 
experiences surrounding drifting in and out of IROL violations. We 
disagree with MISO that TOP-007-0 covers reporting of ``drifting'' in 
and out of IROL violations because that Reliability Standard only 
requires reporting of IROL violations exceeding 30 minutes. With regard 
to APPA's suggestion that NERC should determine whether such 
information would improve reliable operations, we believe a survey is 
appropriate to determine actual practices, and simply modifying the 
compliance reporting procedures may not provide sufficient data to 
determine the reliability impacts of such practices and whether a 
modification to the Reliability Standard is appropriate. Accordingly, 
we direct the ERO to conduct a survey on the operating practices and 
actual experiences surrounding drifting in and out of IROL violations. 
Such a survey will provide factual support for whether additional 
modifications to the Reliability Standard are needed. The survey will 
also indicate whether additional vigilance on the part of compliance 
auditors is warranted in this area to ensure Bulk-Power System 
reliability.
    1639. As mentioned above, the Commission proposed to interpret 
``multiple outages'' in the context of Requirement R3 to include 
multiple element outages resulting from high-risk conditions such as 
hurricanes, wild fires, ice storms or periods of high solar magnetic 
disturbances during which the probability of multiple outages 
approaches that of a single element outage. This is not an exhaustive 
list but is meant to contain illustrative examples, and the Reliability 
Standards development process should develop a procedure to identify 
applicable high risk conditions. Under the high-risk conditions, the 
Commission understands that systems are normally operated in a more 
secure manner so that the Bulk-Power System can withstand multiple 
outages. These multiple outages exceed the normal N-1 criterion because 
the probability of multiple outages during high-risk conditions 
approaches that of a single outage during normal conditions. This does 
not preclude development of restoration plans as suggested by 
California PUC. Thus, we direct the ERO to develop a modification to 
the Reliability Standard that explicitly incorporates this 
interpretation with the details identified in the Reliability Standards 
development process.
    1640. We direct the ERO to consider Santa Clara's suggestion 
regarding changes to Requirement R2 in the Reliability Standards 
development process.
    1641. Accordingly, the Commission approves Reliability Standard 
TOP-004-0. Further, we approve TOP-004-1 so that it will become 
mandatory and enforceable on the stated effective date of October 1, 
2007. In addition, pursuant to section 215(d)(5) of the FPA and Sec.  
39.5(f) of our regulations, the Commission directs the ERO to develop a 
modification to the Reliability Standard through the Reliability 
Standards development process that: (1) Modifies Requirement R4 to 
state that the system should be restored to respect proven limits as 
soon as possible, taking no more than 30 minutes and (2) defines high 
risk conditions under which the system must be operated to respect 
multiple outages in Requirement R3, consistent with the discussion 
above.
    1642. In addition, the Commission directs the ERO to perform a 
survey of the prevailing operating practices and actual operating 
experiences surrounding drifting in and out of IROL limits as discussed 
more fully in this Final Rule in connection with the IRO group of 
Reliability Standards. As an example of the type of data that would be 
appropriate in the survey, we would expect to have reliability 
coordinators report any violation of an IROL not exceeding 30 minutes, 
its causes, the date and time of the violation, and the duration for 
which actual operations exceeded IROL to the ERO on a monthly basis for 
one year beginning two months after the effective date of the Final 
Rule. The ERO should report the results to the Commission in an 
informational filing within 18 months from the effective date of this 
Final Rule.
e. Operational Reliability Information (TOP-005-1)
    1643. Reliability Standard TOP-005-1 seeks to ensure that 
reliability information is shared among reliability coordinators, 
transmission operators and balancing authorities. It requires the 
transmission operator and the balancing authority to provide operating 
data to each other and to the reliability coordinator, and it provides 
a list of typical operating data that must be provided. TOP-005-1 also 
provides that each data recipient must execute a confidentiality 
agreement as a condition of receiving data from NERC's Interregional 
Security Network.\415\
---------------------------------------------------------------------------

    \415\ Interregional Security Network is a data exchange system 
that facilitates the exchange of real-time and other operational 
data among reliability coordinators, balancing authorities and 
transmission operators to help ensure reliable electric power system 
operations.
---------------------------------------------------------------------------

    1644. The Commission proposed in the NOPR to approve Reliability 
Standard TOP-005-1 as mandatory and enforceable. The Commission also 
proposed to direct NERC to submit a modification to TOP-005-1 that: (1) 
Includes information about the operational status of special protection 
systems and power system stabilizers in Attachment 1 and (2) deletes 
references to confidentiality agreements, but addresses the issue 
separately to ensure that necessary protections are in place related to 
confidential information.
i. Comments
    1645. FirstEnergy states that TOP-005-1 should also apply to 
transmission providers because some of the information listed in 
Attachment 1 to the Reliability Standard is in their possession. 
Attachment 1 should be modified so that it allows each entity to know 
what data it is expected to provide. As currently written, Attachment 1 
lists various entities that are supposed to provide data without

[[Page 16568]]

specifying who will provide which information. FirstEnergy states that 
transmission operators, for example, may not have all the information 
listed in item 1.5 of Attachment 1.
    1646. APPA and Entergy agree that TOP-005-1 should be modified to 
include information about the operational status of special protection 
systems and power system stabilizers in Attachment 1. However, APPA 
contends that the Commission's directive should be revised so that this 
change is developed through the Reliability Standards development 
process.
    1647. ISO-NE recommends that the reference to ``purchasing-selling 
entity'' in Requirement R4 should be replaced with ``generator owner, 
transmission owner, and LSE.'' \416\ It argues that since NERC's 
glossary defines the term ``purchasing-selling entity'' as ``[t]he 
entity that purchases or sells, and takes title to, energy, capacity, 
and Interconnected Operation services,'' many entities can fall within 
this category (e.g., commodity traders such as financial/power 
marketers) that may possess little or none of the operational or 
reliability data the host balancing authority and transmission operator 
need to conduct reliability assessments.
---------------------------------------------------------------------------

    \416\ Requirement R4 states: ``Each Purchasing-Selling Entity 
shall provide information as requested by its Host Balancing 
Authorities and Transmission Operators to enable them to conduct 
operational reliability assessments and coordinate reliable 
operations.''
---------------------------------------------------------------------------

    1648. A number of commenters discussed the Commission's proposal to 
delete references to confidentiality agreements in the Reliability 
Standard but to address the issue separately to ensure that necessary 
protections are in place related to confidential information. Those 
comments are summarized above in connection with the same proposal made 
by the Commission in the case of TOP-002-1.
ii. Commission Determination
    1649. For the reasons stated in the NOPR,\417\ we direct the ERO to 
develop a modification to TOP-005-1 through the Reliability Standards 
development process regarding the operational status of special 
protection systems and power system stabilizers in Attachment 1. 
Several commenters agree with this directive, and we believe that this 
information will provide a more comprehensive list in Attachment 1.
---------------------------------------------------------------------------

    \417\ NOPR at P 1005.
---------------------------------------------------------------------------

    1650. We are adopting our proposal regarding deletion of references 
to confidentiality agreements from the Requirements. Our discussion of 
this matter in connection with TOP-002-1 applies equally here.
    1651. The Commission directs the ERO to consider FirstEnergy's 
recommended modifications to Attachment 1 to the Reliability Standard 
and ISO-NE's recommended revision to Requirement R4 in the Reliability 
Standards development process.
    1652. Accordingly, the Commission approves Reliability Standard 
TOP-005-1. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to TOP-005-1 through the Reliability Standards 
development process that: (1) Includes information about the 
operational status of special protection systems and power system 
stabilizers in Attachment 1 and (2) deletes references to 
confidentiality agreements, but addresses the issue separately to 
ensure that necessary protections are in place related to confidential 
information.
f. Monitoring System Conditions (TOP-006-1)
    1653. TOP-006-1 requires operating personnel to continuously 
monitor essential Bulk-Power System parameters such as line flows, 
circuit breaker status, generator resources, relays, weather forecasts 
and frequency to ensure that the facilities do not exceed their 
operating limits.
    1654. The Commission proposed in the NOPR to approve the 
Reliability Standard as mandatory and enforceable.\418\ The Commission 
also proposed to direct NERC to submit a modification that: (1) 
Includes Measures and Levels of Non-Compliance; (2) includes a new 
Requirement related to the provision of a minimum set of analytical 
tools that will aid in situational awareness and (3) clarifies the 
meaning of ``appropriate technical information'' concerning protective 
relays.
---------------------------------------------------------------------------

    \418\ In its November 15, 2006 filing, NERC submitted TOP-006-1, 
which supersedes the Version 0 Reliability Standard. TOP-006-1 adds 
Measures and Levels of Non-Compliance to the Version 0 Reliability 
Standard. In this Final Rule, we review the November version, TOP-
006-1.
---------------------------------------------------------------------------

i. Comments
    1655. Dominion supports including a new requirement for a minimum 
set of analytical tools. It argues that such a requirement will ensure 
that operators have a minimum set of tools with which to perform their 
duties. The Reliability Standard should also specify metrics that can 
be audited, such as minimum availability times, so that these tools are 
adequately maintained. However, Alcoa states that requiring a minimum 
set of tools will be unduly onerous, especially to smaller balancing 
authorities and transmission operators. Although situational awareness 
tools, such as state estimators, are critical for an ISO and RTO, 
smaller balancing authorities and transmission operators should provide 
necessary data to the reliability coordinator that monitors a wide 
region using such tools.
    1656. Alcoa claims that developing additional capability at the 
balancing authority and transmission operator levels when such 
capability already exists at the reliability coordinator level will be 
redundant. Requiring state estimation for a small balancing area that 
is under an ISO would provide little benefit for grid reliability since 
the scope of the balancing area's visibility is limited.
    1657. APPA does not support the proposed requirement related to the 
provision of a minimum set of analytical tools and claims that 
inclusion of specific analytical tools is counterproductive because the 
tools become obsolete within two to five years due to technical 
advances. APPA states that deciding whether to add a new requirement 
for a minimum set of analytical tools should be left to NERC in the 
first instance. Similarly, TAPS argues that NERC should consider in the 
first instance whether minimum analytical tools are necessary and for 
what subset of generator operators and transmission operators.
    1658. LPPC maintains that the Commission should require NERC to 
list the capabilities required rather than specific tools because tools 
will change over time.
    1659. APPA states that the ERO's filing on November 15, 2006 
includes new Measures M1 through M6, which only measure Requirements 
R1, R2, R4, R5 and R7.
ii. Commission Determination
    1660. The Commission approves TOP-006-1 as mandatory and 
enforceable. In addition, the Commission directs the ERO to develop 
modifications to TOP-006-1 through the Reliability Standards 
development process, as discussed below.
    1661. We adopt our proposal to require the ERO to develop a 
modification related to the provision of a minimum set of analytical 
tools. In response to LPPC and others, we note that our intent was not 
to identify specific sets of tools, but rather the minimum capabilities 
that are necessary to enable operators to deal with real-time 
situations and to ensure reliable operation of the Bulk-Power System. 
In response to APPA that the inclusion of specific analytical tools is 
counterproductive because the tools

[[Page 16569]]

will become obsolete, we note that we are not seeking specific 
analytical tools, but rather minimum capabilities.
    1662. In regard to Alcoa's concern that this new Requirement would 
be unduly onerous, especially for smaller balancing authorities and 
transmission operators, the Commission's intent is not to subject 
smaller balancing authorities and transmission operators to the same 
requirements placed on larger balancing authorities and transmission 
operators. As part of the modification of this Reliability Standard to 
develop a new requirement for minimum capability for analytical tools, 
the ERO should take into account what would be required of smaller 
balancing authorities and transmission operators for the Reliable 
Operation of the Bulk-Power System, instead of applying the same 
requirements as are placed on other reliability entities such as 
reliability coordinators and larger balancing authorities and 
transmission operators.
    1663. We disagree with Alcoa that developing additional capability 
at the balancing authority and transmission operator levels when such 
capability already exists at the reliability coordinator level will be 
redundant. We are not seeking to duplicate the same capability for each 
reliability entity, but rather the new requirement should specify the 
minimum capability taking into account the role played by each entity. 
For example, a reliability coordinator may need to have access to state 
estimator and contingency analysis whereas a generator operator may not 
need these capabilities.\419\
---------------------------------------------------------------------------

    \419\ We note that TOP-006-0 applies to transmission operators, 
balancing authorities, generator operators and reliability 
coordinators.
---------------------------------------------------------------------------

    1664. No commenters addressed our proposal with respect to the 
meaning of ``appropriate technical information'' concerning protective 
relays in Requirement R3 of the Reliability Standard. To provide more 
clarity, criteria that define what ``appropriate technical 
information'' is necessary should be specified so that operators can 
make better informed decisions. An example of such information would be 
the allowable reclosing angle set in the existing relays and the 
maximum angle at specific points in the Bulk-Power System that would be 
acceptable to allow closing of lines during system restoration.
    1665. The ERO should consider APPA's comment regarding the missing 
Measures in the ERO's Reliability Standards development process.
    1666. Accordingly, the Commission approves Reliability Standard 
TOP-006-1. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, the Commission directs the ERO to 
develop a modification to TOP-006-1 through the Reliability Standards 
development process that: (1) Includes a new requirement related to the 
provision of minimum capabilities that are necessary to enable 
operators to deal with real-time situations and to ensure reliable 
operation of the Bulk-Power System and (2) clarifies the meaning of 
``appropriate technical information'' concerning protective relays.
g. Reporting SOL and IROL Violations (TOP-007-0)
    1667. TOP-007-0 requires that violations of SOL and IROL be 
promptly reported to the reliability coordinator so that it can direct 
corrective action and inform other affected systems. It also requires a 
transmission operator to mitigate an IROL violation as soon as possible 
but in no longer than 30 minutes. A transmission operator must take 
``all appropriate actions up to and including shedding firm load'' to 
return its system to a stable state within IROL. Finally, the 
Reliability Standard requires that the reliability coordinator take 
action to mitigate an SOL or IROL violation if the transmission 
operator's actions are not effective.
    1668. The Commission proposed in the NOPR to approve TOP-007-0 as 
mandatory and enforceable.
    1669. In the NOPR, the Commission solicited comment on potentially 
overlapping matters addressed in Reliability Standards TOP-007-0 and 
TOP-008-0.
i. Comments
    1670. NERC recognizes that there are some redundancies and awkward 
relationships among the various Reliability Standards, which are the 
result of the translation from the previous operating policies where 
each policy was treated as a separate set of concepts. NERC states that 
its 2007-2009 Reliability Standards Work Plan addresses work to be done 
to eliminate redundancies and better organize the Requirements across 
Reliability Standards so as to provide a more logical presentation.
    1671. APPA states that the concerns expressed in the NOPR about 
overlapping matters between TOP-007-0 and TOP-008-0 should be referred 
to the NERC Reliability Standards development process to better comport 
with the statutory division of responsibility. FirstEnergy and SoCal 
Edison state that Requirements R2 through R4 are clearly not reporting 
activities and should be combined with the requirements of TOP-008.
    1672. NRC states that some nuclear power plant voltage requirements 
would result in SOL, i.e., the nuclear power plant voltage limits would 
be an SOL as a result of the minimum and maximum voltages required at 
the nuclear power plant switchyard, which typically has a tighter 
operating band (a higher minimum and a lower maximum) than other nodes 
in the system. It therefore recommends adding a new requirement that 
states as follows: ``Following discovery of a potential contingency 
that could result in an SOL being exceeded at a nuclear power plant 
(e.g., at post-trip voltage), the transmission owner shall notify the 
nuclear power plant operator as soon as possible but not longer than 30 
minutes if the contingency has not been corrected.'' NRC also suggests 
modifying the Measures and Compliance sections and Table 1 to account 
for the new requirement, and provides specific language to be included 
in those places.
ii. Commission Determination
    1673. The Commission approves TOP-007-0 as mandatory and 
enforceable. We agree with APPA, FirstEnergy and SoCal Edison that the 
Reliability Standards would benefit from the elimination of overlapping 
matters in TOP-007-0 and TOP-008-1. The ERO indicates that it plans to 
address this as part of its Work Plan and this suffices.
    1674. NRC has raised some significant issues regarding the 
consideration of nuclear power plants voltage requirements. Consistent 
with our general approach in this Final Rule, we direct the ERO to 
consider NRC's comments in the Reliability Standards development 
process when addressing TOP-007-0 as part of its Work Plan.
    1675. Accordingly, the Commission approves Reliability Standard 
TOP-007-0 as mandatory and enforceable.
h. Response to Transmission Limit Violations (TOP-008-1)
    1676. TOP-008-1 requires a transmission owner to take immediate 
steps to mitigate SOL and IROL violations.
    1677. The Commission proposed in the NOPR to approve Reliability 
Standard TOP-008-0 as mandatory and enforceable. The Commission also 
proposed to direct that NERC submit a modification to TOP-008-0 that: 
(1) Includes Measures and Levels of Non-Compliance and (2) includes 
reliability

[[Page 16570]]

coordinators in the applicability section.\420\
---------------------------------------------------------------------------

    \420\ In its November 15, 2006, filing, NERC submitted TOP-008-
1, which supersedes the Version 0 Reliability Standard. TOP-008-1 
adds Measures and Levels of Non-Compliance to the Version 0 
Reliability Standard. In this Final Rule, we review the November 
version, TOP-008-1.
---------------------------------------------------------------------------

i. Comments
    1678. APPA questions whether TOP-008-1 should be modified to apply 
to reliability coordinators. It claims that the Requirement R3 simply 
mentions that the reliability coordinator will receive information 
provided by the transmission operator and does not play any substantive 
role under TOP-008-1. MISO notes that the reliability coordinators' 
responsibility related to IROL violations are outlined in connection 
with IRO Reliability Standards and the reasons for adding the 
reliability coordinator as applicable entity in multiple locations is 
unclear.
    1679. APPA states that NERC has not submitted a Measure for the 
Requirement R2 of the Reliability Standard. The new Measures M1 through 
M5 included in TOP-008-1 only measure Requirements R1, R3, and R4. In 
addition, the data retention and compliance levels reference Measures 
M1 through M5. Therefore, an entity subject to TOP-008-1 could arguably 
comply with Requirements R1, R3 and R4 and be in compliance with the 
entire Reliability Standard.
ii. Commission Determination
    1680. For the reasons stated in the NOPR,\421\ the Commission 
approves TOP-008-1 as mandatory and enforceable. We address the 
concerns raised by commenters below.
---------------------------------------------------------------------------

    \421\ See NOPR at P 1035-36.
---------------------------------------------------------------------------

    1681. We agree with APPA that the reliability coordinator merely 
receives information provided by the transmission operator and does not 
play any substantive role under TOP-008-1. We also agree with MISO that 
the reliability coordinators' responsibility related to IROL violations 
are outlined in connection with the IRO Reliability Standards and 
therefore there is no need to modify the applicability section of TOP-
008-1 to include the reliability coordinator.
    1682. The ERO should consider APPA's comment regarding the missing 
Measures in the ERO's Reliability Standards development process.
    1683. Accordingly, the Commission approves Reliability Standard 
TOP-008-1 as mandatory and enforceable.
12. TPL: Transmission Planning
    1684. The Transmission Planning (TPL) group of Reliability 
Standards consists of six Reliability Standards that are applicable to 
transmission planners, planning authorities and regional reliability 
organizations. These Reliability Standards are intended to ensure that 
the transmission system is planned and designed to meet an appropriate 
and specific set of reliability criteria. Transmission planning is a 
process that involves a number of stages including developing a model 
of the Bulk-Power System, using this model to assess the performance of 
the system for a range of operating conditions and contingencies, 
determining those operating conditions and contingencies that have an 
undesirable reliability impact, identifying the nature of potential 
options, and the need to develop and evaluate a range of solutions and 
selecting the preferred solution, taking into account the time needed 
to place the solution in service. The proposed TPL Reliability 
Standards address: (1) The types of simulations and assessments that 
must be performed to ensure that reliable systems are developed to meet 
present and future system needs \422\ and (2) the information required 
to assess regional compliance with planning criteria and for self-
assessment of regional reliability.\423\
---------------------------------------------------------------------------

    \422\ See TPL-001-0, TPL-002-0, TPL-003-0 and TPL-004-0.
    \423\ See TPL-005-0 and TPL-006-0.
---------------------------------------------------------------------------

    1685. The TPL group of Reliability Standards contains a table 
designated ``Table 1'' (Transmission System Standards--Normal and 
Emergency Conditions), which is a key part of this group of Reliability 
Standards. It lays out the system performance requirements for a range 
of contingencies grouped according to the number of elements forced out 
of service as a result of the contingency. For example: Category A 
applies to the normal system with no contingencies; Category B applies 
to contingencies resulting in the loss of a single element, defined as 
a generator, transmission circuit, transformer, single DC pole with or 
without a fault; Category C applies to a contingency resulting in loss 
of two or more elements, such as any two circuits on a multiple circuit 
tower line or both poles of a bi-polar DC line; while Category D 
applies to extreme contingencies resulting in loss of multiple 
elements, such as a substation or all lines on a right-of-way. The 
system performance expectations for Category C contingencies are lower 
than those for Category B contingencies, in that they allow unspecified 
amounts of planned or controlled loss of load.
a. General Issues
    1686. Commenters raise a number of issues that apply generally to 
Reliability Standards TPL-001-0 through TPL-004-0. These issues are 
related to the transmission planning process, sensitivity studies and 
critical system conditions, element-based versus event-based 
contingencies, spares strategy, and resource information for planning 
and sharing information with neighboring systems. We address these 
general issues here, and the conclusions reached will apply to our 
discussion of individual TPL Reliability Standards.
i. Transmission Planning Process
    1687. The Commission stated in the NOPR that the Reliability 
Standards are not intended to make the Bulk-Power System failure-
proof.\424\ In addition, we did not propose to modify the TPL 
Reliability Standards to require that the system be able to withstand 
all multiple-contingency and extreme contingency events without loss of 
load. Nonetheless, we stated that we believe that the planning-related 
Reliability Standards could be improved to better account for probable 
contingencies when conducting planning studies. Much of our proposal 
was consistent with the potential improvements NERC recognized in its 
comments on the Staff Preliminary Assessment. In addition, we noted 
that a number of regions currently utilize superior planning practices 
that may be characterized as ``best practices'' and are more stringent 
than the proposed TPL Reliability Standards.\425\ Accordingly, we 
proposed that the ERO submit to the Commission such regional 
differences in transmission planning criteria that are more stringent 
than those specified in the TPL group of Reliability Standards.
---------------------------------------------------------------------------

    \424\ NOPR at P 1042.
    \425\ Examples include practices cited in NERC's ``Examples of 
Excellence'' found in its Readiness Audits (available at http://www.nerc.com) and filings for jurisdictional utilities in Part 4 of 
FERC Form No. 715, Transmission Planning Reliability Criteria. 
Regional reliability organizations also specify requirements that 
exceed NERC Reliability Standards, such as WECC's Minimum Operating 
Requirement Criteria and the NPCC Document A-02--Basic Criteria for 
Design and Operation of Interconnected Power Systems.
---------------------------------------------------------------------------

(a) Comments
    1688. EEI and APPA strongly believe that the transmission planning 
processes performed under these Reliability Standards have served this 
nation extremely well. The Reliability Standards have evolved with 
changes in industry structure, computer and

[[Page 16571]]

communications technology, electric generation and transmission 
technology and a broad range of state and federal regulatory demands. 
EEI and APPA state that it is unclear whether the Commission is 
proposing a significant expansion of this reliability planning process, 
which would amount to a fundamental shift in the nature of that 
process, or whether the Commission is proposing a more specific 
description of today's comprehensive planning approach. EEI and APPA 
state that they can interpret the Commission's proposal either as 
suggesting that planning should support a robust and flexible network 
that can ``bend'' to a broad range of critical system conditions, as 
practiced up to now, or that planning should be ``finely tuned'' so 
that reliability can be maintained under conditions where both 
resources and loads are highly controlled. They find the source for the 
latter interpretation in the Commission's request that the industry 
move toward more explicit requirements that transmission planners 
consider the effects of load control or other forms of DSM, or conduct 
planning studies for far more combinations of resource alternatives. 
EEI and APPA state that the existing Reliability Standards fully meet 
the Commission's criteria as set forth in Order No. 672, unless the 
Commission envisions a very different transmission system planning 
process or seeks to move away from current network design toward the 
development of a much ``tighter'' transmission system through 
substantially higher saturations of controllable resources and loads.
    1689. SDG&E notes that the NOPR's characterization of the dual 
objectives of ``appropriateness'' and ``specificity'' speaks, on the 
one hand, to the need for Reliability Standards that are tailored to 
each transmission planner's area of responsibility, and, on the other 
hand, clear, consistent and workable rules. SDG&E urges the Commission 
to be mindful of the need to assess and balance these considerations in 
future iterations of the transmission planning Reliability Standards.
    1690. Northern Indiana states that the presentation of TPL-001-0 
through TPL-004-0 as individual Reliability Standards creates a great 
deal of confusion. In practice, most transmission planners take an 
integrated view of these Reliability Standards and treat them as if 
they were a single standard. Accordingly, Northern Indiana suggests 
that the Commission ask NERC to file a substitute proposal that would 
integrate the transmission planning standards and improve their clarity 
and quality.
    1691. SDG&E supports the Commission's proposal to direct NERC to 
submit for approval regional transmission planning criteria that have 
been adopted and extensively used that are more stringent than those 
specified in the current TPL Reliability Standards. NCPA states that 
whenever a RTO/ISO adopts criteria that differ from ERO or regional 
standards, those criteria should be made public and transparent.
(b) Commission Determination
    1692. EEI and APPA raise an important question on the Commission's 
intent regarding the transmission planning process and proposed 
modifications to the transmission planning standards. They ask whether 
the Commission is proposing a fundamental shift in the nature of the 
planning process that would result in a move away from the current 
network design towards a much ``tighter'' transmission system through 
substantially increased use of controllable resources and loads. The 
Commission is not proposing a fundamental shift in the nature of the 
planning process as it is practiced today. We clarify that all the 
proposed modifications to the TPL group of Reliability Standards are 
aimed at ensuring Reliable Operation of the Bulk-Power System. To 
achieve this goal, it is necessary, among other things, to ensure that 
the planning process and the Reliability Standards produce a Bulk-Power 
System that is robust enough to be able to withstand a range of 
probable contingencies while reliably serving customer demand and 
preventing the identified outages, and flexible enough to accommodate a 
broad range of system conditions over a planning horizon that takes 
into account lead times to place facilities in service. Further, the 
proposed modifications are intended to ensure that the planning 
requirements are specific enough to promote rigor and consistency in 
assessments and provide clear and measurable rules for mandatory and 
enforceable Reliability Standards. The Commission therefore agrees with 
SDG&E's comments in this regard and on the need to balance 
``appropriateness'' and ``specificity.''
    1693. The Commission agrees with Northern Indiana that the 
Reliability Standards TPL-001-0 through TPL-004-0 would be improved if 
they were integrated into a single Reliability Standard. Such an 
approach conforms more closely to common planning practices, and 
integrating these Reliability Standards therefore could enhance their 
practical effectiveness. The Commission notes that the Work Plan 
submitted by the ERO has earmarked this group of Reliability Standards 
for revision during the early stages of the plan. The Commission 
directs the ERO to consider integrating Reliability Standards TPL-001-0 
through TPL-004-0 into a single Reliability Standard through the 
Reliability Standards development process.
    1694. The Commission agrees with SDG&E and NCPA that any criteria 
that are more stringent than the ERO planning criteria should be made 
public and transparent. It is essential that such criteria be 
accessible to and understood by the entities to which they apply. 
Accordingly, the Commission directs the ERO to submit to the Commission 
in an informational filing, in addition to regional criteria, all 
utility and RTO/ISO differences in transmission planning criteria that 
are more stringent than those specified by the TPL group of Reliability 
Standards. We believe that this information will provide us, as well as 
the ERO and industry with an indication of the actual transmission 
practices utilized in the industry today. This should be used by the 
ERO in the Reliability Standards development process.
ii. Sensitivity studies and critical system conditions
    1695. The Commission stated in the NOPR that it is not realistic to 
expect the ERO to develop Reliability Standards that anticipate every 
conceivable critical operating condition applicable to unknown future 
configurations for regions with various configurations and operating 
characteristics.\426\ The practical solution implemented by many in the 
industry is to perform sensitivity studies that define and provide 
documentation of the reliability impact on the system. The Commission 
therefore stated that it would be appropriate for planning entities to 
conduct sensitivity studies to ``bracket'' the range of probable 
outcomes. Thus, without having to anticipate ``every conceivable 
critical operating condition,'' planning entities will have a means to 
identify an appropriate range of critical operating conditions. Both 
staff and commenters on the Staff Preliminary Assessment noted that 
system conditions are as important as contingencies in evaluating the 
performance of present and future systems.
---------------------------------------------------------------------------

    \426\ NOPR at P 1047.
---------------------------------------------------------------------------

(a) Comments
    1696. Most of the commenters agree with the Commission's proposal 
on sensitivity studies to determine critical

[[Page 16572]]

system conditions. These include FirstEnergy, TVA, MidAmerican, Entergy 
and SDG&E. However, a few commenters, including EEI, APPA, MISO and 
Northern Indiana, take the view that such a requirement is unnecessary 
and overly prescriptive.
    1697. FirstEnergy states that it is appropriate for the Commission 
to require sensitivity analyses, because assessing multiple 
sensitivities against a set of system contingencies is prudent system 
planning.
    1698. TVA agrees that an appropriate range of critical operating 
conditions that will ``stress'' the Bulk-Power System needs to be 
identified for use in transmission planning. It states that sensitivity 
studies should be performed and historic data analyzed to determine the 
most probable range of operating conditions that will stress the Bulk-
Power System.
    1699. MidAmerican believes that the proposal to require sensitivity 
studies to ``bracket'' the range of probable outcomes and determine 
critical system conditions is reasonable. It states that, while 
critical conditions may be determined in a similar manner for the 
different TPL Reliability Standards, different critical conditions are 
pertinent to each Reliability Standard. For example, thermal overloads 
occur under peak load conditions and dynamic instability occur under 
light load conditions.
    1700. Entergy does not object to an assessment of critical system 
conditions using the factors identified in the NOPR,\427\ but it 
contends that the Commission's guidance is problematic to the extent 
that it may require constructing facilities to address potential 
constraints identified through these assessments. Entergy states that 
such construction may not create a desirable result and may instead 
threaten reliability. For example, assessing a system using alternative 
generation dispatch and transaction patterns could bias a transmission 
provider in favor of transmission plans that benefit a specific 
generator or set of generators.
---------------------------------------------------------------------------

    \427\ Id. at P 1061.
---------------------------------------------------------------------------

    1701. SDG&E sees the Commission's treatment of sensitivity studies 
and critical system conditions as requiring transmission planning 
entities to exercise judgment in determining the scope, content and 
number of their sensitivity studies so that they are appropriate given 
unique system characteristics and reasonably anticipated contingencies. 
SDG&E state that this guidance is welcome and should be reflected in 
future Requirements.
    1702. MISO agrees that planning entities should have a process to 
identify appropriate critical system conditions for planning purposes. 
However, it does not believe that the Reliability Standard needs to be 
prescriptive in terms of the specific sensitivities that should be 
evaluated. If an entity's approach to selecting the critical planning 
conditions is appropriate, sensitivities to variations from these 
conditions are unnecessary. MISO and Northern Indiana state that 
requiring sensitivities in planning studies as a mandatory standard 
practice could result in unnecessary additional analysis that could 
overwhelm the planning process and detract from more appropriate 
focused analysis and evaluation of solutions.
    1703. EEI and APPA state that the Commission's proposal on 
sensitivity studies would add an unnecessarily redundant process that 
ignores the totality of the studies contained in study libraries that 
inform planners' decisions. The historical libraries of system studies 
provide a strong base for selecting critical transmission system 
conditions. EEI believes that the knowledge and experience of planners 
who have conducted these studies provides reliable guidance and that a 
new array of sensitivity analyses would offer no additional benefit 
over existing practices.
    1704. Regarding specific variables to be included in sensitivity 
studies, EEI and APPA note that load power factors, controllable loads 
and DSM at specific locations and outages of reactive devices have much 
more to do with distribution operations planning than long-term system 
planning. They state that while transmission system planners will study 
a broad range of combinations of substation loadings, system 
configurations and resource availabilities over the planning horizon, 
changes in the variables of the sort identified by the Commission have 
very little influence on the long-term study outcomes except for the 
loss of load that could occur under extreme circumstances. MISO 
believes that transmission reactive power devices should be treated 
like any other transmission facility and included in the required 
contingency analysis. The current Reliability Standards are not 
explicit in this regard, and MISO agrees that this would be an 
appropriate clarification. It believes that power factor sensitivity 
studies are best suited for operational planning studies rather than 
long-term planning since corrective actions have relatively short lead 
times. In regard to alternative dispatch scenarios, MISO states that if 
a variation from the expected dispatch leads to unacceptable 
performance, it becomes an economic planning question, rather than a 
planning standard issue, whether expansion should be undertaken or 
whether the dispatch becomes a congestion cost.
(b) Commission Determination
    1705. In response to Entergy's comments, the Commission reiterates 
the statement from the NOPR \428\ that the results of the sensitivity 
studies would be used to document the selection of critical system 
conditions and study years used in assessing system conditions. The 
Commission notes that it is not the purpose of sensitivity studies to 
identify remedial actions, but, as stated in the NOPR, if different 
scenarios that lead to criteria violations are probable they require 
mitigation plans.\429\ Entergy goes on to state that constructing 
facilities, the need for which is determined through sensitivity 
studies, may not create a desirable result, in that they may bias 
transmission plans towards a specific generator or set of generators 
and as a result may threaten reliability. The Commission disagrees that 
constructing well-planned facilities may threaten reliability. The 
planning process should anticipate any inter-regional impacts, and the 
net result should be higher local and inter-regional reliability. In 
any case, we are not requiring the construction of additional 
facilities.
---------------------------------------------------------------------------

    \428\ Id. at P 1061.
    \429\ Id. at n 324.
---------------------------------------------------------------------------

    1706. MISO, EEI, APPA and others question the value of sensitivity 
studies and their role in mandatory Reliability Standards given the 
knowledge and experience of planners and the historical library of 
system studies. The Commission notes that while specificity was not 
required in the regime of voluntary standards, it is required in a 
regime of mandatory Reliability Standards to ensure consistency in 
system assessment and provide clear and measurable requirements. 
Further, as stated in the NOPR \430\ and concurred with by commenters 
to the Staff Preliminary Assessment, system conditions are as important 
as contingencies in evaluating the performance of present and future 
systems. Indeed, Table 1 lists the contingencies to be evaluated, but 
there is no corresponding requirement for selecting critical system 
conditions.
---------------------------------------------------------------------------

    \430\ Id. at P 1046.
---------------------------------------------------------------------------

    1707. The Commission believes it is important to clarify the type 
of analysis

[[Page 16573]]

required in determining critical system conditions, which is the intent 
of the directed modifications on sensitivity studies. The Commission 
proposed in the NOPR a range of variables to be included in sensitivity 
studies, specifically: firm transfers, demand levels, existing and 
planned facilities, reactive power resources, control devices, load 
power factors, generation retirements, generation dispatch, transaction 
patterns, controllable loads, DSM and transmission outages including 
outages of reactive power devices.\431\ The Commission also stated that 
it is not precluding other approaches to defining and documenting 
critical system conditions that have proven to be effective. The 
Commission also notes that in analyzing contingencies as part of 
Requirement R1.3.1 in Reliability Standards TPL-002-0 through TPL-004-
0, not all contingencies need be assessed for every system element but 
only those that would produce the more severe reliability impacts with 
documentation of selection rationale. The same applies to the range of 
variables specified for sensitivity studies. The Commission expects 
that the full range of variables will be considered, but only those 
deemed to be significant need to be assessed and documentation provided 
that explains the rationale for the selection of variables assessed.
---------------------------------------------------------------------------

    \431\ Id. at P 1047.
---------------------------------------------------------------------------

iii. Element-Based vs. Event-Based Contingencies
    1708. The Commission stated in the NOPR that planning Reliability 
Standards must influence system design and not the other way 
around.\432\ To achieve this objective, planning Reliability Standards 
should promote system designs that result in the minimum set of 
elements being removed from service for ``unanticipated failures of 
system elements.'' \433\ The NOPR goes on to say that the Commission 
believes that the simulations used in planning assessments should 
faithfully duplicate what will happen in the actual power system and 
not a generic listing of outages. The Bulk-Power System also must be 
operated, and planned to be operated, within a number of conditions 
after a contingency or cyber event. The contingency can be a sudden 
disturbance or an unanticipated failure of any system element. If a 
specific portion of the system has been designed such that the response 
to a failure results in multiple lines, transformers, generators, 
circuit breakers, etc., being removed from service, the Commission 
proposed that this is what should be simulated.\434\
---------------------------------------------------------------------------

    \432\ Id. at P 1049.
    \433\ Section 215(a) of the FPA defines ``Reliable Operation'' 
as ``operating the elements of the Bulk-Power System within 
equipment and electric system thermal, voltage, and stability limits 
so that instability, uncontrolled separation, or cascading failures 
of such system will not occur as a result of sudden disturbance, 
including a Cybersecurity Incident, or unanticipated failure of 
system elements'' (emphasis added).
    \434\ With respect to failure, the element includes a single 
transmission line, transformer, generator or single pole of a DC 
line.
---------------------------------------------------------------------------

(a) Comments
    1709. National Grid, MidAmerican and SDG&E support the principles 
set forth in the NOPR. National Grid states that event-based planning 
is a more robust form of contingency analysis than element-based 
planning because the former focuses on contingencies regardless of how 
many elements may be affected while the latter focuses on losses of 
specific elements that may not have a direct relationship to the 
severity of the impact on or risks to reliability. As such it supports 
the Commission's statement that ``simulations should faithfully 
duplicate what will happen in the actual power system and not a generic 
listing of outages.'' \435\
---------------------------------------------------------------------------

    \435\ NOPR at P 1049.
---------------------------------------------------------------------------

    1710. MidAmerican states that it supports the Commission's proposal 
to interpret a ``single contingency'' to include all elements of the 
system, irrespective of their number, that go out of service in 
response to failure of a single element, as it has historically 
performed this analysis as a part of normal planning in the interest of 
reliability. MidAmerican is concerned, however, that this proposal may 
be too restrictive for system planning, particularly with regard to the 
double contingencies of Category C. It states that if a multi-element 
single contingency occurs first, as part of system adjustment, the 
reliability coordinator or transmission operator will switch back the 
unfaulted elements to service prior to the next contingency. Therefore 
this N-1-1 contingency at its worst will consist of a single element 
outage followed by a multi-element outage. Therefore MidAmerican states 
that the extent of a multiple-element single contingency is better 
determined through coordinated efforts of neighboring systems in 
conjunction with the planning authority and reliability coordinator.
    1711. SDG&E agrees that further modifications to the TPL 
Reliability Standards should be guided by the NOPR's directive that 
simulations should faithfully duplicate what will happen in the actual 
power system and not a generic listing of outages. However, it states 
that the Commission should provide further guidance in defining an 
event so that planning studies can assess electrical system 
contingencies consistently and numerically. A simulation that 
faithfully duplicates reasonably expected scenarios will necessarily 
involve the transmission planner's sound engineering judgment and 
knowledge of elements that would be expected to be removed from service 
during the contingency. SDG&E states that the updated TPL Reliability 
Standard should reflect and implement these concerns.
    1712. EEI believes the planning Reliability Standards and practices 
clearly reflect the language in FPA section 215 regarding ``element 
based'' planning. Planners study single contingency and multiple 
contingency events covering a broad range of system elements and not a 
list of generic outages.
    1713. TANC recommends that the Commission direct that transmission 
planning in the West be based on probability of an event occurring and 
the severity of the consequences, rather than on a deterministic 
approach that uses single and multiple contingency categories as 
exemplified by Table 1. It states that WECC has assessed the 
probability of an event occurring for each category and assigned 
probabilities accordingly. TANC states that to be more cost effective 
and efficient, investments to remedy a problem should be based on a 
combination of the probability of the occurrence of the event and the 
severity of the associated consequences.
    1714. In response to the Commission's request in the NOPR for 
comment on whether planning for cyber security events should be 
addressed in the planning Reliability Standards or in the Critical 
Infrastructure Protection (CIP) Reliability Standards,\436\ 
MidAmerican, EEI, APPA, ISO-NE and SoCal Edison state they believe that 
events requiring study under the CIP Reliability Standards should be 
included in that specialized forum rather than the TPL Reliability 
Standards. Such events are identified using approaches provided for in 
the CIP Reliability Standards. Therefore the best place to explore 
those events and determine their impacts using the full background of 
the information about the events is the CIP Reliability Standards, 
although some of these events will require

[[Page 16574]]

implementation of elements from other Reliability Standards.
---------------------------------------------------------------------------

    \436\ Id. at P 1050.
---------------------------------------------------------------------------

    1715. National Grid and International Transmission take the view 
that cyber security incidents are no different than other events that 
remove single or multiple elements from service at a single time and 
require analysis of system impacts. Planning assessment for cyber 
security incidents therefore is most appropriately addressed in the TPL 
Reliability Standards. International Transmission states that although 
Table 1 of the TPL Reliability Standards does not list the initiating 
event, cyber security events could be included in the list of 
contingencies as an initiating event. National Grid cautions that 
provisions detailing specific cyber security protections should be 
addressed in CIP Reliability Standards, and emergency response 
procedures for response to cyber security events should be addressed in 
EOP Reliability Standards.
(b) Commission Determination
    1716. Several commenters \437\ agree with the Commission's 
statement in the NOPR \438\ that ``simulations should faithfully 
duplicate what will happen in the actual power system and not a generic 
listing of outages.'' It follows that in simulating the failure of a 
single element, as required in Category B of TPL-002-0, all of the 
elements that are removed from service to isolate the single faulted 
element should be modeled in the simulation rather than restricting the 
simulation to just the single faulted element, as Table 1 of TPL-002-0 
implies. As SDG&E notes, this will require the transmission planner's 
sound engineering judgment and knowledge of elements that would be 
expected to be removed from service during the single contingency. The 
Commission agrees with MidAmerican that for Category C contingencies of 
TPL-003-0, the worst N-1-1 contingency would be a single element outage 
followed by a multiple element outage, provided that following the 
first N-1 contingency, capability exists to switch the unfaulted 
elements back into service promptly, i.e., within 30 minutes, as part 
of the adjustments that the Reliability Standard allows.
---------------------------------------------------------------------------

    \437\ National Grid, MidAmerican and SDG&E.
    \438\ NOPR at P 1049.
---------------------------------------------------------------------------

    1717. SDG&E agrees that simulations should faithfully duplicate 
what will happen in the actual power system and not a generic listing 
of outages, but it seeks Commission guidance on how an event should be 
defined. In the Commission's view, a single contingency consists of a 
failure of a single element that faithfully duplicates what will happen 
in the actual system.\439\ Such an approach is necessary to ensure that 
planning will produce results that will enhance the reliability of that 
system. Thus, if the system is designed such that failure of a single 
element removes from service multiple elements in order to isolate the 
faulted element, then that is what should be simulated to assess system 
performance. Accordingly, the Commission directs the ERO to submit 
modifications to Category B of Table 1 consistent with this approach. 
Entities whose systems may have been planned and designed on the basis 
of a different approach to single contingencies should work with the 
ERO in developing plans to transition to this approach.
---------------------------------------------------------------------------

    \439\ A ``single element'' means a transmission line, a 
transformer, a generator or a single pole of a DC line.
---------------------------------------------------------------------------

    1718. The Commission disagrees with EEI that the planning 
Reliability Standards and practices clearly reflect the language in FPA 
section 215 regarding ``element based'' planning. Section 215(a) of the 
FPA defines ``Reliable Operation'' as ``operating the elements of the 
Bulk-Power System'' within certain limits so that ``instability, 
uncontrolled separation or cascading failures of that system will not 
occur as a result of sudden disturbances, including a cyber security 
incident, or unanticipated failure of system elements.'' This 
definition specifies an ultimate goal and does not dictate any specific 
type of planning. The approach to a single contingency the Commission 
has set forth above ensures that transmission planners analyze 
contingencies based on the actual number of elements that would be 
removed from service in the actual power system for ``an unanticipated 
failure of system elements,'' rather than simulating only the limited 
number of outages listed in Table 1 of the TPL Reliability Standards. 
In short, the Commission's approach speaks directly to the problem that 
the statute requires be addressed.
    1719. In response to TANC's proposal that the Commission direct 
that probabilistic approaches to transmission planning be adopted in 
the West, the Commission notes that proposals of this type should be 
submitted to the ERO for approval as a regional difference. If such a 
proposal is developed for the Western Interconnection, to assist the 
ERO and the Commission in its assessment of such a proposal, we 
encourage WECC to also submit operating information that quantifies the 
level of actual performance that has been achieved with the present 
deterministic planning approach. Such performance metrics would assist 
us in determining whether a probabilistic approach would result in 
equivalent or higher levels of Reliable Operation than currently 
achieved.
    1720. In response to the comments received on how best to address 
planning for cyber security events, it is clear that the nature of 
risks as well as the contingencies and measures needed to overcome them 
are best addressed in the CIP Reliability Standards because this forum 
has the specialized knowledge to deal with cyber security matters. 
However, the system impacts of cyber security events are best addressed 
in the TPL group of Reliability Standards, particularly TPL-004-0, 
alongside other similar common mode failures. Emergency plans and 
restoration procedures to deal with cyber security events are best 
addressed by the EOP Reliability Standards because these Reliability 
Standards deal with emergency plans and restoration procedures. The 
Commission directs the ERO to consider appropriate revisions to the 
Reliability Standards through its Reliability Standards development 
process to address these matters.
iv. Spare Equipment Strategy
    1721. The Commission stated in the NOPR that while Reliability 
Standards TPL-002 through TPL-004 require consideration of planned 
outages at those demand levels for which planned outages are performed, 
they do not address situations where critical equipment, such as a 
transformer or phase angle regulator, may be unavailable for a 
prolonged period. Including such a requirement would ensure the 
coordination of contingency plans, including the entity's spare 
equipment strategy, to return facilities to service in a timely manner 
for reliability. The Commission therefore proposed that the Reliability 
Standards be modified to include a new requirement to assess the 
reliability impact of an entity's existing spare equipment strategy.
(a) Comments
    1722. SDG&E states that it generally supports a new requirement 
that would include assessing the reliability impact of an entity's 
spare equipment strategy, but several key features of this requirement 
need clear and thorough definition. For example, the requirement should 
provide an industry-developed finite list of ``critical items,'' and 
the meaning of ``impact IROL'' would need further clarification. SDG&E 
submits that, absent a careful delineation of the requirement and its

[[Page 16575]]

terms, this proposed modification will not enhance system reliability.
    1723. MidAmerican, LPPC, EEI, APPA and SoCal Edison state that they 
understand the Commission's concern about spare equipment planning and 
acquisition strategy. However, MidAmerican and LPPC note that typically 
spare equipment strategy is of more concern in operating studies than 
planning studies. MidAmerican states that most equipment can be 
installed in a year or less even if it is not on hand. It maintains 
that it may be appropriate to add this requirement to the TPL 
Reliability Standards because scarcity of new equipment due to recent 
disasters has led to longer lead times. LPPC cautions the Commission 
that associating spare equipment strategy with the planning Reliability 
Standards could lead to Reliability Standards that overstep the limits 
of FPA section 215(i)(2) through proposing a Reliability Standard that 
would, indirectly, come close to authorizing the ERO to order the 
construction of transmission capacity. LPPC states that it is unclear 
how to separate: (1) Requiring a utility to assess its spare equipment 
strategy; (2) requiring a utility to have spares on hand to meet 
anticipated reliability needs and (3) requiring a utility to use spare 
equipment to meet the reliability needs.
    1724. EEI, APPA and SoCal Edison question the need to address this 
issue in the context of a Reliability Standard. EEI states that, where 
delivery delay could occur for long lead time equipment such as 
transformers, the existing Reliability Standards provide for study of 
the full range of single and multiple-event contingencies with that 
piece of equipment modeled off-line. According to EEI, the Commission's 
general concern regarding the current policies and practices related to 
equipment acquisition can be addressed in the NERC forum without 
revising the Reliability Standards. This forum also will account for 
the need to protect information on critical infrastructure facilities.
(b) Commission Determination
    1725. Several commenters stated that they understand the 
Commission's concern about requiring a reliability impact assessment of 
an entity's spare equipment strategy, but they question the need to 
address this issue in the Reliability Standards in general and the 
transmission planning Reliability Standards in particular. The 
Commission disagrees with EEI that the existing Reliability Standards 
provide for situations that cover the delivery of long lead time 
equipment, such as transformers, by requiring a full range of single 
and multiple contingency studies with that equipment modeled off-line. 
TPL-002-0 and TPL-003-0 currently state explicitly in Requirement 
R1.3.12 that the assessments shall include planned outages of bulk 
electric equipment at those demand levels for which planned (including 
maintenance) outages are performed. However, equipment such as 
transformers may not be available for service for a year or more and 
therefore their unavailability cannot be scheduled when system 
conditions permit.
    1726. The current Reliability Standards do not require assessment 
of the reliability impacts that result from not having this long lead 
time equipment available under those system conditions likely to be 
experienced during the course of the year when the system is heavily 
stressed. Clearly the consideration of planned outages is inextricably 
linked with spare equipment strategy. Thus, if an entity's spare 
equipment strategy for the permanent loss of a transformer is to use a 
``hot spare'' or to relocate a transformer from another location in a 
timely manner, the outage of the transformer need not be assessed under 
peak system conditions. However, if the spare equipment strategy 
entails acquisition of a replacement transformer that has a one-year or 
longer lead time, then the outage of the transformer must be assessed 
under the most stressed system conditions likely to be experienced. 
Accordingly, the Commission directs the ERO to modify the planning 
Reliability Standards to require the assessment of planned outages 
consistent with the entity's spare equipment strategy.
    1727. LPPC questions whether the Commission's proposal oversteps 
the limits of FPA section 215(i)(2) because assessing the impact on 
reliability of an entity's decision concerning spare equipment could 
force an entity to construct transmission capability. FPA section 
215(i)(2) prohibits the ERO and the Commission from ordering the 
construction of ``additional'' transmission capacity. A requirement to 
assess the reliability impacts of an entity's spare equipment strategy 
is no different than a requirement to assess the reliability impacts of 
any number of contingencies. Even if an entity was forced to conclude 
that its spare strategy was inadequate, rectifying the problem would 
not require that the entity construct ``additional'' transmission 
capacity, only that it possess adequate spares, or take other 
appropriate action, to ensure the reliable operation of its system. In 
short, while FPA section 215(i)(2) precludes ordering expansion of 
transmission or generation capacity, section 215 clearly authorizes 
requiring entities to take appropriate steps to ensure that their 
existing capacity operates reliably.
    1728. With regard to SDG&E's suggestion to clarify specific 
elements of this Reliability Standard, we direct the ERO to consider 
such suggestions in its Reliability Standards development process.
v. Resource Information for Planning
    1729. The Commission in the NOPR requested comments on whether 
transmission planners and planning authorities are currently able to 
obtain and validate resource information on new generation and 
retirements for assessments over the ten year planning horizon. 
Further, if transmission planners and planning authorities currently 
experience difficulty obtaining this information, the Commission asked 
how this potential information gap should be addressed.\440\
---------------------------------------------------------------------------

    \440\ NOPR at P 1060.
---------------------------------------------------------------------------

(a) Comments
    1730. The Commission noted in the NOPR that transmission planning 
requires information on forecasted loads and probable generation plans 
to supply those loads.\441\ While the MOD Reliability Standards require 
information on forecasted loads, energy, interruptible loads and direct 
control load management over the next ten years, there is no 
requirement to inform transmission planners and planning authorities of 
new or retiring generation resources. The Commission sought comments on 
whether transmission planners and planning authorities are currently 
able to obtain and validate resource information on new generation and 
retirements for assessments over the ten year planning horizon and if 
not, how this potential gap should be addressed.
---------------------------------------------------------------------------

    \441\ Id.
---------------------------------------------------------------------------

    1731. NERC stated that it and the regional reliability 
organizations have generally not had problems obtaining the data and 
information required for reliability assessments. NERC believes that 
given its authority and responsibility as the ERO, it will be 
successful in obtaining all the data and information it needs to 
conduct reliability assessments without the need to include these 
requirements in Reliability Standards. In the event that it and the 
regional reliability organizations are unsuccessful in obtaining such 
data and information,

[[Page 16576]]

the ERO will turn to the Commission for assistance.
    1732. ISO-NE states that as the planning authority it obtains 
resource plans for additions, capacity changes, deactivations and 
retirements for a ten year planning horizon. Although these plans 
cannot be expected to occur exactly as projected, they serve as useful 
information in projecting needs for new resources or new or upgraded 
transmission facilities. As the administrator of wholesale electric 
markets, ISO-NE relies on the development of robust market rules 
accompanied by a regulated transmission planning process to achieve its 
goal of encouraging the availability of sufficient resources. ISO-NE 
states that planning for the introduction and retirement of specific 
resources ten years in advance not only is unnecessary, it is 
inconsistent with relying on markets to determine the most efficient 
allocation of resources to meet system needs.
    1733. FirstEnergy and SoCal Edison state that currently they are 
able to obtain information regarding new generation from publicly 
available information and from the generator interconnection queue. 
Typically, a generation application that is in the interconnection 
agreement phase is considered for transmission planning studies. New 
generation has a longer lead time, and thus information on it may be 
available sooner than information about retirements, which have a much 
shorter lead time before they are announced. FirstEnergy states that 
despite the unpredictability of such information, assessments can be 
conducted using assumptions of new generation and retirements, and the 
results should recognize that the inputs were based on reasonably 
foreseeable conditions.
    1734. In contrast, CAISO, National Grid and Northern Indiana state 
that obtaining resource information has been a challenge given that the 
Reliability Standards impose no obligation on generation owners to 
provide information to planning authorities and transmission service 
providers about new and retiring generation. Northern Indiana states 
that this issue is among the greatest challenges for its transmission 
planners. Because transmission planning is focused on matching the 
source to the sink, having the sources unknown, in the case of future 
generation, creates a weakness in the entire transmission planning 
process. Northern Indiana contends that weakness will be difficult to 
eliminate because information about siting of future generation units 
is considered commercially sensitive information. This lack of 
information makes it difficult for transmission planners to reflect 
accurately the amount and location of new generation in their 
transmission studies. CAISO agrees that there is a gap in its ability 
to obtain this information particularly from adjacent balancing 
authorities. CAISO suggests that to bridge this gap, generator owners 
and operators should be required to provide data about new and retiring 
generation to their planning authorities and that the planning 
authorities be required to share this information with neighboring 
balancing authorities, subject to appropriate non-disclosure 
agreements. CAISO notes that there currently exists no centralized 
database for the collection and dissemination of this information 
within the Western Interconnection.
    1735. National Grid states that forward capacity markets and the 
generation interconnection queue provide some understanding about new 
generation but only for five to seven years, even though transmission 
planning horizons are considerably longer. National Grid and Northern 
Indiana contend that it may be reasonable to conclude that certain 
areas are prime locations for new resources, particularly inexpensive 
and renewable resources that are dependent on ``non-transportable'' 
fuel supplies. National Grid states that the Commission should embrace 
efforts of transmission planners to facilitate new generation entry 
when such initiatives are expected to increase customer access to 
inexpensive, renewable and diverse sources of supply.
    1736. Entergy believes that from a transmission provider's point of 
view it would be desirable to have LSEs provide ten or even five-year 
resource forecasts. Entergy recognizes that such a requirement may not 
be practical when LSEs depend significantly on short-term purchases due 
to the abundance of independent power producers or in areas that have 
an locational marginal pricing-like market structure. MISO states that 
its experience suggests that LSEs do not identify new generation 
resources except in very general terms past the second or third year. 
In most cases LSEs show future capacity requirements served from 
generic base load and peaking power resources or from potential 
contract purchases with no information on location. This increases the 
difficulty of accurate long-range transmission planning studies.
    1737. National Grid states that it is also vitally important to 
acknowledge that generation retirements may pose a greater threat to 
reliability in some areas of the country than the slow down of new 
generation. Because required notice periods for retirements may be as 
little as ninety days in some areas, it is imperative that transmission 
planners use a robust statistical approach to identify vulnerable 
sources of generation and conduct such modeling as an integral part of 
the transmission planning process.
    1738. MISO states that planning assumptions around generation 
retirements are particularly difficult because such assumptions are 
driven by complex economic factors that may or may not prevail. While 
MISO has the tools to project what unit may be more likely to retire 
than others, it contends that the preferred approach is to have in 
place tariff provisions that require suppliers to announce retirement 
intentions six months in advance of the retirement. This permits 
reliability studies to be performed with certainty and corrective 
actions to be implemented that could include placing the unit on 
contract to continue operations until appropriate operating measures or 
system expansions can be made.
    1739. SoCal Edison states that business decisions by generator 
owners to retire or mothball units are outside of SoCal Edison's 
control, and generally SoCal Edison does not receive this information 
in a timely manner for transmission planning studies.
    1740. National Grid urges the Commission to support longer planning 
horizons. It states that in many respects, the ten year planning 
horizon may be too short a time frame for assessing transmission needs, 
particularly with regard to long distance extra high voltage facilities 
that pose considerable siting and permitting challenges. Establishing 
planning horizons that are shorter than transmission construction lead 
times may create gaps where the identification of a reliability need to 
which transmission may be the best solution occurs too late to head off 
the identified reliability violation. National Grid states that PJM is 
establishing a fifteen year planning horizon that will accommodate 
large-scale projects that are needed for reliability and to support 
regional transactions.
    1741. MISO and International Transmission note that while it is 
important for planners to have quality information on available 
resources, the enabling legislation for the ERO specifically excludes 
authority regarding resource adequacy. MISO states it is not certain 
how far the Reliability Standards can go. International Transmission 
states that, in the absence of a standard on resource

[[Page 16577]]

adequacy, transmission service providers must use their judgment on 
potential new generation or retirements to create base cases and plan 
the system accordingly.
    1742. Reliant states that, while section 215 of the FPA requires 
the ERO to develop Reliability Standards that provide an adequate level 
of Bulk-Power System reliability, the proposed Reliability Standards 
surprisingly lack any substantive consideration of planning reserve 
obligations to ensure capacity available to meet the needs of a 
reliable system. Reliant proposes that each regional reliability 
organization develop and enforce its own minimum planning reserve 
margin. Such a program would be critical to the development of new 
generation, demand response and distributed generation resources and 
allow each region to retain its own autonomy in developing its own 
resource adequacy standards.
    1743. Process Electricity Committee supports long-term planning as 
a vital part of any economic and thorough set of Reliability Standards. 
However, it is concerned that transmission service providers who are 
also market participants will have an incentive to exploit commercially 
sensitive data on generation plans to the disadvantage of other 
competing suppliers. Process Electricity Committee asks the Commission 
to clarify that transmission planners may not use the Reliability 
Standard to obtain and exploit such information, and it urges the 
Commission to take all appropriate measures to guard against such 
abuse.
(b) Commission Determination
    1744. Several commenters addressed separately the availability of 
information on new generation resources and generation retirements, 
given that these have very different lead times. NERC, ISO-NE and 
others appear to be able to acquire the resource information they need 
on new resources and retirements for reliability assessments. Others, 
such as National Grid and MISO, have had difficulty in obtaining this 
information in a timely manner, particularly as it relates to 
generation retirements.
    1745. The Commission disagrees with ISO-NE's statement that 
planning for the introduction of resources ten years in advance is not 
necessary. The existing Reliability Standard requires that the planning 
horizon must take into account the lead times for siting and permitting 
of new long-distance transmission lines and other solutions that can 
exceed ten years. In short, the need for long-term planning has already 
been widely recognized. The Commission agrees with National Grid that 
establishing planning horizons that are shorter than transmission lead 
times may create gaps where the identification of a reliability need to 
which transmission may be the best solution occurs too late to avert 
the identified reliability violation. Indeed, this point is supported 
by the fact that PJM is establishing a fifteen year planning 
horizon.\442\
---------------------------------------------------------------------------

    \442\ See http://www.pjm.com/contributions/pjm-manuals/manuals.html.
---------------------------------------------------------------------------

    1746. In the absence of information about future generation 
resources required for transmission planning the Commission notes that 
entities conduct assessments using assumptions based on the knowledge 
that certain areas are prime locations for new resources, particularly 
those resources that use non-transportable fuels. National Grid states 
that generation retirements may pose a greater threat to reliability in 
some areas than the slowdown of new generation construction. As a 
result, it states that it is imperative that transmission planners use 
robust statistical approaches to identify vulnerable sources of 
generation and conduct such modeling as an integral part of the 
transmission planning process. The Commission understands this as a 
further endorsement of its proposal to require a full range of 
sensitivity studies discussed above.
    1747. MISO, International Transmission and Reliant raise important 
issues about the absence of a Reliability Standard on resource 
adequacy. Reliant points out the inconsistency between the statutory 
requirement to provide an adequate level of Bulk-Power System 
reliability and the lack of any substantive consideration of planning 
reserve obligations to ensure capacity is available to meet the needs 
of a reliable system. In the same vein, the Commission notes that 
Requirement R7 of TOP-002-0 requires each balancing authority to plan 
to meet capacity and energy reserve requirements in the operating time-
frame but that there is no explicit corresponding consideration 
required of generation reserves in the planning time-frame.
    1748. Section 215(a)(3) of the FPA makes clear that enforceable 
Reliability Standards may not address requirements to enlarge 
facilities or construct new generation capacity. We have noted that 
when a state or appropriate jurisdictional entity has such a 
requirement, it should be included in transmission planning analysis. 
Resource adequacy levels are set to achieve a number of goals, one of 
which is system reliability. Our jurisdiction is to approve and enforce 
Reliability Standards that provide for an adequate level of reliability 
for the Bulk-Power System. The TPL group of Reliability Standards 
includes load growth, changes in the transmission topology, existing 
generation, generation retirements, and confirmed new generation as 
inputs to the analyses. When an entity does not meet a reliability 
criterion, including the inability of generation to be deliverable to 
load, mitigation plans are required. Although the Commission 
anticipates that some of those mitigation plans may include new 
generation, we do not require this.
    1749. Some entities have proposed possible solutions to address the 
gap of inadequate and unreliable resource information for long-term 
planning as required by the TPL group of Reliability Standards. CAISO 
suggests that generator owners and operators be required to provide 
data on new generation and retirements to their planning authorities. 
Entergy proposes requiring LSEs to provide this information, but 
recognizes that this approach has its limitations. MISO contends the 
preferred approach to retirements is to have in place tariff provisions 
that require suppliers to announce retirement intentions six months in 
advance of retirements. Process Electricity Committee is concerned 
about the implications of sharing non-public transmission or customer 
information which could then be exploited to the disadvantage of 
competing suppliers. The Commission's Standards of Conduct addresses 
the sharing of such information and generally prohibits the sharing of 
commercially sensitive information between the transmission 
organization and affiliated merchant functions.\443\ In response to 
Process Electricity Committee, the Commission will continue to enforce 
the information sharing prohibition in the Standards of Conduct.
---------------------------------------------------------------------------

    \443\ See Order No. 2004.
---------------------------------------------------------------------------

    1750. The responses to the Commission's inquiry on these matters 
are helpful. The comments further point out the importance of 
conducting a wider range of sensitivity studies on generation 
scenarios. However, the Commission is not directing at this time any 
modifications to address the Commission's concerns.

[[Page 16578]]

vi. Sharing of Information With Neighboring Systems
    1751. In the NOPR, the Commission stated that, because neighboring 
systems may be adversely impacted, such systems should be involved in 
determining and reviewing system conditions and contingencies to be 
assessed in connection with Requirement R1.3 of TPL-001-0 to TPL-004-
0.\444\
---------------------------------------------------------------------------

    \444\ NOPR at P 1063.
---------------------------------------------------------------------------

(a) Comments
    1752. EEI, APPA, FirstEnergy, ERCOT and SDG&E support or 
acknowledge the value of sharing of various kinds of planning 
information with neighboring systems. FirstEnergy states that the 
proposed requirement that system conditions and contingencies assessed 
be shared and reviewed by neighboring systems will improve 
communications with interconnected companies. This process was 
established among former ECAR companies through the ``ECAR Peer Review 
Process,'' and FirstEnergy recommends that regional reliability 
organizations be encouraged to establish a similar process going 
forward. EEI and APPA state that sharing of various kinds of planning 
information, including expected generation additions and retirements, 
planned outages, demand forecasts and estimates of firm transfers will 
go a long way to improving the quality and consistency of planning 
study efforts. However, it is not clear to EEI whether a formal 
Reliability Standard would be the most effective approach. An 
alternative could be to request that NERC oversee an informal process 
to explore alternatives and report back to the Commission by a specific 
date. Although ERCOT states that this proposal is a sensible 
recommendation, it also states that it would not be appropriate for 
ERCOT since the transmission service provided there is not subject to 
interruption by the ISO, and outbound flows are also not interrupted if 
there is a shortage of capacity.
    1753. SDG&E notes that under the auspices of the CAISO it regularly 
convenes stakeholder meetings with the general public, neighboring 
utilities, generator owners, regulators and the CAISO. In these 
meetings, SDG&E reviews the grid assessment process and receives 
comments from participants about all aspects of its process. As a 
member of WECC, SDG&E states that it also holds meetings to discuss 
inter-area projects that SDG&E has proposed to construct. This review 
group consists of neighboring utilities, generator owners and other 
stakeholders who are members of WECC. Similarly, SDG&E maintains that 
it participates in other California-based utility review groups. SDG&E 
finds that these existing processes provide ample opportunities for 
regular sharing of relevant information with neighboring transmission 
planning entities. It thus recommends that the Reliability Standards 
development process take into account existing forums for apprising 
neighboring utilities of current and anticipated transmission planning 
issues and projects. If the Commission believes additional 
communications are needed, SDG&E strongly recommends that the 
Commission, through NERC or the applicable Regional Entity, specify in 
greater detail the nature and periodicity of the information to be 
shared pursuant to the TPL Reliability Standards.
    1754. SoCal Edison states that TPL-001-0 is for systems operating 
under normal conditions, and as such there should not be a need for any 
review by neighboring systems.
(b) Commission Determination
    1755. Most commenters agree with the Commission's proposal that 
neighboring systems be involved in a peer review of system assessments 
in connection with Requirement R1.3 of TPL-001-0 through TPL-004-0. 
Given that neighboring systems assessments by one entity may identify 
possible interdependent or adverse impacts on its neighboring systems, 
this peer review will provide an early opportunity to provide input and 
coordinate plans. The Commission therefore disagrees with SoCal 
Edison's view that there is no need for any review by neighboring 
systems for TPL-001-0. For example, the planning authorities needs to 
be consistent in the line flow values that they use.
    1756. While supporting the concept of a peer review, EEI questions 
whether making this a Requirement in a Reliability Standard is the most 
effective approach or whether NERC should explore alternatives and 
report to the Commission by a specific date. The Commission sees no 
reason why peer reviews should not be part of a Reliability Standard 
since TPL-001-0 through TPL-004-0 already include in Requirement R1.3 a 
review of assessments by the associated regional reliability 
organization. The Commission understands that some regions include peer 
review as part of their procedures. Accordingly, to ensure that 
neighboring systems are not adversely affected and to provide an early 
opportunity for input and coordination of plans, the Commission directs 
the ERO to include these modifications to the Reliability Standard 
through its Reliability Standards development process to provide for 
the appropriate sharing of information with neighboring systems.
    1757. The Commission has taken action on its OATT reform initiative 
in Order No. 890. In that order, the Commission encourages the 
formation of regional planning processes and economic planning 
studies.\445\ Sharing of information and peer review are the first 
steps in a regional planning process. The Commission provides guidance 
and direction on these subjects in our discussion of Reliability 
Standard TPL-005-0.
---------------------------------------------------------------------------

    \445\ Order No. 890 at P 526, 542.
---------------------------------------------------------------------------

b. System Performance Under Normal (No Contingency) Conditions (TPL-
001-0)
    1758. Reliability Standard TPL-001-0 deals with planning related to 
system performance under normal conditions, i.e., a situation where no 
system contingency or no unexpected failure or outage of a system 
component has occurred.\446\ The Reliability Standard seeks to ensure 
that the Bulk-Power System is planned to meet the system performance 
requirements under these normal conditions by requiring the 
transmission planner and the planning authority to evaluate their 
transmission system annually and document the ability of that system to 
meet the performance requirements established in the Reliability 
Standard under conditions where no system contingencies are 
present.\447\ Meeting these requirements means two things. First, when 
all system facilities are in service and normal operating procedures 
are in effect, the system can be operated to supply projected customer 
demands and projected firm (non-recallable reserved) transmission 
services at all demand levels over the range of forecast system 
demands. Secondly, the system remains stable and within the applicable 
ratings for thermal and voltage limits, no loss of demand or curtailed 
firm transfers occurs, and no cascading outages occur. TPL-001-0 
applies both to near-term and longer-term planning horizons.
---------------------------------------------------------------------------

    \446\ The NERC Glossary defines a ``contingency'' as ``[t]he 
unexpected failure or outage of a system component, such as a 
generator, transmission line, circuit breaker, switch or other 
electrical element.'' NERC Glossary at 3.
    \447\ The performance requirements are set forth in Category A 
of Table I of the Reliability Standard.
---------------------------------------------------------------------------

    1759. The Requirements of TPL-001-0 specify that the planning 
authority and transmission planner must

[[Page 16579]]

demonstrate through a valid assessment that the Reliability Standard's 
system performance requirements can be met. The assessment must be 
supported by a current or past study and/or system simulation testing 
that addresses various categories of conditions to be simulated as set 
forth in the Reliability Standard to verify system performance under 
normal conditions. When system simulations indicate that the system 
cannot meet the performance requirements set forth in the Reliability 
Standard, a documented plan to achieve system performance requirements 
must be prepared. The specific study elements selected from each of the 
categories for assessments are subject to approval by the associated 
regional reliability organization.
    1760. The Commission proposed in the NOPR to approve Reliability 
Standard TPL-001-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
we proposed to direct NERC to submit a modification to TPL-001-0 that: 
(1) Requires that critical system conditions be determined by 
conducting sensitivity studies; (2) requires that system conditions and 
contingencies assessed be reviewed by neighboring systems; (3) modifies 
Requirement R1.3 to substitute the reference to regional reliability 
organization with Regional Entity; (4) requires consideration of 
planned outages of critical equipment; and (5) modifies footnote (a) of 
Table 1 to not apply emergency ratings to compare stresses on the 
system under normal conditions as recommended by the Transmission 
Issues Subcommittee of the NERC Planning Committee \448\ and require 
that normal facility ratings be in accordance with Reliability Standard 
FAC-008-1 and that normal voltages be in accordance with Reliability 
Standard VAR-001-1.\449\
---------------------------------------------------------------------------

    \448\ See NERC Transmission Issues Subcommittee Report: 
Evaluation of Criteria, Methods and Practices Used in System Design, 
Planning and Analysis in Response to NERC Blackout Recommendation 
13c. Appendix B, November 28, 2005.
    \449\ NOPR at P 1065-67.
---------------------------------------------------------------------------

i. Comments
    1761. APPA agrees with the Commission that TPL-001-0 is sufficient 
for approval as a mandatory and enforceable standard.
    1762. MidAmerican and others generally support the Commission's 
proposal to improve TPL-001-0 but caution that: (1) Planned outages 
should only be considered at load levels and conditions under which 
they commonly occur and (2) emergency ratings should recognize the 
varying timeframes of overloads that result from various contingency 
events. Further, MidAmerican states that, while it is appropriate that 
planning margins for normal voltages be calculated in accordance with 
VAR-001-1 as proposed by the Commission, it would be better if the 
proposed modification provided that voltage criteria do not conflict 
with VAR-001-1. Northern Indiana agrees with the Commission's position 
regarding consideration of planned outages and states that it considers 
them currently in its transmission planning studies. International 
Transmission states that both planned outages of critical equipment and 
the extended forced outages of similar equipment should be considered. 
FirstEnergy states that planned outages should be accounted for at load 
levels and conditions under which they commonly apply.
    1763. Other commenters disagree that planned outages of critical 
equipment should be included in TPL-001-0.\450\ They contend that the 
Reliability Standard has a very simple aim, namely, to examine whether 
a system can perform under normal system intact conditions, i.e., when 
all elements are in service and operating as expected. The outages 
contemplated are appropriate for TPL-002-0 through TPL-004-0 where the 
planned outage could be a line outage caused by a maintenance project 
that extends into a period where the system is heavily loaded. SDG&E 
states that for near-term planned outages, the transmission planning 
entity should retain an appropriate amount of latitude to plan the 
outage's timing and details and to modify them as necessary. SDG&E 
comments that, for outages planned with a more distant horizon (one 
year or longer), this information can be accounted for in sensitivity 
analyses. SoCal Edison states that no information will be available 
about planned outages of critical equipment to be used for short-term 
(five years) or long-term (10 years) simulations. It may be possible to 
consider planned outages of critical equipment if there is a major 
project construction activity. If generators and transmission lines are 
out for scheduled maintenance during off-peak load conditions, then 
these outages should be considered.
---------------------------------------------------------------------------

    \450\ See, e.g., EEI, APPA, SDG&E, Entergy, SoCal Edison and 
TVA.
---------------------------------------------------------------------------

    1764. EEI supports the Commission's recommendation to modify 
footnote (a) in Table 1. International Transmission states that the 
footnotes in Table 1 are not footnotes but rather requirements for 
transmission system performance. These should be made requirements of 
the Reliability Standards so that they are more obvious and easier to 
monitor. APPA, LPPC and TANC recommend that changes to footnotes of 
Table 1 be subject to the Reliability Standards development process. 
They state that the footnotes have been extensively reviewed by 
technical experts at NERC for several years and currently represent a 
general consensus among these industry technical experts. Changes to 
the footnotes impact Table 1 and have a direct impact on the 
determination of the severity of consequences that were approved along 
with the original Reliability Standard. Therefore, the Commission 
should give due weight to the ERO and allow the Reliability Standards 
development process to resolve any existing ambiguities in the Table 1 
footnotes.
ii. Commission Determination
    1765. The Commission approves TPL-001-0 as a mandatory and 
enforceable Reliability Standard. In addition, we direct the ERO to 
develop modifications to TPL-001-0 through the Reliability Standards 
development process, as discussed below.
    1766. In assessing system conditions, Requirement R1.3.1 of TPL-
001-0 requires entities to cover ``critical system conditions and study 
years,'' as deemed appropriate by the entity performing the study. As 
stated in the NOPR, system conditions are as important as contingencies 
in evaluating the performance of present and future systems,\451\ and 
yet TPL-001-0 does not specify the rationale for determining critical 
system conditions and study years. Consistent with our discussion of 
the issue above regarding sensitivity studies and critical system 
conditions, the Commission concludes that proposed modification (1), 
which requires that critical system conditions be determined by 
conducting sensitivity studies, is justified. Accordingly, we direct 
the ERO to modify the Reliability Standard to require that critical 
system conditions and study years be determined by conducting 
sensitivity studies with due consideration of the range of factors 
outlined above.
---------------------------------------------------------------------------

    \451\ NOPR at P 1046.
---------------------------------------------------------------------------

    1767. Requirement R1.3 of TPL-001-0 states that the planning 
authority and transmission planner must provide studies and simulations 
to support its planning assessments, and that the specific elements 
selected for the study shall be acceptable to the associated regional 
reliability organization. Given that neighboring systems may be

[[Page 16580]]

adversely affected, our goal is to ensure that they are involved in the 
determination and review of system assessments to permit an early 
opportunity to provide input and coordinate plans. We discussed above 
the issue of information sharing as it applies to the TPL group of 
Reliability Standards generally and, consistent with our conclusions 
there, we direct the ERO to modify TPL-001-0 to require a peer review 
of planning assessments with neighboring entities.
    1768. The Commission received no comments on its proposal that 
Requirement R1.3 be modified to substitute the reference to the 
regional reliability organization with a reference to the Regional 
Entity. The Commission has explained the need for this modification 
above, and therefore it directs the ERO to modify Requirement R1.3 of 
TPL-001-0 to substitute the reference to the regional reliability 
organization with a reference to the Regional Entity.
    1769. While some commenters support the consideration of planned 
outages at load levels for conditions under which they are performed, 
others disagree on the grounds that the goal of TPL-001-0 is to ensure 
that the Bulk-Power System can perform reliably when all elements are 
in service and operating as expected. The Commission notes that 
Reliability Standards TPL-002-0 through TPL-004-0 include consideration 
of planned outages, as initial system conditions, at load levels for 
conditions under which they are performed. Because these Reliability 
Standards, and not TPL-001-0, will govern the adequacy of the Bulk-
Power System under planned outage conditions, the Commission will not 
adopt the NOPR proposal to require consideration of planned outages at 
load levels for conditions under which they are performed for 
Reliability Standard TPL-001-0. However, consistent with our discussion 
above on spare equipment strategy, the Commission directs a 
modification to this Reliability Standard to require assessments of 
outages of critical long lead time equipment, consistent with the 
entity's spare equipment strategy. Thus, for example, if an entity's 
spare equipment strategy for the permanent loss of a transformer is to 
use a ``hot spare'' or to relocate a transformer from another location 
in a timely manner, the outage of the transformer need not be assessed 
under peak system conditions. However, if the spare equipment strategy 
entails acquisition of a replacement transformer that has a one-year or 
longer lead time, then the outage of the transformer must be assessed 
under peak loading conditions likely to be experienced. This approach 
will ensure that system conditions are adequately assessed.
    1770. While commenters generally agree with the Commission's 
proposal to modify footnote (a) of Table 1, they caution that any 
changes to the footnotes affect Table 1 and should be reviewed through 
NERC's Reliability Standards development process. International 
Transmission states that the footnotes in Table 1 are not footnotes but 
rather requirements for transmission system performance and therefore 
should be made Requirements in the Reliability Standard. The Commission 
agrees with International Transmission because this will promote 
clarity in and consistent application of the Reliability Standard. The 
Commission therefore directs the ERO to modify the Reliability Standard 
to address the concerns regarding footnote (a) of Table 1, including 
the applicability of emergency ratings and consistency of normal 
ratings and voltages with values obtained from other Reliability 
Standards. As with any modification to a Reliability Standard, 
modifications to TPL-001-0 should be developed through the ERO's 
Reliability Standards development process.
    1771. Accordingly, the Commission approves Reliability Standard 
TPL-001-0 as mandatory and enforceable. In addition, the Commission 
directs the ERO to develop a modification to TPL-001-0 through the 
Reliability Standards development process that: (1) Requires that 
critical system conditions and study years be determined by conducting 
sensitivity studies with due consideration of the range of factors 
outlined above; (2) requires a peer review of planning assessments with 
neighboring entities; (3) modifies Requirement R1.3 to substitute the 
reference to regional reliability organization with Regional Entity; 
(4) requires assessments of outages of critical long lead time 
equipment, consistent with the entity's spare equipment strategy; and 
(5) address the concerns regarding footnote (a) of Table 1, including 
the applicability of emergency ratings and consistency of normal 
ratings and voltages with values obtained from other Reliability 
Standards and the concerns raised by International Transmission in 
regard to the footnotes in Table 1.
c. System Performance Following Loss of a Single Element (TPL-002-0)
    1772. Reliability Standard TPL-002-0 addresses system planning 
related to performance under contingency conditions involving the 
failure of a single element with or without a fault, i.e., the 
occurrence of an event such as a short circuit, a broken wire or an 
intermittent connection. The Reliability Standard seeks to ensure that 
the future Bulk-Power System is planned to meet the system performance 
requirements, with the loss of one element, by requiring that the 
transmission planner and planning authority annually evaluate and 
document the ability of the transmission system to meet the performance 
requirements where an event results in the loss of a single 
element.\452\ Meeting these requirements means two things. First, it 
means that the system can be operated following the event to supply 
projected firm customer demands and projected firm (non-recallable 
reserved) transmission services at all demand levels over the range of 
forecast system demands. Second, it means that the system remains 
stable and within the applicable ratings for thermal and voltage 
limits, no loss of demand or curtailed firm transfers occurs, and no 
cascading outages occur.\453\ The Reliability Standard applies both to 
near-term and longer-term planning horizons.
---------------------------------------------------------------------------

    \452\ The performance requirements are set forth in Category B 
of Table 1 of the Reliability Standard.
    \453\ Footnote b to Table 1 allows for the interruption of firm 
load for consequential load loss.
---------------------------------------------------------------------------

    1773. TPL-002-0 specifies that the planning authority and 
transmission planner must demonstrate through a valid assessment that 
the Reliability Standard's system performance requirements can be met. 
The assessment must be supported by a current or past study and/or 
system simulation testing that addresses various categories of 
conditions to be simulated, as set forth in the Reliability Standard, 
to verify system performance under contingency conditions involving the 
failure of a single element with or without a fault. The Reliability 
Standard requires that planned outages of transmission equipment be 
considered for those demand levels for which planned outages are 
performed. When system simulations indicate that the system cannot meet 
the performance requirements stipulated in the Reliability Standard, a 
documented plan to achieve system performance requirements must be 
prepared. The specific study elements selected from each of the 
categories for assessments are subject to approval by the associated 
regional reliability organization.
    1774. The Commission proposed in the NOPR to approve Reliability 
Standard TPL-002-0 as mandatory and

[[Page 16581]]

enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 
Sec.  39.5(f) of our regulations, we proposed to direct NERC to submit 
a modification to TPL-002-0 that: (1) Requires that critical system 
conditions be determined in the same manner as proposed for TPL-001-0; 
(2) requires the inclusion of the reliability impact of the entity's 
existing spare equipment strategy; (3) explicitly requires all 
generators to ride through the same set of Category B and C 
contingencies as required for wind generators in Order No. 661; (4) 
requires documentation of load models used in system studies and 
supporting rationale for their use; (5) clarifies the phrase ``permit 
operating steps necessary to maintain system control'' and (6) 
clarifies footnote (b) to Table 1 to allow no firm load or firm 
transactions to be interrupted except for consequential load loss.
i. Comments
    1775. APPA agrees that TPL-002-0 is sufficient for approval as a 
mandatory and enforceable reliability standard.
    1776. In response to the Commission's proposal \454\ that NERC 
modify TPL-002-0, in part, because it does not address situations in 
which critical equipment may be unavailable for a prolonged period, 
Northern Indiana states that systems depicted in planning studies 
cannot possibly contain complete planned and forced outage schedules 
for the next ten years. For this reason TPL-003-0 deals with double 
contingencies, i.e., contingencies that allow operator intervention 
after the first outage, and then capture system response to an 
additional outage. Operator intervention includes coordination of 
contingency plans and may impact strategies for spare equipment, 
particularly for critical equipment.
---------------------------------------------------------------------------

    \454\ NOPR at P 1081.
---------------------------------------------------------------------------

    1777. EEI and MidAmerican support requiring all generators to ride 
through the same contingencies as required for wind generators. 
Constellation notes that while it supports the Commission's proposed 
modifications to TPL-002-0, an explicit requirement that all generators 
stay online during the same set of Category B and C events, as is 
required for wind generators, is too broad. Constellation requests that 
the Commission modify this requirement to recognize that NRC has 
specific requirements for how nuclear generation must respond to 
disturbances on the Bulk-Power System, and that those NRC rules should 
apply. Moreover, Constellation generally recommends that the 
Reliability Standards applied to nuclear generation should be 
consistent with NRC requirements and that NRC rules should control in 
the event of conflict.
    1778. NRC notes that there appears to be significant variation in 
the interpretation of this Reliability Standard. It states that some of 
its licensees interpret the TPL-002-0 Reliability Standard to state 
that if a licensee is operating in an N-1 condition another single 
contingency does not need to be considered. NRC states that its 
interpretation has been that the N-1 condition is always analyzed from 
the conditions being experienced. They state that this Reliability 
Standard should be clarified and recommend specific revisions to 
Requirements R1.6, R2.1, R2.2 and Levels of Non-Compliance.
    1779. Northern Indiana expresses concern about the statement in P 
1062 of the NOPR that ``load models used in system studies have a 
significant impact on system performance * * *.'' Northern Indiana 
believes the opposite is true, i.e., system performance has a 
significant impact on load models. The goal of the models is to attempt 
to capture system performance.
    1780. MidAmerican supports the proposed clarifications to operating 
steps and to footnote (b). International Transmission states that more 
clarification should be provided for the thresholds of normal and 
emergency ratings. There are potential inconsistencies with respect to 
whether or not an entity can plan to operate above normal ratings, but 
below emergency ratings, and for how long.
    1781. Northern Indiana also takes issue with the NOPR proposal that 
no load or transactions be interrupted except for consequential load 
loss. Attempting to reduce the probability of load loss to zero would 
greatly increase capital spending, and therefore increase rates to 
customers, and all in the name of achieving an unattainable goal. PG&E 
disputes that the Reliability Standard should provide limits on the 
magnitude and duration of consequential load loss. Determining the 
magnitude and consequences of load loss is a factor in the economic 
evaluation during the development of transmission expansion plans. This 
economic evaluation is not an appropriate subject for this Reliability 
Standard. Northern Indiana urges the Commission to acknowledge that 
planning studies by nature must balance infrastructure improvement and 
expansion against site-specific and regional load projections, using 
available resources. It questions whether the NOPR reflects a proper 
balance between the many costs involved and the benefits, if any, that 
would be realized.
    1782. Entergy opposes the Commission's proposed guidance concerning 
footnote (b) to Table 1 for two reasons. First, Entergy believes the 
Commission should give due weight to the technical expertise of NERC 
and permit NERC to address these matters through Reliability Standards 
development process. Second, the Commission's guidance suggests that it 
views all transmission outages as having the same level of importance 
to and impact on the interconnected transmission grid. Entergy states 
that the Commission should recognize that the effect of transmission 
outages can be local in nature and have no impact on the reliability of 
the Bulk Power System. Removing the transmission operator's ability to 
shed load or enact other system adjustments as appropriate for a single 
contingency would result in significant facility upgrade costs simply 
to avoid the consequence of a local outage. Entergy requests that the 
Commission clarify that its guidance does not constrain the 
transmission operator's ability to determine the best course of action 
to take to address any reliability constraint that may result from 
these local outages.
    1783. PG&E disagrees with the Commission's proposal to delete from 
footnote (b) of this Reliability Standard the phrase ``to prepare for 
the next contingency, system adjustments are permitted, including 
curtailments of contracted Firm (non-recallable reserved) electric 
power transfers.'' \455\ PG&E states that this phrase permits critical 
system adjustments to reduce the potential for and impact of future 
contingencies. It would allow re-scheduling power (but not load 
shedding) as part of manual system adjustment after the first Category 
B contingency (first N-1) to bring the system back to a safe operating 
point before the next Category B contingency (second N-1). This phrase 
is consistent with the manual system adjustment allowed in Category 
C.3.\456\ PG&E states that, contrary to the Commission's 
interpretation, footnote (c) does not capture this phrase. The 
difference between footnote (b) as part of Category B and Category C.3 
is that footnote (b) applies before the second N-1, whereas Category 
C.3 applies after the second N-1. Without this phrase in footnote (b), 
no manual system adjustment would be

[[Page 16582]]

allowed after a Category B contingency, which would be inconsistent 
with Category C.3.
---------------------------------------------------------------------------

    \455\ Id. at P 1084.
    \456\ From TPL Standards Table 1, Category C.3 is Category B 
(B1, B2, B3 or B4) contingency, manual system adjustments, followed 
by another Category B (B1, B2, B3 or B4) contingency.
---------------------------------------------------------------------------

    1784. APPA and LPPC recommend that changes to the footnotes of 
Table 1 be subject to the NERC Reliability Standards development 
process. They state that the footnotes have been extensively reviewed 
by technical experts at NERC for several years and currently represent 
a general consensus among these industry technical experts. Changes to 
the footnotes affect Table 1 and have a direct impact on the 
determination of the severity of consequences that were approved along 
with the original standard. APPA also states that consideration of 
reliability impacts of spare equipment strategies and obligations of 
all generators to have the same voltage ride through capabilities are 
important changes that should not be made by Commission fiat.
ii. Commission Determination
    1785. The Commission approves TPL-002-0 as a mandatory and 
enforceable Reliability Standard. In addition, we direct the ERO to 
develop modifications to TPL-002-0 through the Reliability Standards 
development process, as discussed below.
    1786. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, R1.3.2 of TPL-002-0 requires an entity assessing system 
performance to cover ``critical system conditions and study years'' as 
deemed appropriate by the entity performing the study, but it does not 
specify the rationale for determining critical system conditions and 
study years. The Commission directs the ERO to modify TPL-002-0 to 
require that critical system conditions and study years be determined 
in the same manner as it directed with regard to TPL-001-0. The 
Commission's explanation of the need for that change applies equally 
here.
    1787. With regard to Northern Indiana's concerns, we disagree that 
the proposal to address situations in which critical equipment may be 
unavailable for a prolonged period requires planned and forced outage 
schedules for the next ten years. Reliability Standard TPL-002-0 
requires consideration of planned outages at those demand levels for 
which planned outages are performed but does not address situations in 
which critical long lead time equipment, such as a transformer or phase 
angle regulator, may be unavailable for a prolonged period that could 
extend into periods where planned outages of such equipment would not 
normally be performed. Assessments of these situations do not require 
outage schedules for the next ten years but rather identification of 
which facilities are deemed to be critical that have long lead times 
for repair or replacement. Given that planned outage considerations of 
such long lead time equipment are inexorably linked to spare equipment 
strategy, consistent with our discussion of the issue above in 
connection with spare equipment strategy, the Commission directs the 
ERO to modify the Reliability Standard to require assessments of 
planned outages of long lead time critical equipment consistent with 
the entity's spare equipment strategy.
    1788. In the NOPR, the Commission identified an implicit assumption 
in the TPL Reliability Standards that all generators are required to 
ride through the same types of voltage disturbances and remain in 
service after the fault is cleared. This implicit assumption should be 
made explicit. Commenters agree with the proposed requirement for all 
generators to ride through the same set of Category B and C events as 
required for wind generators. The Commission understands that NRC has 
both degraded voltage and loss of voltage requirements. The degraded 
voltage requirement allows the voltage at the auxiliary power system 
busses to go below the minimum value for a time frame that is usually 
much longer than normal fault clearing time.\457\ If a specific nuclear 
power plant has an NRC requirement that would force it to trip off-line 
if its auxiliary power system voltage was depressed below some minimum 
voltage, the simulation should include the tripping of the plant in 
addition to the faulted facilities. In this regard, the Commission 
agrees that NRC requirements should be used when implementing the 
Reliability Standards. Using NRC requirements as input will assure that 
there is consistency between the Reliability Standards and the NRC 
requirement that the system is accurately modeled. Accordingly, the 
Commission directs the ERO to modify the Reliability Standard to 
explicitly require either that all generators are capable of riding 
through the same set of Category B and C contingencies, as required by 
wind generators in Order No. 661, or that those generators that cannot 
ride through be simulated as tripping. If a generator trips due to low 
voltage from a single contingency, the initial trip of the faulted 
element and the resulting trip of the generator would be governed by 
Category B contingencies and performance criteria.
---------------------------------------------------------------------------

    \457\ 10 CFR 50, Appendix a, GDC17.
---------------------------------------------------------------------------

    1789. The Commission agrees with NRC that for operations purposes 
the N-1 condition is always analyzed from the conditions being 
experienced. In other words, allowing for the 30 minute system 
adjustment period, the system must be capable of withstanding an N-1 
contingency, with load shedding available to system operators as a 
measure of last resort to prevent cascading failures. However, for 
planning purposes, a different analysis applies. The N-1 condition is a 
Category B event under TPL-002-0, and, following the N-1 contingency, 
the system must be stable and thermal loading and voltages be within 
applicable limits. Some adjustment of generation or other controls is 
permitted to return loadings to within continuous ratings, provided the 
loadings before adjustments are within the emergency or short-term 
ratings. Under TPL-002-0 the system is not required to be able to 
withstand another N-1 contingency. That N-1 requirement is a Category C 
contingency which is addressed by TPL-003-0. The Commission has 
addressed NRC's comment concerning N-1 contingencies in real-time 
operation in TOP-002. In regard to the specific revisions proposed by 
NRC, the Commission directs the ERO to consider these as part of the 
Reliability Standards development process.
    1790. In regard to Northern Indiana's comment concerning the load 
modeling statement made in the NOPR, it should be clear that the 
context of the discussion is system performance during simulations. 
Load models used in simulations clearly should, to the extent feasible, 
represent the actual performance of the aggregate mix of industrial, 
commercial and residential loads. If the load model representations 
used in simulations do not mirror the actual performance of loads, 
especially during dynamic simulations, but also when carrying out 
voltage stability studies, the simulation results will not be accurate. 
Because load representation in simulations has a significant impact on 
simulation results and often load models are not well known, it is 
common practice for planners to perform sensitivity studies with a 
range of load models. Accordingly, as proposed in the NOPR, the 
Commission directs the ERO to modify the Reliability Standard to 
require documentation of load models used in system studies and the 
supporting rationale for their use.
    1791. In the NOPR, the Commission set forth its rationale for 
proposing that the ERO clarify the phrase ``permit operating steps 
necessary to maintain system control'' in footnote (a) to Table 1.\458\ 
Specifically, the Commission stated that the operating steps required

[[Page 16583]]

to relieve emergency loadings and return the system to a normal state 
should not include firm load shedding. MidAmerican agrees with the 
Commission. International Transmission states clarification is required 
on the thresholds for normal and emergency ratings and, in particular, 
on whether an entity can plan to operate above normal ratings but below 
emergency ratings and for how long. The Commission agrees that this 
issue requires clarification and therefore directs the ERO to modify 
the standard to clarify the phrase of footnote (a) that states ``permit 
operating steps necessary to maintain system control'' to clarify the 
use of emergency ratings.
---------------------------------------------------------------------------

    \458\ NOPR at P 1083.
---------------------------------------------------------------------------

    1792. The Commission stated in the NOPR that footnote (b) raises 
three issues that need to be addressed.\459\ Two relate to the use of 
planned or controlled load interruption under certain circumstances, 
and the third relates to the use of system adjustments including 
curtailment of firm transfers to prepare for the next contingency. 
Northern Indiana and Entergy disagree with the Commission's proposal to 
modify footnote (b) to state that load shedding for a single 
contingency is not permitted except in very special circumstances where 
such interruption is limited to the firm load associated with the 
failure (consequential load loss). The commenters argue that the impact 
of transmission outages can be local in nature and have no impact on 
the reliability of the Bulk-Power System and that removing the option 
to shed load in a local area for a single contingency would result in 
significant facility upgrade costs and therefore increased rates to 
customers simply to avoid a local outage. Entergy seeks clarification 
that the Commission does not intend to constrain the transmission 
operator's ability to determine the best course of action to address 
local reliability constraints.
---------------------------------------------------------------------------

    \459\ Id. at P 1084.
---------------------------------------------------------------------------

    1793. The NOPR proposed a modification that would clarify footnote 
(b) as disallowing loss of such firm load or the curtailment of firm 
transactions after a first contingency of the bulk electric system. In 
its comments to the Staff Preliminary Assessment, NERC agreed with this 
interpretation, representing that a practice that permits the planned 
interruption of ``firm transmission service'' is a misapplication of 
the Reliability Standard.\460\ Some commenters now argue otherwise, and 
in some cases cite examples where, based on a balance of economic and 
reliability considerations, it may be preferable to plan the bulk 
electric system in such a manner that contemplates the interruption of 
some firm load customers in the event of a N-1 contingency. We view 
these arguments as based largely on the matter of economics, not 
reliability, with the underlying premise that it is not economically 
feasible to invest in the bulk electric system to the point that it can 
continue service to all firm load customers under some specific N-1 
scenarios. Therefore, they argue, the ambiguities of footnote (b) 
should be interpreted to allow that an entity plan for some amount of 
load loss to avoid costly infrastructure investments.
---------------------------------------------------------------------------

    \460\ ``NERC standards, including footnote (b), are not intended 
to endorse or approve planning the interconnection using radial 
configurations as a preferred method for reliably serving load, nor 
do NERC standards consider load shedding acceptable for a single 
contingency.'' NERC comments to the Staff Preliminary Assessment at 
57-58.
---------------------------------------------------------------------------

    1794. The Commission considers this matter to be a fundamental 
issue of transmission service. Indeed, the ERO's definition of ``firm 
transmission service'' specifically states that it is the ``highest 
quality (priority) service offered to customers under a filed rate 
schedule that anticipates no planned interruption.''
    1795. Based on the record before us, we believe that the 
transmission planning Reliability Standard should not allow an entity 
to plan for the loss of non-consequential load in the event of a single 
contingency.\461\ The Commission directs the ERO to clarify the 
Reliability Standard. Regarding the comments of Entergy and Northern 
Indiana that the Reliability Standard should allow entities to plan for 
the loss of firm service for a single contingency, the Commission finds 
that their comments may be considered through the Reliability Standards 
development process. However, we strongly discourage an approach that 
reflects the lowest common denominator.\462\ The Commission also 
clarifies that an entity may seek a regional difference to the 
Reliability Standard from the ERO for case-specific circumstances.
---------------------------------------------------------------------------

    \461\ Consequential load is the load that is directly served by 
the elements that are removed from service as a result of the 
contingency.
    \462\ See Order No. 672 at P 329.
---------------------------------------------------------------------------

    1796. PG&E disputes that the Reliability Standard should provide 
limits on the magnitude and duration of consequential load loss, as 
this is an economic evaluation and is not an appropriate goal for this 
Reliability Standard. The Commission disagrees. Indeed in its comments 
to the Staff Preliminary Assessment, the ERO raised the issue of what 
is an acceptable magnitude and duration of consequential load 
loss.\463\ The Commission notes that most utilities have guidelines for 
the magnitude and duration of load loss that is acceptable on radial 
facilities before the facilities are looped to provide a second source 
of supply to accommodate load growth. NERC also stated that it 
recognizes that looped configurations are key to the reliable operation 
of the Interconnection and to meet reasonable expectations for reliable 
service to loads.\464\ The Commission, therefore, suggests that the ERO 
consider developing a ceiling on the amount and duration of 
consequential load loss that will be acceptable. If the ERO determines 
that such a ceiling is appropriate, it should be developed through the 
ERO's Reliability Standards development process. Further, we note that 
the DOE thresholds for reporting disturbances on Form EIA-417 would be 
one example of an appropriate starting point for developing such a 
ceiling. These thresholds for load loss are 300 MW for 15 minutes or 
50,000 customers for one hour, whichever is greater.
---------------------------------------------------------------------------

    \463\ NERC Comments to Staff Preliminary Assessment at 56-57.
    \464\ ``NERC recognizes that looped configurations are key to 
the reliable operation of the interconnection, and to meet 
reasonable expectations for reliable service to loads.'' Id. at 57.
---------------------------------------------------------------------------

    1797. The third issue with footnote (b) relates to the Commission's 
proposal in the NOPR to delete the footnote's second sentence, which 
states ``[t]o prepare for the next contingency, system adjustments are 
permitted, including curtailments of contracted Firm (non-recallable 
reserved) electric power transfers.'' \465\ PG&E disagrees with the 
Commission's proposal because it allows re-scheduling power (but not 
load shedding) as part of manual adjustment after the first Category B 
contingency to bring the system back to a safe operating point. The 
Commission agrees that footnote (b) should permit manual adjustments 
including generation redispatch and transmission reconfiguration, but 
not load shedding, to return the system to a normal operating state 
within the time period permitted by the emergency or short term 
ratings. The Commission understands that this is the normal practice 
used by most transmission planners. However, the system adjustments 
permitted in the statement above includes curtailments of contracted 
firm, non-recallable reserved and electric power transfers and this is 
not acceptable for Category B single contingencies. Therefore, the ERO 
should modify the sentence to indicate that manual system adjustments, 
except

[[Page 16584]]

for shedding firm load or curtailment of firm transfers, are permitted 
after the first contingency to bring the system back to a normal 
operating state. The Commission disagrees with PG&E's statement that 
the difference between footnote (b) as part of Category B and Category 
C.3 is that footnote (b) applies before the second N-1 contingency, 
whereas Category C.3 applies after the second N-1 contingency. Rather, 
manual adjustments referred to in both cases apply after the first N-1 
contingency. The Commission, therefore, directs the ERO to modify the 
second sentence of footnote (b) to clarify that manual system 
adjustments other than shedding of firm load or curtailment of firm 
transfers are permitted to return the system to a normal operating 
state after the first contingency, provided these adjustment can be 
accomplished within the time period allowed by the short term or 
emergency ratings.
---------------------------------------------------------------------------

    \465\ NOPR at P 1083.
---------------------------------------------------------------------------

    1798. Accordingly, the Commission approves Reliability Standard 
TPL-002-0 as mandatory and enforceable. In addition, the Commission 
directs the ERO to develop a modification to TPL-002-0 through the 
Reliability Standards development process that: (1) Requires that 
critical system conditions be determined in the same manner as we 
propose to require for TPL-001-0; (2) requires assessments of planned 
outages of long lead time critical equipment consistent with the 
entity's spare equipment strategy; (3) requires all generators to ride 
through the same set of Category B and C contingencies as required by 
wind generators in Order No. 661, or to simulate those generators that 
cannot ride through as tripping; (4) requires documentation of load 
models used in system studies and supporting rationale for their use; 
(5) clarifies the phrase ``permit operating steps necessary to maintain 
system control'' in footnote (a) and the use of emergency ratings and 
(6) clarifies footnote (b) in regard to load loss following a single 
contingency, specifying the amount and duration of consequential load 
loss and system adjustments permitted after the first contingency to 
return the system to a normal operating state, as discussed above.
d. System Performance Following Loss of Two or More Elements (TPL-003-
0)
    1799. Reliability Standard TPL-003-0 seeks to ensure that the 
future Bulk-Power System is planned to meet the system performance 
requirements of a system with the loss of multiple elements. It does 
this by requiring that the transmission planner and the planning 
authority annually evaluate and document the ability of its 
transmission system to meet the performance requirements of Category C 
contingencies specified in Table 1 (i.e., events resulting in the loss 
of two or more elements) for both the near-term and the longer-term 
planning horizons. TPL-003-0 requires the preparation of a documented 
plan to achieve the necessary performance requirements if the system is 
unable to meet the Category C performance criteria.
    1800. TPL-003-0 applies to each planning authority and transmission 
planner. They must demonstrate annually through valid assessments that 
their portion of the interconnected transmission system is planned to 
meet the performance requirements of Category C with all transmission 
facilities in service over a planning horizon that takes into account 
lead times for corrective plans. The Reliability Standard also requires 
the applicable entities to consider planned outages of transmission 
equipment for those demand levels for which they perform such outages. 
The Reliability Standard defines various categories of conditions to be 
simulated. The specific study elements selected from each of the 
categories for assessments, including the subset of Category C 
contingencies to be evaluated, require approval by the associated 
regional reliability organization.
    1801. The Commission proposed in the NOPR to approve Reliability 
Standard TPL-003-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
we proposed to direct NERC to submit a modification to TPL-003-0 that: 
(1) Requires that critical system conditions be determined by 
conducting sensitivity studies (as elaborated in our discussion of TPL-
001-0); (2) makes certain clarifications to footnote (c) to Table 1; 
(3) requires the applicable entities to define and document the proxies 
necessary to simulate cascading outages and (4) tailors the purpose 
statement to reflect the specific goal of the Reliability Standard.
    1802. The Commission also sought comments on one potential addition 
to TPL-003-0. It noted that Category C3 of this Reliability Standard 
involves a situation in which two single contingencies occur, with 
manual system adjustments permitted after the first contingency to 
prepare for the next one (generally referred to as N-1-1). However, the 
Commission also noted that should the second contingency occur before 
the manual system adjustments can be completed, the local area and 
potentially the system would be exposed to risk of cascading outages. 
For that reason some entities plan and operate their systems so that 
they are able to withstand the simultaneous occurrence of the two 
contingencies (normally referred to as N-2) for major load pockets. The 
Commission sought comments on the value and appropriateness of 
including such a requirement in TPL-003-0.
i. Comments
    1803. LPPC recommends that changes to footnotes of Table 1 be 
subject to the NERC Reliability Standards development process. It 
states that the footnotes have been extensively reviewed by technical 
experts at NERC for several years and currently represent a general 
consensus among these industry technical experts which should be given 
due weight by the Commission. Changes to the footnotes impact Table 1 
and have a direct impact on the determination of the severity of 
consequences that were approved along with the original Reliability 
Standard.
    1804. FirstEnergy supports the proposed requirement to document 
proxies of subsequent line trips due to thermal overload and low 
voltage generation trips to evaluate potential cascading conditions. 
FirstEnergy states it currently is required to account for these items 
in its planning process.
    1805. EEI questions the value of providing proxies when planners 
conduct thousands of studies based on combinations of contingencies 
under a broad range of circumstances and conditions, especially in 
longer-term planning horizons where the uncertainty around the value of 
any one variable is already very high. SoCal Edison states that one can 
determine the cascading outages in load flow studies. In transient 
stability studies, if the outage is severe, then the thermal overload 
relays and undervoltage relays, if modeled, will trip the load. If the 
load tripped was not planned to be tripped for this outage, then the 
planning authority should take the necessary steps to avoid this 
situation, as cascading is not allowed.
    1806. LPPC and Northern Indiana oppose the proposal to require 
proxies necessary to simulate cascading outages be defined and 
documented. Northern Indiana states that there is no consensus on what 
these proxies should be. LPPC states that utility planners have 
traditionally used their engineering judgment to simulate a 
conservative estimate of the level of thermal overload or low voltage 
that will cause the likelihood of subsequent line or generator trips 
and cascading events. LPPC states that this approach has been

[[Page 16585]]

successful, and NERC should not be asked to second-guess the decisions 
of operators in this area. That could result in the adoption of less 
conservative, least common denominator, design assumptions across all 
regions and reduce modeling flexibility and use of engineering 
judgment. Proxies are typically tailored to specific systems because 
the development of proxies is highly dependent on regional differences 
and localized knowledge. If the Commission determines that independent 
review of utility outage simulation proxies is necessary, Regional 
Entities should conduct that review, because they better understand the 
regional and localized factors that influence the proxies.
    1807. EEI requests that the Commission clarify the meaning of the 
term ``controlled load interruption'' and the meaning of its statement 
that ``to avoid undue negative impact on competition, third party 
studies could be permitted to implement the same or less controlled 
load interruption as used by the transmission owner.'' \466\
---------------------------------------------------------------------------

    \466\ Id. at P 1097.
---------------------------------------------------------------------------

    1808. NRC states that this Reliability Standard should be clarified 
in regard to the N-1-1 condition. In addition, it recommends specific 
changes to Requirements R1.6, R.1.2 and R2.2.
    1809. A number of commenters respond to the Commission's request 
for comments on the value and appropriateness of including the ability 
of the system to withstand two simultaneous contingencies for major 
load pockets. NERC states that this issue has been recognized as 
needing clarification, and it welcomes comments in the development of 
these revisions in accordance with its Reliability Standards 
development process. NERC states that it is developing a proposal for a 
transmission availability data system that will provide a quantitative 
(probabilistic) basis for judging the likelihood of various multi-
element contingencies which will be helpful in determining the value of 
this proposal.
    1810. APPA, LPPC and National Grid state that imposing N-2 planning 
may be difficult to administer since there is no consensus on what 
constitutes a ``major load pocket.'' LPPC states that the definition of 
major load pockets has been, and is still being debated. As there is no 
nation-wide consensus on the term's definition, no list of major load 
pockets exists. Because load pockets and their boundaries change with 
the dynamically changing system and load patterns, it is difficult to 
establish or administer a rule that encompasses the particular sub-
region to which such an N-2 requirement would apply.
    1811. APPA and EEI believe such provisions would significantly 
expand planning requirements for extremely unlikely events that in most 
cases are not cost effective to build into system planning decisions. 
They explain that the Reliability Standard currently includes the more 
likely situation, i.e., where two events occur in a time frame that 
allows some time to adjust in response to the first event. APPA and EEI 
state that various planning entities may, of course, study much more 
extreme events, including the hypothetical the Commission poses, 
especially if formal state or regional planning requires such studies, 
and actual preparation for extreme events is viewed as cost-effective 
in a particular area. However, this level of planning sensitivity is 
simply unnecessary for many regions of the country. They ask that if 
the Commission envisions changes to provide for N-2 service to load 
pockets, a dialogue must first be initiated within the industry and 
with state public utility commissions to identify such load pockets, 
target the required transmission investments (which could be very 
substantial) and develop plans for allocating the costs of such 
investments.
    1812. FirstEnergy comments that, although simultaneous C.3 
independent contingencies may pose potentially high risk, they are most 
likely extremely low in probability. FirstEnergy states that it 
nevertheless routinely evaluates these contingencies across its system 
for facilities 200 kV and higher and suggests that if this analysis is 
made a requirement, it should be limited to an extra high voltage 
subset of the Bulk-Power System.
    1813. MISO believes that evaluation of multiple contingency events 
should only reside in the planning arena and not in the operations 
environment. It states that the current Reliability Standard provides a 
reasonable and time tested methodology.
    1814. National Grid opposes applying this N-2 criterion across the 
board. It states that N-2 planning is usually relied upon when a 
particular area does not have the resources or flexibility to adopt the 
N-1-1 approach. The Bulk-Power System is designed differently in every 
region, and there is no need to impose N-2 planning where regions are 
satisfactorily implementing the N-1-1 methodology.
    1815. SDG&E states that the N-2 consideration for major load 
pockets is neither of value nor appropriate for transmission planning 
entities at large. The probability of such a contingency for a major 
load pocket is very low, and the costs for addressing such a remote 
contingency would be significant. SoCal Edison states the potential 
number of multi-contingency events that could be studied under TPL-003-
0 is staggering. Planners should be given flexibility to select 
generation and transmission elements that reflect a broad range of 
potential combinations without having to commit resources to conduct 
potentially hundreds or thousands of contingency studies. Northern 
Indiana contends that this requirement is in effect a third back-up 
capability, that it would be prohibitive in terms of time and cost, and 
that it would take many years to put the infrastructure it would 
require into place.
    1816. PG&E believes there is no need for a general requirement to 
withstand the simultaneous occurrence of any two contingencies for 
major load pockets. It states that IRO-005 provides for contingencies 
that are credible when operating below IROL in current day operations. 
The TPL group of Reliability Standards already require provisions for 
specific circumstances based on evaluations that take into account the 
probability of an outage occurring and the associated consequences when 
transmission plans are developed. PG&E states that TPL-003-0, Category 
C.5 contingency already addresses the more probable simultaneous 
outages (due to common-mode failure) that could occur. PG&E maintains 
that simultaneous occurrence of other contingencies is not credible. 
The principles incorporated in the Reliability Standards require that 
evaluations of credibility be balanced against potential impact, and 
investing resources to prevent improbable events diverts attention and 
focus from more critical Reliability Standards and more probable 
conditions.
ii. Commission Determination
    1817. The Commission approves proposed Reliability Standard TPL-
003-0 as a mandatory and enforceable Reliability Standard. In addition, 
we direct the ERO to develop modifications to TPL-003-0 through the 
Reliability Standards development process, as discussed below.
    1818. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, Requirement R1.3.2 of TPL-003-0 requires an entity assessing 
system performance to cover ``critical system conditions and study 
years'' as deemed appropriate by the entity performing the study, but 
that the Requirement does not specify the rationale for determining 
critical system conditions and study years. The Commission directs the 
ERO to modify TPL-003-0 to require that

[[Page 16586]]

critical system conditions and study years be determined in the same 
manner as we directed with regard to TPL-001-0, for the reasons as set 
forth in our discussion of TPL-001-0.
    1819. The intent underlying the statement that ``to avoid undue 
negative impact on competition, third party studies should be permitted 
to implement the same or less controlled load interruption as used by 
the transmission owner'' is to ensure that third parties have access to 
the same options that the transmission owner uses to alleviate 
reliability constraints including those related to controlled load 
shedding. For example, if a transmission owner designs its system to 
result in a controlled load shedding of 300 MW for Category C 
contingencies, designs proposed for third parties requesting 
interconnections to that system must also be permitted, but not 
required, to have 300 MW of controlled load shedding for the same 
Category C contingencies. The Commission directs the ERO to modify 
footnote (c) of Table 1 to the Reliability Standard to clarify the term 
``controlled load interruption.'' In response to LPPC's comments on 
modification procedures, the Commission agrees that changes to the 
footnotes of Table 1 should be addressed through the ERO's Reliability 
Standards development process.
    1820. The Commission stated in the NOPR that the concern involved 
relates to the use of thermal overloads or low voltage proxies to judge 
the likelihood of subsequent line or generator trips leading to a 
cascading outage.\467\ The Commission agrees with SoCal Edison that, if 
an entity models overload relays, undervoltage relays, all remedial 
action schemes including those of neighboring systems and has a good 
load representation, then proxies are not required. However, due to 
modeling and simulation limitations this is often not the case and 
planners invariably use proxies.\468\ Recognizing this and the range of 
proxies currently in use, the Transmission Issues Subcommittee of the 
NERC Planning Committee recommended that proxies used in simulations be 
defined until such time as improved analytical tools and models are 
available to simulate cascading events.
---------------------------------------------------------------------------

    \467\ Id. at P 1098.
    \468\ See WECC Disturbance Performance Table W-1 and Figure W-1 
of Allowable Effects on other Systems, NERC/WECC Planning Standards 
April 10, 2003.
---------------------------------------------------------------------------

    1821. The Commission disagrees with LPPC that defining and 
documenting proxies will result in the adoption of less conservative, 
least common denominator design assumptions across all regions and 
reduce modeling flexibility and engineering judgment. To the contrary, 
the Commission believes that such sharing of information will improve 
knowledge and understanding and promote a more rigorous approach to 
analyzing cascading outages. The Commission agrees with LPPC that it 
may be preferable for the Regional Entities to conduct the review of 
proxies, because they better understand the regional and localized 
factors that influence the proxies. However, we expect the ERO to 
coordinate between regions to assure that best practices are shared 
among the Regional Entities. Accordingly, the Commission directs the 
ERO to modify the Reliability Standard to require definition and 
documentation of proxies necessary to simulate cascading outages.
    1822. No comments were received on the Commission's proposal that 
the purpose statement of TPL-003-0 be tailored to reflect the specific 
goal of the Reliability Standard. The Commission directs that this 
modification be made. Reliability Standards should be clear and 
unambiguous, and a clear statement of a Reliability Standard's purpose 
and goal is one of the features necessary to achieve this end.
    1823. The NRC's comments on TPL-003-0 parallel its comments on TPL-
002-0. The Commission discussed those comments above, and its 
conclusions there apply equally here. The Commission, for the same 
reasons set forth in our discussion of TPL-002-0, directs the ERO to 
address NRC concerns through its Reliability Standards development 
process.
    1824. The Commission received numerous comments on its request for 
comments on the appropriateness and value of including the ability of 
the system to withstand two simultaneous Category B contingencies for 
major load pockets. The Commission stated that it was aware that 
several entities currently apply this approach and notes that one 
entity was actually commended by NERC for doing so as part of its 
readiness review. FirstEnergy states that it routinely evaluates these 
contingencies across its system for 200 kV and higher. NERC states that 
this issue has been recognized as requiring clarification, and it 
welcomes comments on these revisions in accordance with the Reliability 
Standards development process.
    1825. Many commenters state that, without a consensus on what 
constitutes a major load pocket, little progress can be made in this 
regard. LPPC states that the definition of major load pockets has been 
and is still being debated. National Grid states that N-2 planning is 
usually relied upon when a particular area does not have the resources 
and flexibility to adopt the N-1-1 approach. The Commission agrees with 
National Grid but notes that this is more applicable to the operating 
domain, something that MISO opposes. PG&E states that this approach is 
not necessary because Category C5 already addresses more probable 
simultaneous outages due to common mode failure. The Commission 
disagrees since Category C5 only deals with a loss of any two circuits 
on a multi-circuit tower line and not a simultaneous loss of a line and 
a generator which was envisaged by the request for comments. Many 
commenters indicated that this was a very low probability event and the 
costs for addressing such an event would be significant. As a result, 
EEI states that a dialogue must first be initiated within the industry 
and with state public utility commissions to identify such load 
pockets, to target the required potentially significant transmission 
investments and to develop plans for allocating the costs of such 
investments. In light of these comments, the Commission does not intend 
to recommend action on this issue at this time and, instead, directs 
the ERO to consider the comments in possible future revisions to the 
Reliability Standard.
    1826. Accordingly, the Commission approves Reliability Standard 
TPL-003-0 as mandatory and enforceable. In addition, the Commission 
directs the ERO to develop a modification to TPL-003-0 through the 
Reliability Standards development process that: (1) Requires that 
critical system conditions be determined in the same manner as we 
propose to require for TPL-001-0; (2) modifies footnote (c) to Table 1 
to clarify the term ``controlled load interruption;'' (3) requires 
applicable entities to define and document the proxies necessary to 
simulate cascading outages and (4) tailors the purpose statement to 
reflect the specific goal of the Reliability Standard.
e. System Performance Following Extreme Events (TPL-004-0)
    1827. The goal of Reliability Standard TPL-004-0 is to ensure that 
the future Bulk-Power System is evaluated to assess the risks and 
consequences of an extreme event involving the loss of multiple 
elements. It seeks to do this by requiring the transmission planner and 
the planning authority to evaluate and document annually the risks and 
consequences of Category D contingencies (i.e., extreme events

[[Page 16587]]

resulting in loss of two or more elements or cascading) for the near-
term (five-year) planning horizon.
    1828. TPL-004-0 applies to each planning authority and transmission 
planner. Each must demonstrate annually through valid assessments that 
its portion of the interconnected transmission system is evaluated for 
the risks and consequences of a number of each of the extreme 
contingencies of Category D with all transmission facilities in service 
over a planning horizon that takes into account lead times for 
corrective plans. TPL-004-0 also requires that planned outages of 
transmission equipment be considered for those demand levels for which 
planned outages are performed. It defines various categories of 
conditions to be simulated. The associated regional reliability 
organization must approve the specific study elements selected from 
each of the categories for assessment, including the subset of Category 
D contingencies to be evaluated.
    1829. The Commission proposed in the NOPR to approve Reliability 
Standard TPL-004-0 as mandatory and enforceable. In addition, pursuant 
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, 
we proposed to direct NERC to submit a modification to TPL-004-0 that: 
(1) Requires that critical system conditions be determined in the same 
manner as proposed for TPL-001-0; (2) requires the identification of 
options for reducing the probability or impacts of extreme events that 
cause cascading; (3) requires that, in determining the range of extreme 
events to be assessed, the contingency list of Category D be expanded 
to include recent events and (4) tailors the purpose statement to 
reflect the specific goal of the Reliability Standard.
i. Comments
    1830. MidAmerican supports the Commission's proposed modifications 
to the Reliability Standard as reasonable and agrees with the 
Commission that the Reliability Standard should not require 
improvements for low probability events that cannot be justified.\469\ 
MidAmerican supports developing options for any events listed in TPL-
004-0 that result in cascading outages and suggests use of 
probabilistic estimates to determine which, if any, of the TPL-004 
extreme events options should be estimated to reduce their probability 
or impacts.
---------------------------------------------------------------------------

    \469\ See NOPR at P 1112.
---------------------------------------------------------------------------

    1831. FirstEnergy, EEI, APPA, TVA and Northern Indiana all oppose 
the expansion of the list of extreme contingencies to include natural 
disasters such as hurricanes and ice storms. They state that the 
potential contingencies resulting from this expansion are endless and 
therefore impractical to consider through engineering studies. As a 
result, additional requirements in this Reliability Standard are 
unnecessary. EEI and APPA state that to the extent that such events 
will happen, entities historically have put heavy emphasis on emergency 
planning and procedures, which are addressed by the EOP group of 
Reliability Standards.
ii. Commission Determination
    1832. The Commission approves proposed Reliability Standard TPL-
004-0 as mandatory and enforceable. In addition, we direct the ERO to 
develop modifications to TPL-004-0 through the Reliability Standards 
development process, as discussed below.
    1833. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, Requirement R1.3.2 of TPL-004-0 requires an entity assessing 
system performance to cover ``critical system conditions and study 
years'' as deemed appropriate by the entity performing the study, but 
it does not specify the rationale for determining critical system 
conditions and study years. The Commission directs the ERO to modify 
TPL-004-0 to require that critical system conditions and study years be 
determined in the same manner as we directed with regard to TPL-001-0 
and for the reasons stated there.
    1834. MidAmerican states that it supports the proposal to modify 
TPL-004-0 to require identification of options for reducing the 
probability or impacts of extreme events that cause cascading. 
Accordingly, for the reasons cited in the NOPR, the Commission directs 
the ERO to modify the Reliability Standard to make this modification to 
the Reliability Standard.
    1835. All commenters that responded on the issue opposed the 
Commission's proposal to modify TPL-004-0 to require that, in 
determining the range of the extreme events to be assessed, the 
contingency list of Category D be expanded to include recent events 
such as hurricanes and ice storms. The Commission is not persuaded by 
the commenters' contention that expansion of the extreme events list 
will lead to an endless list of possibilities. The two that the 
Commission used are examples from the general news media. While the 
NOPR referred to two recent events, other examples include: (1) Loss of 
a large gas pipeline into a region or multiple regions that have 
significant gas-fired generation; (2) a successful cyber attack; (3) 
regulation that restricts or eliminates the use of a river or lake or 
other body of water as the cooling source for generation; (4) shutdown 
of a nuclear power plant and other facilities a day or more prior to a 
hurricane, tornado or wildfire, or other event and (5) the loss of 
older transmission lines, which may not be constructed to meet an 
entity's present radial ice loading requirements, while the newer or 
stronger transmission lines remain in service. The above examples are 
not an exhaustive list, however, the Commission would not expect the 
range of scenarios to be much more extensive than this, either. Thus, 
we are not expecting an endless list of scenarios and infinite number 
of combinations in directing this modification. Each event is 
identifiable for each entity based on its topology, facilities and 
generation mix. Accordingly, the Commission directs the ERO to expand 
the list of events with examples of such events identified above.
    1836. The Commission received no comments on its proposal to modify 
the purpose statement of TPL-004-0 to reflect the specific goal of the 
Reliability Standard. The Commission directs that this modification be 
made.
    1837. Accordingly, the Commission approves Reliability Standard 
TPL-004-0 as mandatory and enforceable. In addition, the Commission 
directs the ERO to develop a modification to TPL-004-0 through the 
Reliability Standards development process that: (1) Requires that 
critical system conditions be determined in the same manner as proposed 
for TPL-001-0; (2) requires the identification of options for reducing 
the probability or impacts of extreme events that cause cascading; (3) 
requires that, in determining the range of extreme events to be 
assessed, the contingency list of Category D be expanded to include 
recent events and (4) tailors the purpose statement to reflect the 
specific goal of the Reliability Standard.
f. Regional and Interregional Self-Assessment Reliability Reports (TPL-
005-0)
    1838. Reliability Standard TPL-005-0 seeks to ensure that each 
regional reliability organization conducts reliability assessments of 
its existing and planned regional bulk electric system annually by 
requiring it to assess and document the performance of its power system 
for the current year, the next five years, and to analyze trends for 
the longer-term planning horizons.
    1839. The Commission proposed in the NOPR not to approve or remand

[[Page 16588]]

TPL-005-0, as it applies only to regional reliability organizations.
i. Comments
    1840. EEI comments that TPL-005-0 should be revised to remove the 
regional reliability organizations.
ii. Commission Determination
    1841. Consistent with our discussion in the Common Issues section 
above, we will not approve or remand TPL-005-0 until we receive 
additional information from the ERO.
    1842. In Order No. 890, the Commission stated that there will be a 
series of technical conferences and regional meetings to obtain 
industry input to achieving the goal of regional planning.\470\ The 
Commission encourages the ERO to monitor those proceedings and use the 
results as input to the Reliability Standards development process in 
revising Reliability Standard TPL-005-0 to address regional planning 
and related processes.
---------------------------------------------------------------------------

    \470\ Order No. 890 at P 443.
---------------------------------------------------------------------------

g. Assessment Data From Regional Reliability Organizations (TPL-006-0)
    1843. Reliability Standard TPL-006-0 seeks to ensure that the data 
necessary to conduct reliability assessments is available by requiring 
the regional reliability organization to provide NERC with Bulk-Power 
System data, reports, demand and energy forecasts, and other 
information necessary to assess reliability and compliance with NERC 
Reliability Standards and relevant regional planning criteria.
    1844. The Commission proposed in the NOPR not to approve or remand 
TPL-006-0, as it applies only to regional reliability organizations.
i. Comments
    1845. EEI agrees that TPL-006-0 should be revised to remove the 
regional reliability organizations.
ii. Commission Determination
    1846. Consistent with our discussion in the Common Issues section 
above, the Commission will not approve or remand TPL-006-0.
13. VAR: Voltage and Reactive Control
    1847. The Version 0 Voltage and Reactive Control (VAR) Reliability 
Standard VAR-001-0 is intended to maintain Bulk-Power System facilities 
within voltage and reactive power limits, thereby protecting 
transmission, generation, distribution, and customer equipment and the 
reliable operation of the Interconnection. The Voltage and Reactive 
Control group of Reliability Standards is intended to replace the 
existing VAR-001-0 and consists of two proposed Reliability Standards, 
VAR-001-1 and VAR-002-1, with new Requirements. These two new proposed 
Reliability Standards have been submitted by NERC as part of the August 
28, 2006 Supplemental Filing for Commission review. NERC requested an 
effective date of February 2, 2007 for VAR-001-1, and August 2, 2007 
for VAR-002-1.
a. VAR-001-1 Voltage and Reactive Control
    1848. Reliability Standard VAR-001-1 requires transmission 
operators to implement formal policies for monitoring and controlling 
voltage levels, acquire sufficient reactive resources, specify criteria 
for generator voltage schedules, know the status of all transmission 
reactive power resources, operate or direct the operation of devices 
that regulate voltage and correct IROL or SOL violations resulting from 
reactive resource deficiencies. VAR-001-1 also requires purchasing-
selling entities to arrange for reactive resources to satisfy their 
reactive requirements.
    1849. In the NOPR, the Commission proposed to approve VAR-001-1 as 
mandatory and enforceable. In addition, the Commission proposed to 
direct NERC to submit a modification to VAR-001-1 that: (1) Expands the 
applicability to include reliability coordinators and LSEs; (2) 
includes detailed and definitive requirements on ``established limits'' 
and ``sufficient reactive resources,'' and identifies acceptable 
margins above the voltage instability points; (3) includes Requirements 
to perform voltage stability assessments periodically during real-time 
operations and (4) includes controllable load among the reactive 
resources to satisfy reactive requirements. The Commission also 
requested comments concerning NERC's assertion that all LSEs are also 
purchasing-selling entities, and on the acceptable ranges of net power 
factor range at the interface at which the LSEs receive service from 
the Bulk-Power System during normal and extreme load conditions.
    1850. Most comments address the specific modifications and concerns 
raised by the Commission in the NOPR. Below, we address each topic 
separately, followed by an overall conclusion and summary.
i. Applicability to Load-Serving Entities and Reliability Coordinators
(a) Comments
    1851. EEI agrees with the Commission that the applicability of VAR-
001-1 should be expanded to include reliability coordinators and LSEs.
    1852. MISO contends that the view and role of generator operators, 
transmission operators and reliability coordinators are different, and 
reliability coordinators' monitoring and response requirements are 
addressed elsewhere in the Reliability Standards.
    1853. In response to the Commission's request in the NOPR for 
comments concerning whether all LSEs are also purchasing-selling 
entities, SoCal Edison believes they are distinguishable. It states 
that a purchasing-selling entity, according to the functional model, 
makes financial deals across balancing authorities (from source to 
sink). Within the area of a large balancing authority, such as the 
CAISO, an LSE can serve load from a resource within the balancing 
authority, so that there is no requirement to tag this transaction, and 
technically there is no purchasing-selling entity involved.
    1854. APPA is concerned that requiring VAR-001-1 to be applicable 
to LSEs would require LSEs to conduct various studies and perform 
reliability functions that have been assigned to other functional 
entities. The role of LSEs in voltage stability assessments should be 
limited to coordination and the provision of data. TAPS also questions 
the need to expand applicability of these Reliability Standards to 
LSEs. TAPS maintains that purchasing and selling utilities are already 
subject to the Reliability Standards, and are required to satisfy any 
reactive requirements through purchasing Ancillary Service No. 2 under 
the OATT (or self-supply). TAPS believes that the addition of LSEs as 
an additional applicable entity serves no reliability purpose.
(b) Commission Determination
    1855. In a complex power grid such as the one that exists in North 
America, reliable operations can only be ensured by coordinated efforts 
from all operating entities in long-term planning, operational planning 
and real-time operations. To that end, the Staff Preliminary Assessment 
recommended and the NOPR proposed that the applicability of VAR-001-1 
extend to reliability coordinators and LSEs.
    1856. Since a reliability coordinator is the highest level of 
authority overseeing the reliability of the Bulk-Power System, the 
Commission believes that it is

[[Page 16589]]

important to include the reliability coordinator as an applicable 
entity to assure that adequate voltage and reactive resources are being 
maintained. As MISO points out, other Reliability Standards address 
responsibilities of reliability coordinators, but we agree with EEI 
that it is important to include reliability coordinators in VAR-001-1 
as well. Reliability coordinators have responsibilities in the IRO and 
TOP Reliability Standards, but not the specific responsibilities for 
voltage levels and reactive resources addressed by VAR-001-1, which 
have a great impact on system reliability. For example, voltage levels 
and reactive resources are important factors to ensure that IROLs are 
valid and operating voltages are within limits, and that reliability 
coordinators should have responsibilities in VAR-001-1 to monitor that 
sufficient reactive resources are available for reliable system 
operations. Accordingly, the ERO should modify VAR-001-1 to include 
reliability coordinators as applicable entities and include a new 
requirement(s) that identifies the reliability coordinator's monitoring 
responsibilities.
    1857. The Commission agrees with SoCal Edison that not all LSEs are 
purchasing-selling entities, because not all LSEs purchase or sell 
power from outside of their balancing authority area. This 
understanding is consistent with the NERC functional model and NERC 
glossary. Both LSEs and purchasing-selling entities should have some 
requirements to provide reactive power to appropriately compensate for 
the demand they are meeting for their customers. Neither a purchasing-
selling entity nor a LSE should depend on the transmission operator to 
supply reactive power for their loads during normal or emergency 
conditions.
    1858. VAR-001-1 recognizes that energy purchases of purchasing-
selling entities can increase reactive power consumption on the Bulk-
Power System and the purchasing-selling entities must supply what they 
consume. The Commission agrees with APPA that LSEs would provide data 
for voltage stability assessments. However, the Commission also 
believes that LSEs have an active role in voltage and reactive control, 
since LSEs are responsible for maintaining an agreed-to power factor at 
the interface with the Bulk-Power System.
    1859. While the Commission recognizes the point made by TAPS, that 
purchasing-selling entities are required to satisfy any reactive 
requirements through purchasing Ancillary Service 2 under the 
OATT or self-supply, the Commission disagrees that adding LSEs to this 
Reliability Standard serves no reliability purpose. As discussed in the 
NOPR and the Staff Preliminary Assessment, LSEs are responsible for 
significantly more load than purchasing-selling entities.\471\ The 
reactive power requirements can have significant impact on the 
reliability of the system and LSEs should be accountable for that 
impact in the same ways that purchasing-selling entities are 
accountable, by providing reactive resources, and also by providing 
information to transmission operators to allow transmission operators 
to accurately study the reactive power needs for both the LSEs' and 
purchasing-selling entities' load characteristics.\472\ The Commission 
recognizes that all transmission customers of public utilities are 
required to purchase Ancillary Service No. 2 under the OATT or self-
supply, but the OATT does not require them to provide information to 
transmission operators needed to accurately study reactive power needs. 
The Commission directs the ERO to address the reactive power 
requirements for LSEs on a comparable basis with purchasing-selling 
entities.
ii. Acceptable Ranges of Net Power Factor Range
---------------------------------------------------------------------------

    \471\ NOPR at P 1134.
    \472\ Purchasing selling entities provide information concerning 
their load through the INT series of Reliability Standards. Load 
serving entities would need to provide similar information through 
this Reliability Standard.
---------------------------------------------------------------------------

(a) Comments
    1860. SoCal Edison states that its Bulk-Power System facilities are 
designed and operated to provide a unity power factor during normal 
load conditions, and that during extreme load conditions, this power 
factor could be in the range of 0.95 to 1.0.
    1861. APPA contends that it may be difficult to reach an agreement 
on acceptable ranges of net power factors at the interfaces where LSEs 
receive service from the Bulk-Power System because the acceptable range 
of power factors at any particular point on the electrical system 
varies based on many location-specific factors. APPA further states 
that system power factors will be affected by the transmission 
infrastructure used to supply the load. As an example, APPA states that 
an overhead circuit may operate at a higher power factor than an 
underground cable due to a substantial amount of reactive line 
charging, and that a transmission circuit carrying low levels of real 
power will tend to provide more reactive power, which will affect the 
need to switch off capacitor banks at the delivery point to manage 
delivery power factors.
(b) Commission Determination
    1862. In the NOPR, the Commission asked for comments on acceptable 
ranges of net power factor at the interface at which the LSEs receive 
service from the Bulk-Power System during normal and extreme load 
conditions. The Commission asked for these comments in response to 
concerns that during high loads, if the power factor at the interface 
between many LSEs and the Bulk-Power System is so low as to result in 
low voltages at key busses on the Bulk-Power System, then there is risk 
for voltage collapse. The Commission believes that Reliability Standard 
VAR-001-1 is an appropriate place for the ERO to take steps to address 
these concerns by setting out requirements for transmission owners and 
LSEs to maintain an appropriate power factor range at their interface. 
We direct the ERO to develop appropriate modifications to this 
Reliability Standard to address the power factor range at the interface 
between LSEs and the Bulk-Power System.
    1863. We direct the ERO to include APPA's concern in the 
Reliability Standards development process. We note that transmission 
operators currently have access to data through their energy management 
systems to determine a range of power factors at which load operates 
during various conditions, and we suggest that the ERO use this type of 
data as a starting point for developing this modification.
    1864. The Commission expects that the appropriate power factor 
range developed for the interface between the bulk electric system and 
the LSE from VAR-001-1 would be used as an input to the transmission 
and operations planning Reliability Standards. The range of power 
factors developed in this Reliability Standard provides the input to 
the range of power factors identified in the modifications to the TPL 
Reliability Standards. In the NOPR, the Commission suggested that 
sensitivity studies for the TPL Reliability Standards should consider 
the range of load power factors.\473\
---------------------------------------------------------------------------

    \473\ NOPR at P 1047.
---------------------------------------------------------------------------

iii. Requirements on ``established limits'' and ``sufficient reactive 
resources''
(a) Comments
    1865. Dynegy supports the Commission's proposal to include more 
definitive requirements on ``established

[[Page 16590]]

limits'' and ``sufficient reactive resources.'' It recommends that VAR-
001-1 be further modified to require the transmission operator to have 
more detailed and definitive requirements when setting the voltage 
schedule and associated tolerance band that is to be maintained by the 
generator operator. Dynegy states that the transmission operator should 
not be allowed to arbitrarily set these values, but rather should be 
required to have a technical basis for setting the required voltage 
schedule and tolerance band that takes into account system needs and 
any limitations of the specific generator. Dynegy believes that such a 
requirement would eliminate the potential for undue discrimination, as 
well as the possibility of imposing overly conservative and burdensome 
voltage schedules and tolerance bands on generator operators that could 
be detrimental to grid reliability, or conversely, the imposition of 
too low a voltage schedule and too wide a tolerance band that could 
also be detrimental to grid reliability.
    1866. While MISO supports the concept of including more detailed 
requirements, it believes that there needs to be a definitive reason 
for establishing voltage schedules and tolerances, and that any 
situations monitored in this Reliability Standard need to be limited to 
core reliability requirements.
    1867. EEI seeks clarification about whether the Commission is 
suggesting that reactive requirements should aim for significantly 
greater precision, especially in terms of planning for various 
emergency conditions. If so, EEI cautions the Commission against `` 
`putting too many eggs' '' in the reactive power `basket.' '' \474\ To 
the extent compliance takes place pursuant to all other modeling and 
planning assessments under the other Reliability Standards, EEI 
strongly believes that the Commission should have some high level of 
confidence that the system's reactive power needs can be met 
satisfactorily across a broad range of contingencies that planners 
might reasonably anticipate. Moreover, EEI believes that requirements 
to successfully predict reactive power requirements in conditions of 
near-system collapse would require significantly more creative 
guesswork than solid analysis and contingency planning. For example, 
EEI notes that the combinations and permutations of how a voltage 
collapse could occur on a system as large as the eastern 
Interconnection are numerous.
---------------------------------------------------------------------------

    \474\ EEI at 99.
---------------------------------------------------------------------------

    1868. EEI suggests that, alternatively, the Commission should 
consider that reactive power evaluations should be conducted within a 
process that is documented in detail and includes a range of 
contingencies that might be reasonably anticipated, because this would 
avoid the `one size fits all' problem, where a prescriptive analytical 
methodology does not fit with a particular system configuration. EEI 
believes that this flexible approach would provide a more effective 
planning tool for the industry, while satisfying the Commission's 
concerns over potentially inadequate reactive reserves. MRO notes that 
the need for, and method of providing for, reactive resources varies 
greatly, and if this Reliability Standard is expanded it must be done 
carefully. MRO believes that all entities should not be required to 
follow the same methodology to accomplish the goal of a reliable 
system.
(b) Commission Determination
    1869. In the NOPR, the Commission expressed concern that the 
technical requirements containing terms such as ``established limits'' 
or ``sufficient reactive resources'' are not definitive enough to 
address voltage instability and ensure reliable operations.\475\ To 
address this concern, the NOPR proposed directing the ERO to modify 
VAR-001-1 to include more detailed and definitive requirements on 
``established limits'' and ``sufficient reactive resources'' and 
identify acceptable margins (i.e. voltage and/or reactive power 
margins) above voltage instability points to prevent voltage 
instability and to ensure reliable operations. We will keep this 
direction, and direct the ERO to include this modification in this 
Reliability Standard.
---------------------------------------------------------------------------

    \475\ See NOPR at P 1140.
---------------------------------------------------------------------------

    1870. We recognize that our proposed modification does not identify 
what definitive requirements the Reliability Standard should use for 
``established limits'' and ``sufficient reactive resources.'' Rather, 
the ERO should develop appropriate requirements that address the 
Commission's concerns through the ERO Reliability Standards development 
process. The Commission believes that the concerns of Dynegy, EEI and 
MISO are best addressed by the ERO in the Reliability Standards 
development process.
    1871. In response to EEI's concerns about a prescriptive analytical 
methodology, we clarify that the Commission is not asking that the 
Reliability Standard dictate what methodology must be used to determine 
reactive power needs. Rather, the Commission believes that the 
Reliability Standard would benefit from having more defined 
requirements that clearly define what voltage limits are used and how 
much reactive resources are needed to ensure voltage instability will 
not occur under normal and emergency conditions. For example, in the 
NOPR, the Commission suggested that NERC consider WECC's Reliability 
Criteria, which contain specific and definitive technical requirements 
on voltage and margin application. While we are not directing that the 
WECC reliability criteria be adopted, we believe they represent a good 
example of clearly-defined requirements for voltage and reactive 
margins.
    1872. In sum, the Commission believes that minimum requirements for 
voltage levels and reactive resources should be clearly defined by 
placing more detailed requirements on the terms ``established limits'' 
and ``sufficient reactive resources'' in the Reliability Standard as 
discussed in the NOPR and the Staff Preliminary Assessment. As 
mentioned above, EEI's concerns should be considered in the ERO's 
Reliability Standards development process.
iv. Periodic Voltage Stability Analysis in Real-Time Operations
(a) Comments
    1873. SDG&E supports the NOPR recommendation that a more effective 
requirement could be based on WECC's reliability criteria, which 
contain specific and definitive technical requirements on voltage and 
margin application. MidAmerican and PacifiCorp recommend that the 
``WECC Methods to address voltage stability and settling margins'' 
should be consulted when designing corresponding NERC requirements.
    1874. Xcel Energy recommends that this proposed modification 
instead address requirements to measure reactive power margin for a 
variety of topology conditions. MidAmerican recommends that the 
Commission's proposal be modified to require real-time checks for 
voltage stability assessments only in areas susceptible to voltage 
instability. Alternatively, MidAmerican suggests that the Commission 
``should exempt from these requirements areas that can demonstrate they 
are not susceptible to voltage instability.''
    1875. APPA, SDG&E and EEI all state that they are not aware of 
commercially-available tools to provide real-time transient stability 
assessments as part of an integrated energy management system for 
operators. APPA notes that

[[Page 16591]]

premature reliance on various tools that are now under development but 
not yet operational may jeopardize reliability by providing operators 
with a false sense of security and recommends leaving the decision to 
use such tools to NERC. EEI points out that any tools to conduct the 
analyses recommended by the Commission will require adjustments and 
modifications to improve their capabilities. Therefore, EEI recommends 
that the Commission consider its proposals regarding these standards as 
long-term industry objectives and of a lower priority than other 
Reliability Standards. In addition, it is unclear to EEI whether the 
proposed voltage stability assessments apply to steady-state or dynamic 
analyses, or whether these assessments are of a general nature. Since 
these analyses are technically complex and involve a broad range of 
assumptions regarding system configurations, EEI suggests that the 
Commission provide further guidance.
(b) Commission Determination
    1876. In response to the concerns of APPA, SDG&E and EEI on the 
availability of tools, the Commission recognizes that transient voltage 
stability analysis is often conducted as an offline study, and that 
steady-state voltage stability analysis can be done online. The 
Commission clarifies that it does not wish to require anyone to use 
tools that are not validated for real-time operations. Taking these 
comments into consideration, the Commission clarifies its proposed 
modification from the NOPR. For the Final Rule, we direct the ERO, 
through its Reliability Standards development process, to modify 
Reliability Standard VAR-001-1 to include Requirements to perform 
voltage stability analysis periodically, using online techniques where 
commercially-available, and offline simulation tools where online tools 
are not available, to assist real-time operations. The ERO should 
consider the available technologies and software as it develops this 
modification to VAR-001-1 and identify a process to assure that the 
Reliability Standard is not limiting the application of validated 
software or other tools.
    1877. With respect to MidAmerican's suggestion of exempting areas 
that are not susceptible to voltage instability from the requirement to 
perform voltage stability analysis, the Commission notes that such 
exemption is not appropriate. We draw an analogy between transient 
stability limits and voltage stability limits. The requirement to 
perform voltage stability analysis is similar to existing operating 
practices for IROLs that are dictated by transient stability. Transient 
stability IROLs are determined using the results of off-line simulation 
studies, and no areas are exempt. In real-time operations, these IROLs 
are monitored to ensure that they are not violated. Similarly, voltage 
stability is conducted in the same manner, determining limits with off-
line tools and monitoring limits in real-time operations. Areas that 
are susceptible to voltage instability are expected to run studies 
frequently, and areas that have not been susceptible to voltage 
instability are expected to periodically update their study results to 
ensure that these limits are not encountered during real-time 
operations.
v. Controllable Load
(a) Comments
    1878. SMA supports adoption of the proposal to include controllable 
load as a reactive resource. SMA notes that its members' facilities 
often include significant capacitor banks, and further, reducing load 
can reduce local reactive requirements.
    1879. SoCal Edison suggests caution regarding the Commission's 
proposal to include controllable load as a reactive resource. It agrees 
that, when load is reduced, voltage will increase and for that reason 
controllable load can lessen the need for reactive power. However, 
SoCal Edison believes that controllable load is typically an energy 
product and there are other impacts not considered by the Commission's 
proposal to include controllable load as a reactive resource. For 
example, activating controllable load for system voltage control 
lessens system demand, requiring generation to be backed down. It is 
not clear to SoCal Edison whether any consideration has been given to 
the potential reliability or commercial impacts of the Commission's 
proposal.
(b) Commission Determination
    1880. The Commission noted in the NOPR that in many cases, load 
response and demand-side investment can reduce the need for reactive 
power capability in the system.\476\ Based on this assertion, the 
Commission proposed to direct the ERO to include controllable load 
among the reactive resources to satisfy reactive requirements for 
incorporation into Reliability Standard VAR-001-1. While we affirm this 
requirement, we expect the ERO to consider the comments of SoCal Edison 
with regard to reliability and SMA in its process for developing the 
technical capability requirements for using controllable load as a 
reactive resource in the applicable Reliability Standards.
---------------------------------------------------------------------------

    \476\ See FERC Staff Report, Principles of Efficient and 
Reliable Reactive Power Supply and Consumption (2005), available at 
http://www.ferc.gov/legal/staff-reports.asp.
---------------------------------------------------------------------------

vi. Summary of Commission Determination
    1881. Accordingly, the Commission approves Reliability Standard 
VAR-001-1 as mandatory and enforceable. In addition, pursuant to 
section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the 
Commission directs the ERO to develop a modification to VAR-001-1 
through the Reliability Standards development process that: (1) Expands 
the applicability to include reliability coordinators and LSEs; (2) 
includes detailed and definitive requirements on ``established limits'' 
and ``sufficient reactive resources'' as discussed above, and 
identifies acceptable margins above the voltage instability points; (3) 
includes Requirements to perform voltage stability analysis 
periodically, using online techniques where commercially available and 
offline techniques where online techniques are not available, to assist 
real-time operations, for areas susceptible to voltage instability; (4) 
includes controllable load among the reactive resources to satisfy 
reactive requirements and (5) addresses the power factor range at the 
interface between LSEs and the transmission grid.
b. VAR-002-1
    1882. Reliability Standard VAR-002-1 requires generator operators 
to operate in automatic voltage control mode, to maintain generator 
voltage or reactive power output as directed by the transmission 
operator, and to notify the transmission operator of a change in status 
or capability of any generator reactive power resource. The Reliability 
Standard requires generator owners to provide transmission operators 
with settings and data for generator step-up transformers. In the NOPR, 
the Commission stated its belief that Reliability Standard VAR-002-1 is 
just, reasonable, not unduly discriminatory or preferential and in the 
public interest; and proposed to approve it as mandatory and 
enforceable.
i. Comments
    1883. APPA and SDG&E agree that VAR-002-1 is sufficient for 
approval as a mandatory and enforceable Reliability Standard.
    1884. Dynegy believes that VAR-002-1 should be modified to require 
more detailed and definitive requirements when defining the time frame 
associated with an ``incident'' of non compliance (i.e., each 4-second 
scan, 10-minute

[[Page 16592]]

integrated value, hourly integrated value). Dynegy states that, as 
written, this Reliability Standard does not define the time frame 
associated with an ``incident'' of non-compliance, but apparently 
leaves this decision to the transmission operator. Dynegy believes that 
either more detail should be added to the Reliability Standard to cure 
this omission, or the Reliability Standard should require the 
transmission operator to have a technical basis for setting the time 
frame that takes into account system needs and any limitations of the 
generator. Dynegy believes that this approach will eliminate the 
potential for undue discrimination and the imposition of overly 
conservative or excessively wide time frame requirements, both of which 
could be detrimental to grid reliability.
ii. Commission Determination
    1885. In the NOPR, the Commission commended NERC and industry for 
its efforts in expanding on the Requirements of VAR-002-1 from the 
predecessor standard, and noted that the submitted Reliability Standard 
includes Measures and Levels of Non-Compliance to ensure appropriate 
generation operation to maintain network voltage schedules. 
Accordingly, the Commission approves Reliability Standard VAR-002-1 as 
mandatory and enforceable.
    1886. Dynegy has suggested an improvement to Reliability Standard 
VAR-002-1, and NERC should consider this in its Reliability Standards 
development process.
14. Glossary of Terms Used in Reliability Standards
    1887. NERC's glossary is updated whenever a new or revised 
Reliability Standard is approved that includes a new defined term. The 
glossary may also be approved by a separate action using NERC's 
Reliability Standards development process. NERC updated the glossary in 
its August 28, 2006 Supplemental Filing.
    1888. In the NOPR, the Commission proposed to approve the glossary. 
In addition, the Commission proposed to direct NERC to submit a 
modification to the glossary that: (1) Includes the statutory 
definitions of Bulk-Power System, Reliable Operation, and Reliability 
Standard, as set forth in section 215(a) of the FPA; (2) modifies the 
definitions of ``transmission operator'' and ``generator operator'' to 
include aspects unique to ISOs, RTOs and pooled resource organizations; 
(3) modifies the definition of ``bulk electric system'' consistent with 
discussion in the NOPR Common Issues section \477\ and (4) modifies the 
definition of terms concerning reserves (such as operating reserves) to 
include DSM, including controllable load.
---------------------------------------------------------------------------

    \477\ NOPR at P 42-43.
---------------------------------------------------------------------------

a. Comments
    1889. NERC supports the Commission's proposal to approve the 
glossary. APPA supports the Commission's proposal to have NERC 
incorporate the statutory definitions of the terms Bulk-Power System, 
Reliable Operation and Reliability Standard into the NERC glossary, as 
an aide to the development of future NERC Reliability Standards.
    1890. APPA suggests that the Commission permit NERC and industry to 
consider whether any modifications to the terms ``transmission 
operator'' and ``generation operator'' are needed, rather than 
directing NERC to modify these terms. APPA's initial reaction is that 
the existing terms are adequate and accommodate most elements of ISO, 
RTO and pooled resource organization operations. APPA believes that a 
broader and continuing inquiry is required to address such situations. 
APPA anticipates that many such concerns will arise as NERC and the 
Regional Entities implement the initial compliance program in June 
2007, and states that any additional changes to the glossary should be 
driven by that experience.
    1891. APPA's concerns regarding the Commission proposal to modify 
the definition of terms concerning reserves to include DSM (including 
controllable load) are discussed above in reference to the BAL 
Reliability Standards.
    1892. NERC supports the Commission's proposal to direct NERC to 
complete the necessary improvements to the proposed Reliability 
Standards through the established NERC Reliability Standards 
development process.
    1893. Santa Clara submits that, to eliminate any ambiguity about 
when these definitions of these commonly-used terms apply, a footnote 
should be added to the glossary that states that the definitions 
contained in the glossary are not intended to supersede any definitions 
in a tariff or contract approved or accepted by the Commission.
 b. Commission Conclusion
    1894. The Commission approves the glossary. The terms defined in 
the glossary have an important role in establishing consistent 
understanding of the Reliability Standards Requirements and 
implementation. The approval of the glossary will provide continuity in 
application of the glossary definitions industry-wide, and will 
eliminate multiple interpretations of the same term or function, which 
may otherwise create miscommunication and jeopardize Bulk-Power System 
reliability. The glossary should be updated through the Reliability 
Standards development process whenever a new or revised Reliability 
Standard that includes a new defined term is approved, or as needed to 
clarify compliance activities. For example, the ERO will need to update 
the glossary to reflect modifications required by the Commission in 
this Final Rule.\478\
---------------------------------------------------------------------------

    \478\ See, e.g., MOD-001-0, TOP-002-1 and the INT Reliability 
Standards.
---------------------------------------------------------------------------

    1895. The Commission directs the ERO to modify the glossary through 
the Reliability Standards development process to include the statutory 
definitions of the terms Bulk-Power System, Reliable Operation and 
Reliability Standard. However, this determination does not negate our 
discussion in the Applicability section of the Final Rule. While the 
glossary should be revised to include the stautory definition of Bulk-
Power System, the Reliability Standards refer to the bulk electric 
system, which is also defined in the glossary.
    1896. The Commission directs the ERO to submit a modification to 
the glossary that enhances the definitions of ``transmission operator'' 
and ``generator operator'' to reflect concerns of the commenters and 
the direction provided by the Commission in other sections of this 
Final Rule. The Commission is concerned that there not be any gaps or 
unecessary overlaps of responsibilities concerning any of the 
Requirements in the Reliability Standards that are applicable to 
transmission operators and generator operators.
    1897. Further, we adopt the NOPR proposal to require the ERO to 
submit a modification to the glossary that updates the definition of 
``operating reserves,'' as required in our discussion of BAL-002-0 and 
BAL-005-0.
    1898. Regarding Santa Clara's concern about terms in the glossary 
differing from definitions in tariffs, we clarify that the glossary 
governs Reliability Standards, while tariff definitions govern tariff 
issues. We recognize that many items have different tariff definitions 
from those in the NERC glossary. However, we expect most of these terms 
to be consistent. If the glossary definition creates a conflict between 
the Reliability Standards and a Transmission Organization's function,

[[Page 16593]]

rule, order, tariff, rate schedule, or agreement accepted, approved, or 
ordered by the Commission, then the Transmission Organization shall 
expeditiously notify the Commission, the Electric Reliability 
Organization and the relevant Regional Entity of the possible conflict 
pursuant to Sec.  39.6 of the Commission's regulations.\479\
---------------------------------------------------------------------------

    \479\ 18 CFR 39.6 (2006).
---------------------------------------------------------------------------

    1899. In conclusion, the Commission approves the glossary. Further, 
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our 
regulations, the Commission directs ERO to modify the glossary through 
the Reliability Standards development process to: (1) Include the 
statutory definitions of the terms Bulk-Power System, Reliable 
Operation and Reliability Standard; (2) modify the definition of 
``transmission operator'' and ``generator operator'' to include aspects 
unique to ISO, RTO and pooled resource organizations and (3) modify the 
definition of ``operating reserves'' as discussed in BAL-002-0 and BAL-
005-0.

III. Information Collection Statement

    1900. The Office of Management and Budget (OMB) regulations require 
that OMB approve certain reporting and recordkeeping (collections of 
information) imposed by an agency.\480\ The information collection 
requirements in this Final Rule are identified under the Commission 
data collection, FERC-725A ``Bulk Power System Mandatory Reliability 
Standards.'' Under section 3507(d) of the Paperwork Reduction Act of 
1995,\481\ the proposed reporting requirements in the subject 
rulemaking will be submitted to OMB for review. Interested persons may 
obtain information on the reporting requirements by contacting the 
Federal Energy Regulatory Commission, 888 First Street, NE, Washington, 
DC 20426 (Attention: Michael Miller, Office of the Executive Director, 
202-502-8415) or from the Office of Management and Budget (Attention: 
Desk Officer for the Federal Energy Regulatory Commission, fax: 202-
395-7285, e-mail: [email protected]).
---------------------------------------------------------------------------

    \480\ 5 CFR 1320.11.
    \481\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------

    1901. The ``public protection'' provisions of the Paperwork 
Reduction Act of 1995 requires each agency to display a currently valid 
control number and inform respondents that a response is not required 
unless the information collection displays a valid OMB control number 
on each information collection or provides a justification as to why 
the information collection number cannot be displayed. In the case of 
information collections published in regulations, the control number is 
to be published in the Federal Register.
    1902. Public Reporting Burden: In the NOPR, the Commission based 
its initial estimates on the premise that the proposed Reliability 
Standards have already been in effect for a substantial period of time 
on a voluntary basis and consequently entities would have already put 
them into practice. Seventy of the 125 commenters express concern with 
the burden to be imposed by the NOPR's requirements. The majority of 
these comments address the potential impact the requirements would have 
on small entities but did not provide specific estimates on this 
impact. Because these comments are also the subject of the analysis 
performed under the Regulatory Flexibility Act, the Commission has 
provided a response under that section of this rulemaking. Commenters 
also raise concerns about the impact of specific Reliability Standards, 
and the Commission has addressed those concerns in the discussion of 
each Reliability Standard. Five commenters, Reliant, TAPS, Wisconsin 
Electric, Portland General and WECC questioned the Commission's initial 
burden estimates as contained in the NOPR.
    1903. By Reliant's estimate, it would take at least four employees 
to prepare and submit compliance filings and to monitor compliance on 
an on-going basis. TAPS, while not providing a specific estimate on the 
burden, believes that the NOPR's proposed application of mandatory 
Reliability Standards is overly-broad and would encompass several 
thousand municipal systems. Wisconsin Electric states that the NOPR 
significantly understated the impact that would be imposed by mandatory 
Reliability Standards. Wisconsin Electric believes that a ``typical 
control area utility with its multiple functional entity 
responsibilities'' will need far more than the 100 hours estimated by 
the Commission to manage a quality compliance program as discussed in 
the ERO's Sanction Guidelines.\482\
---------------------------------------------------------------------------

    \482\ Wisconsin Electric at 9.
---------------------------------------------------------------------------

    1904. Portland General believes that meeting the Requirements of 
mandatory Reliability Standards will place an additional burden for 
documentation, over and above compliance with the substance of the 
Requirements. It claims that the NOPR failed to take this additional 
burden into account in its cost estimate for compliance. WECC disagrees 
with the Commission's estimate that compliance cost would be $40 
million annually on an aggregate basis. It also disagrees with the 
Commission's assumption that there would be no increased reporting 
burden or additional information requirements because the Reliability 
Standards impose new documentation requirements that will create 
additional costs.
    1905. In response to the comments and upon further review we have 
revised our initial estimates as reflected in the table below. While 
the ERO has submitted several new Reliability Standards and included 
additional Measures for documenting compliance with 20 existing 
Reliability Standards, we continue to believe that the reporting 
requirements embedded in the Reliability Standards that are approved in 
the Final Rule have been implemented on a voluntary basis for many 
years in most instances.\483\ This would not apply, however, to 
entities that are new to reliability oversight. We encourage entities 
that are responsible for compliance with mandatory Reliability 
Standards to develop a quality compliance program as discussed in the 
ERO's Sanction Guidelines. However, we believe that the costs of such a 
program are distinct from the reporting burdens that are estimated 
below.
---------------------------------------------------------------------------

    \483\ NOPR at P 1157.
---------------------------------------------------------------------------

    1906. Further, our estimates below reflect a revision in the number 
of respondents, based on our determinations regarding 
``applicability,'' as discussed in section II.C above.
    1907. Total Annual Hours for Collection:

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
FERC-725A
    Investor Owned Utilities....................             170               1           2,080         353,600
    Municipals and Cooperatives--Large..........              80               1           1,420         113,600
    Municipals and Cooperatives--Small..........             670               1             710         475,700
    Generator Operators.........................             360               1             500         180,000

[[Page 16594]]

 
    Power Marketers.............................             159               1             100          15,900
    Recordkeeping...............................     Investor Owned Utilities     ..............          35,360
                                                        Munis/Coops (Large)       ..............          11,360
                                                        Munis/Coops (Small)       ..............          47,570
                                                       Generator Owner/Ops.       ..............          18,000
                                                          Power Marketers         ..............           1,590
        Totals..................................  ..............  ..............  ..............      1,252,680
----------------------------------------------------------------------------------------------------------------
(FTE=Full Time Equivalent or 2,080 hours)

    Total Hours = 1,138,800 (reporting) + 113,880 (recordkeeping) = 
1,252,680 hours. This estimated reporting burden will be significantly 
reduced once joint action agencies are established, which will reduce 
the number of small entities that will be responsible for compliance 
with Reliability Standards.
    1908. Information Collection Costs: The Commission sought comments 
about the costs needed to comply with these requirements. As noted 
above, a number of commenters state that the NOPR underestimated the 
burden of the rulemaking in terms of hours required to comply. However, 
no comments were received regarding the Commission's estimate of the 
projected cost of $200/hour to comply with these requirements. In 
further consideration, the Commission believes that the $200/hour 
projection is too high, and the calculations below reflect an adjusted 
hourly figure.
    Cost to Comply:
    Reporting = 1,138,800 @ $114/hour = $129,823,200
    1,138,800 hours @ $114 per hour (average cost of attorney ($200 per 
hour), consultant ($150), technical ($80) and administrative support 
($25)).
    Recordkeeping = 113,880 @ $17/hour = $1,935,960
    113,880 hours @ $17 per hour (file/record clerk @ $17 an hour)
    Total Costs: Reporting ($129,823,200) + Recordkeeping ($1,935,960) 
= $131,759,160.
    Sources: ``NERC Compliance Update: What it might cost to comply'', 
Herb Schrayshuen, NARUC-Electric Reliability Staff Subcommittee, 
November 12, 2006.
    Janco Associates, Inc., 2005 Information Technology Compensation 
Study, January 2005.
    Bureau of Labor Statistics, Department of Labor, Occupational 
Outlook Handbook, http://www.bls.gov/oco/ocos268.htm.
    Titles: FERC-725A ``Mandatory Reliability Standards for the Bulk-
Power System''.
    Action: Proposed Collection of Information.
    OMB Control Nos: To be determined.
    Respondents: Business or other for profit, not for profit 
institutions, state, local or tribal government and Federal Government.
    Frequency of Responses: On occasion.
    Necessity of Information: The Final Rule approves 83 Reliability 
Standards. Compliance with such Reliability Standards will be mandatory 
and enforceable for the applicable categories of entities identified in 
each Reliability Standard. These Reliability Standards are approved by 
the Commission pursuant to its authority under section 215 of the FPA, 
which authorizes the Commission to approve a Reliability Standard 
proposed by the ERO if the Commission determines that it is just and 
reasonable, not unduly discriminatory or preferential and in the public 
interest. The Reliability Standards approved in this Final Rule are 
necessary for the reliable operation of the nation's interconnected 
Bulk-Power System.
    For information on the requirements, submitting comments on the 
collection of information and the associated burden estimates including 
suggestions for reducing this burden, please send your comments to the 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426 (Attention: Michael Miller, Office of the 
Executive Director, 202-502-8415) or send comments to the Office of 
Management and Budget (Attention: Desk Officer for the Federal Energy 
Regulatory Commission, fax: 202-395-7285, e-mail [email protected]).

IV. Environmental Analysis

    1909. 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.\484\ The 
actions taken here fall within the categorical exclusion in the 
Commission's regulations for rules that are clarifying, corrective or 
procedural, for information gathering, analysis, and 
dissemination.\485\
---------------------------------------------------------------------------

    \484\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & 
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \485\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act

    1910. The Regulatory Flexibility Act of 1980 (RFA)\486\ generally 
requires a description and analysis of Final Rules that will have 
significant economic impact on a substantial number of small entities. 
The RFA does not mandate any particular outcome in a rulemaking. It 
only requires consideration of alternatives that are less burdensome to 
small entities and an agency explanation of why alternatives were 
rejected.
---------------------------------------------------------------------------

    \486\ 5 U.S.C. 601-612 (2006).
---------------------------------------------------------------------------

    1911. In drafting a rule an agency is required to: (1) Assess the 
effect that its regulation will have on small entities; (2) analyze 
effective alternatives that may minimize a regulation's impact and (3) 
make the analyses available for public comment.\487\ In its NOPR, the 
agency must either include an initial regulatory flexibility analysis 
(initial RFA) \488\ or certify that the proposed rule will not have a 
``significant impact on a substantial number of small entities.'' \489\
---------------------------------------------------------------------------

    \487\ 5 U.S.C. 601-604.
    \488\ 5 U.S.C. 603(a).
    \489\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

    1912. If in preparing the NOPR an agency determines that the 
proposal could have a significant impact on a substantial number of 
small entities, the agency shall ensure that small entities will have 
an opportunity to participate in the rulemaking procedure.\490\
---------------------------------------------------------------------------

    \490\ 5 U.S.C. 609(a).
---------------------------------------------------------------------------

    1913. In its Final Rule, the agency must also either prepare a 
Final Regulatory Flexibility Analysis (Final RFA) or make the requisite 
certification. Based on the comments the agency receives on the NOPR, 
it can alter its original position as expressed in the NOPR but it is 
not required to make any substantive changes to the proposed 
regulation.
    1914. The statute provides for judicial review of an agency's final 
certification or Final RFA.\491\ An agency must file a

[[Page 16595]]

Final RFA demonstrating a ``reasonable, good-faith effort'' to carry 
out the RFA mandate.\492\ However, the RFA is a procedural, not a 
substantive, mandate. An agency is only required to demonstrate a 
reasonable, good faith effort to review the impact the proposed rule 
would place on small entities, any alternatives that would address the 
agency's and small entities' concerns and their impact, provide small 
entities the opportunity to comment on the proposals, and review and 
address comments. An agency is not required to adopt the least 
burdensome rule. Further, the RFA does not require an agency to assess 
the impact of a rule on all small entities that may be affected by the 
rule, only on those entities that the agency directly regulates and 
that will be directly impacted by the rule.\493\
---------------------------------------------------------------------------

    \491\ 5 U.S.C. 611.
    \492\ United Cellular Corp. v. FCC, 254 F.3d 78, 88 (D.C. Cir. 
2001); Alenco Commuications, Inc. v. FCC, 201 F.3d 608, 625 (5th 
Cir. 2000).
    \493\ Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327 (D.C. 
Cir 1985).
---------------------------------------------------------------------------

A. Notice of Proposed Rulemaking

    1915. In the NOPR, the Commission stated that the proposed 
Reliability Standards ``may cause some small entities to experience 
significant economic impact.'' \494\ In response to the ERO's proposal 
to develop limits on the applicability of specific Reliability 
Standards, the Commission stated that, while it could not rule on the 
merits until a specific proposal is submitted, the Commission stated 
that it believed that reasonable limits based on size may be an 
acceptable alternative to ``lessen the economic impact on the proposed 
rule on small entities.'' \495\ The Commission emphasized that any such 
limits must not weaken Bulk-Power System reliability.
---------------------------------------------------------------------------

    \494\ NOPR at P 1175.
    \495\ Id. at 1176.
---------------------------------------------------------------------------

    1916. Further, under the Applicability Issues section of the NOPR, 
we devoted an entire subsection to the issues facing small 
entities.\496\ The Commission stated that there may be instances in 
which small entity compliance with a particular Reliability Standard 
may be critical to reliability. It explained that, in such 
circumstances, it may be appropriate to differentiate among subsets of 
users, owners and operators. As an example, the NOPR provided that 
``the requirement to have adequate communications capabilities to 
address real-time emergency conditions * * * may be necessary for all 
applicable entities regardless of size or role, although we understand 
that the implementation of these requirements for applicable entities 
may vary based on size or role.'' \497\ Additionally, in the NOPR, the 
Commission supported the ERO's proposal to permit the registration of 
``joint action agencies,'' a concept designed to ease the burden of 
small entities by allowing one organization to perform reliability-
related activities for multiple entities. The Commission proposed to 
direct the ERO to develop procedures that would permit a joint action 
agency or similar organization to accept compliance responsibility on 
behalf of its members.
---------------------------------------------------------------------------

    \496\ Id. at 49-53 (Section B.3 ``Applicability to Small 
Entities'').
    \497\ Id. at 51.
---------------------------------------------------------------------------

    1917. Thus, in the NOPR, the Commission discussed the potential 
disparate impact on small entities, considered the implications and 
potential alternatives and solicited comments on the limiting the 
application of the Reliability Standards to small entities. Further, 
the Information Collection Statement discussed the difficulty 
estimating the number of small entities that would be affected by the 
Reliability Standards. As such, the Commission was aware of the 
potential impacts on small entities and was actively considering 
alternatives that would lessen the impact on them while still ensuring 
reliability of the Bulk-Power System.
1. Comments
    1918. APPA and NRECA, in their joint comments, provide data about 
their membership. APPA states that, based on 2005 data, 1,971 public 
utilities or 98 percent of the public utilities in the United States 
had less than 4 million MW hours in sales which would qualify them as 
small entities. Of these, 90 percent--or 1,775--are distribution-only 
utilities, 48 are wholesale-only, and 148 make both wholesale and 
retail sales.\498\ NRECA states that its membership includes 930 rural 
cooperatives most of which are distribution utilities and almost all of 
which would qualify as small entities. Additionally, according to 
NRECA, 40 of its 65 generation and transmission cooperatives also 
qualify as small entities.\499\
---------------------------------------------------------------------------

    \498\ APPA/NRECA comments at 2.
    \499\ Id.
---------------------------------------------------------------------------

    1919. APPA/NRECA contends that the Commission did not include a 
complete initial RFA analysis as required and, without a full initial 
RFA, the Commission cannot lay a proper foundation for eliciting public 
comments on the impacts of the rule on small entities. Specifically, 
APPA/NRECA contends that the NOPR failed to include proposals that 
would minimize the impact on small entities. They assert that, instead, 
the Commission's proposed definition of bulk electric system in the 
NOPR exceeds NERC's definition and thereby sweeps in many small 
facilities that are unnecessary to the Reliable Operation of the Bulk-
Power System. APPA/NRECA argue that, if the Commission adopts this 
definition, many small transmission owners and operators of lower 
voltage transmission systems will be unnecessarily required to bear the 
increased training costs to comply with Reliability Standards, yet the 
NOPR never considered these additional burdens. APPA/NRECA also asserts 
that, under this definition, many small distribution providers would 
also be required to comply with the communication-related (COM) 
Reliability Standards at additional costs that were never discussed. 
They request that the Commission address these shortcomings.
    1920. APPA/NRECA also claims that the Commission substantially 
underestimated the number of small entities that would be impacted by 
the application of the Reliability Standards as proposed in the NOPR. 
APPA/NRECA asserts that 98 percent of public utilities and 99 percent 
of public cooperatives, along with numerous small industrial 
facilities, small qualifying facilities and small generators would 
qualify under the small entity definition and would be impacted by the 
rule. According to APPA/NRECA, most of these small entities would not 
have a material impact on the reliability of the Bulk-Power System but, 
under the NOPR's definition of Bulk-Power System, would be required to 
comply with the Reliability Standards.
    1921. APPA/NRECA suggests that the Commission can significantly 
reduce the impact on small entities by ``focusing on materiality.'' 
They contend that an overly-expansive reliability regime would violate 
the FPA by imposing unnecessary regulatory burdens on small entities 
and divert the ERO's and the Commission's resources away from those 
entities that are crucial to Bulk-Power System reliability. APPA/NRECA 
asserts that the Commission can ensure reliability without 
unnecessarily burdening small entities by considering two alternatives. 
First, they urge the Commission to adopt NERC's current definition of 
bulk electric system. Second, they ask the Commission to reconsider the 
standard-by-standard approach to defining owners, users and operators 
of the Bulk-Power System and, instead, accept the NERC compliance 
registry to identify the entities that will be responsible for 
compliance with Reliability Standards. APPA/NRECA, TAPS, and numerous

[[Page 16596]]

other commenters discuss these proposals in their comments, which the 
Commission addresses in the Applicability Issues section of the Final 
Rule.\500\
---------------------------------------------------------------------------

    \500\ See Applicability Issues: Bulk-Power System v. Bulk 
Electric System and Applicability to Small Entities, supra sections 
II.C.1-2.
---------------------------------------------------------------------------

    1922. TAPS asserts that the Commission should apply the ERO's 
registration thresholds and, ``absent such limits, the Commission 
cannot satisfy its obligations under the [RFA].'' \501\ Georgia Cities 
asserts that the Commission should adopt reasonable limits on the 
application of the Reliability Standards to small entities, as it 
promised in its RFA statement.
---------------------------------------------------------------------------

    \501\ TAPS at 13.
---------------------------------------------------------------------------

2. Commission Response
    1923. The Commission believes that the NOPR provided a meaningful 
discussion of the impact that the Reliability Standards could have on 
small entities and discussed several potential alternatives. In fact, 
the NOPR contained an entire section on the applicability of the 
proposed standards on small entities.\502\ In that section, the 
Commission discussed various alternatives to lessen the acknowledged 
potential impact on small entities. The Commission indicated its 
receptiveness to the ERO's proposal to develop threshold limits 
regarding the applicability of specific Reliability Standards. The 
Commission also suggested that, where it is necessary for reliability 
that a Reliability Standard apply to small entities, implementation of 
the requirements of such Reliability Standards may vary based on size 
or role. In the NOPR, the Commission set forth another alternative to 
address the potential burden on small entities when it proposed to 
direct the ERO to develop procedures permitting a joint action agency 
or similar organization to accept compliance responsibility on behalf 
of its members.
---------------------------------------------------------------------------

    \502\ NOPR at P 49-53.
---------------------------------------------------------------------------

    1924. As previously stated, the purpose of the RFA is to ensure 
that agencies consider the impact a proposed rule would have on small 
entities and any potential alternatives that would minimize that 
impact. The initial RFA analysis is designed to elicit informed 
comments on the impacts to small entities and alternatives. The 
Commission believes the NOPR achieved this goal. After the NOPR was 
issued, the Commission received over 125 comments and a majority of 
those addressed small entity issues. Further, almost all of the 
commenters addressed the NOPR's proposed interpretation of the 
definition of the bulk electric system, which as APPA/NRECA states 
would have had the greatest impact on small entities.
    1925. In addition to the comments received addressing these issues, 
Commission staff has met with representatives of small entities, 
including APPA and NRECA, and listened to their concerns on the 
potential impacts of the Final Rule and discussed possible 
alternatives.
    1926. Since receiving APPA/NRECA's comments on the RFA, the 
Commission has compiled and reviewed available data on small entities 
and the impact of the Final Rule on such entities. Therefore, the 
Commission believes that any inadequacy that may have existed in the 
NOPR's initial RFA analysis has now been corrected. This Final RFA and 
the alternative proposals adopted herein demonstrate the Commission's 
consideration of the potential burdens that the rulemaking could place 
on small entities.
    1927. As discussed in the Applicability section above, the 
Commission adopts in the Final Rule the current definition of bulk 
electric system. Any possible change to the definition would occur in a 
future Commission proceeding. Further, the Commission has endorsed the 
ERO's compliance registry process to identify the entities that must 
comply with mandatory Reliability Standards.\503\ By adopting these 
alternative proposals, the Commission has been responsive to small 
entity concerns and greatly reduced the number of small entities that 
will be affected by the Final Rule.
---------------------------------------------------------------------------

    \503\ As noted previously, APPA, NRECA and TAPs submitted 
supplemental comments supporting the ERO's compliance registry 
process.
---------------------------------------------------------------------------

B. Final RFA

1. Description of the Reasons Why Action by the Agency Is Being 
Considered
    1928. On April 4, 2006, as later modified and supplemented, NERC--
the ERO--submitted 107 Reliability Standards for Commission approval 
pursuant to section 215(d) of the FPA. The ERO's submission includes 
the ``Version 0'' standards with which the electric industry has 
complied on a voluntary basis as well as several new Reliability 
Standards approved by NERC since its certification as the ERO.
    1929. As set forth in section 215(a) of the FPA, the term 
``Reliability Standard'' means a requirement, approved by the 
Commission to provide for the Reliable Operation of the Bulk-Power 
System. The term ``Reliable Operation'' means ``operating the elements 
of the bulk-power system within equipment and electric system, thermal, 
voltage, and stability limits so that instability, uncontrolled, or 
cascaded failures of such system will not occur as a result of a sudden 
disturbance * * * or unanticipated failure of system elements.'' \504\ 
Thus, the purpose of each Reliability Standard approved by the 
Commission in this Final Rule is to provide for the Reliable Operation 
of the Bulk-Power System and thereby minimize the risk of instability, 
uncontrolled or cascading failure on the Bulk-Power System.
---------------------------------------------------------------------------

    \504\ 16 U.S.C. 824o(a)(4) (2006).
---------------------------------------------------------------------------

    1930. The Commission is approving 83 of the proposed Reliability 
Standards. Upon the effective date of the Final Rule, compliance with 
these Reliability Standards will be mandatory and enforceable for 
applicable users, owners and operators of the Bulk-Power System. The 
Commission believes that these Reliability Standards form a solid 
foundation on which to develop and maintain the reliability of the 
North American Bulk-Power System.
2. Objectives of and the Legal Basis for the Final Rule
    1931. This Final Rule requires applicable users, owners and 
operators of the Bulk-Power System to comply with mandatory and 
enforceable Reliability Standards. As discussed above, these 
Reliability Standards are necessary to ensure the reliable operation of 
the North American Bulk-Power System.
    1932. EPAct 2005 added a new section 215 to the FPA, which provides 
for a system of mandatory and enforceable Reliability Standards. 
Section 215(d)(1) of the FPA provides that the ERO must file each 
Reliability Standard or modification to a Reliability Standard that it 
proposes to be made effective, i.e., mandatory and enforceable, with 
the Commission. As mentioned above, on April 4, 2006, and as later 
modified and supplemented, the ERO submitted 107 Reliability Standards 
for Commission approval pursuant to section 215(d) of the FPA.
    1933. Section 215(d)(2) of the FPA provides that the Commission may 
approve, by rule or order, a proposed Reliability Standard or 
modification to a proposed Reliability Standard if it meets the 
statutory standard for approval, giving due weight to the technical 
expertise of the ERO. Alternatively, the Commission may remand a 
Reliability Standard pursuant to section 215(d)(4) of the FPA. Further, 
the Commission may order the ERO to submit to the

[[Page 16597]]

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'' section 215 of the FPA.\505\ The Commission's action in 
this Final Rule is based on its authority pursuant to section 215 of 
the FPA.
---------------------------------------------------------------------------

    \505\ See 16 U.S.C. 824o(d)(5) (2006).
---------------------------------------------------------------------------

3. Significant Issues Raised by Comments, Agency Assessment of the 
Comments and a Statement of Any Changes Made in the Proposed Rule as a 
Result of the Comments
    1934. Numerous small entity commenters oppose the NOPR 
interpretation of bulk electric system and urge the Commission to adopt 
the ERO's current definition of that term. Further, small entity 
commenters oppose the NOPR's proposal to address applicability on a 
standard-by-standard basis and, instead, ask that the Commission rely 
on the ERO's compliance registry process as the means to identify 
entities responsible for complying with mandatory and enforceable 
Reliability Standards. Commenters assert that the Commission's proposed 
changes would greatly increase the number of small entities that would 
be significantly impacted by the Final Rule.
    1935. As discussed above, the Commission is not adopting its 
proposed interpretation of bulk electric system contained in the NOPR. 
Rather, the Commission adopts the NERC definition of bulk electric 
system. Further, the Commission is relying on NERC's registration 
process to provide as much certainty as possible regarding the 
applicability and responsibility of specific entities in the start-up 
phase of the mandatory Reliability Standards regime. Any change in 
these approaches would be addressed in a separate Commission 
proceeding.
    1936. A complete summary of these comments and the Commission's 
response has been previously addressed in the Applicability section.
4. Description and Estimate of the Number of Small Entities To Which 
the Final Rule Will Apply
    1937. According to the SBA, a small electric utility is defined as 
one that has a total electric output of less than four million MWh in 
the preceeding year.
    1938. According to the DOE's Energy Information Administration 
(EIA), there were 3,284 electric utility companies in the United States 
in 2005,\506\ and 3,029 of these electric utilities qualify as small 
entities under the SBA definition. Of these 3,284 electric utility 
companies, the EIA subdivides them as follows: (1) 883 cooperatives of 
which 852 are small entity cooperatives; (2) 1,862 municipal utilities, 
of which 1842 are small entity municipal utilities; (3) 127 political 
subdivisions, of which 114 are small entity political subdivisions; (4) 
159 power marketers, of which 97 individually could be considered small 
entity power marketers; \507\ (5) 219 privately owned utilities, of 
which 104 could be considered small entity private utilities; (6) 25 
state organizations, of which 16 are small entity state organizations 
and (7) nine federal organizations of which four are small entity 
federal organizations.
---------------------------------------------------------------------------

    \506\ See Energy Information Administration Database, Form EIA-
861, Dept. of Energy (2005), available at http://www.eia.doe.gov/cneaf/electricity/page/eia861.html.
    \507\ Most of these small entity power marketers and private 
utilities are affiliated with others and, therefore, do not qualify 
as small entities under the SBA definition.
---------------------------------------------------------------------------

    1939. As discussed above, the Commission is relying on the ERO's 
compliance registry process to identify which entities must comply with 
mandatory and enforceable Reliability Standards. The ERO's Compliance 
Registry Criteria describe how NERC will identify organizations that 
may be candidates for registration and assign them to the compliance 
registry.\508\ According to this document, the ERO will register 
transmission owners and operators with an integrated element associated 
with the Bulk-Power System of 100 kV and above, or lower voltage as 
defined by a Regional Entity. The ERO plans to register only those 
distribution providers or LSEs that have a peak load of 25 MW or 
greater and are directly connected to the bulk electric system or are 
designated as a responsible entity as part of a required underfrequency 
load shedding program or a required undervoltage load shedding program. 
For generators, the ERO plans to register individual units of 20 MVA or 
greater that are directly connected to the bulk electric system, 
generating plants with an aggregate rating of 75 MVA or greater, any 
blackstart unit material to a restoration plan, or any generator 
``regardless of size, that is material to the reliability of the Bulk-
Power System.'' Further, the ERO will not register an entity that meets 
the above criteria if it has transferred responsibility for compliance 
with mandatory Reliability Standards to a joint action agency or other 
organization.
---------------------------------------------------------------------------

    \508\ See NERC Statement of Compliance Registry Criteria 
(Revision 3) at 6-8.
---------------------------------------------------------------------------

    1940. As mentioned above, the SBA defines a small electric utility 
as one that has a total electric output of less than four million MWh 
in the proceeding year. Thus, the set of small entities that must 
comply with mandatory Reliability Standards would be those that exceed 
the ERO registry criteria but still meet the SBA definition. The 
Commission has reviewed data compiled by EIA in Form EIA-861, NERC's 
pre-registry data, and information submitted by commenters, and 
determined an estimate of the number of small entities to which the 
Final Rule will apply.
    1941. The Commission estimates that the Reliability Standards 
approved in the Final Rule will apply to approximately 682 small 
entities (excluding entities in Alaska and Hawaii) as follows: 670 
small municipal utilities and cooperatives and 12 small investor-owned 
utilities.
    1942. As discussed above, the ERO's Compliance Registry Criteria 
allows for a joint action agency, G&T cooperative or similar 
organization to accept compliance responsibility on behalf of its 
members. Once such organizations register with the ERO, the number of 
small entities registered with the ERO will diminish and, thus, 
significantly reduce the impact of the Final Rule on small entities.
    1943. To be included in the compliance registry, the ERO will have 
made a determination that a specific small entity has a material impact 
on the Bulk-Power System. Consequently, the compliance of such small 
entities is justifiable as necessary for Bulk-Power System reliability.
5. Description of the Projected Reporting, Recordkeeping and Other 
Compliance Requirements for Small Entities
    1944. A complete summary of comments and the Commission's response 
has been previously addressed in the Information Collection Statement 
section.
6. Duplication of Other Federal Rules
    1945. There are no relevant Federal rules which may duplicate, 
overlap or conflict with the Final Rule.
7. Description of Any Significant Alternatives to the Final Rule
    1946. In the Final Rule, the Commission adopts several significant 
alternatives that will minimize the burden on small entities. The 
Commission approves the current ERO definition of bulk electric system, 
which

[[Page 16598]]

will reduce significantly the number of small entities responsible for 
complying with the Final Rule. The Commission also approves the ERO 
compliance registry process to identify the entities responsible for 
compliance with mandatory and enforceable Reliability Standards. 
Further, the Commission directs the ERO to submit a procedure to permit 
a joint action agency or similar organization to accept compliance 
responsibility on behalf of its members. A complete summary of comments 
and the Commission's response has been previously addressed in the 
Applicability Section.

VI. Document Availability

    1947. 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, N.E., Room 2A, Washington DC 20426.
    1948. 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.
    1949. User assistance is available for eLibrary and FERC's Web site 
during normal business hours from our Help line at (202) 502-8222 or 
the Public Reference Room at (202) 502-8371 Press 0, TTY (202) 502-
8659. E-mail the Public Reference Room at 
[email protected].

VII. Effective Date and Congressional Notification

    1950. These regulations are effective June 4, 2007. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is 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; reporting and recordkeeping requirements.

By the Commission.
Philis J. Posey,
Acting Secretary.

0
In consideration of the foregoing, the Commission amends Chapter I, 
Title 18, Code of Federal Regulations, by adding Part 40 to read as 
follows:

PART 40--MANDATORY RELIABILITY STANDARDS FOR THE BULK-POWER SYSTEM

Sec.
40.1 Applicability.
40.2 Mandatory Reliability Standards.
40.3 Availability of Reliability Standards.

    Authority: 16 U.S.C. 824o.


Sec.  40.1  Applicability.

    (a) This part applies to all users, owners and operators of the 
Bulk-Power System within the United States (other than Alaska or 
Hawaii), including, but not limited to, entities described in section 
201(f) of the Federal Power Act.
    (b) Each Reliability Standard made effective by Sec.  40.2 must 
identify the subset of users, owners and operators of the Bulk-Power 
System to which a particular Reliability Standard applies.


Sec.  40.2  Mandatory Reliability Standards.

    (a) Each applicable user, owner or operator of the Bulk-Power 
System must comply with Commission-approved Reliability Standards 
developed by the Electric Reliability Organization.
    (b) A proposed modification to a Reliability Standard proposed to 
become effective pursuant to Sec.  39.5 of this Chapter will not be 
effective until approved by the Commission.


Sec.  40.3  Availability of Reliability Standards.

    The Electric Reliability Organization must post on its Web site the 
currently effective Reliability Standards as approved and enforceable 
by the Commission. The effective date of the Reliability Standards must 
be included in the posting.

    Note: The following appendices will not be published in the Code 
of Federal Regulations.


              Appendix A.--Disposition of Reliability Standards, Glossary and Regional Differences
----------------------------------------------------------------------------------------------------------------
         Reliability standard                             Title                        Proposed disposition
----------------------------------------------------------------------------------------------------------------
BAL-001-0.............................  Real Power Balancing Control Performance  Approve.
BAL-002-0.............................  Disturbance Control Performance.........  Approve; direct modification.
BAL-003-0.............................  Frequency Response and Bias.............  Approve; direct modification.
BAL-004-0.............................  Time Error Correction...................  Approve; direct modification.
BAL-005-0.............................  Automatic Generation Control............  Approve; direct modification.
BAL-006-1.............................  Inadvertent Interchange.................  Approve; direct modification.
CIP-001-1.............................  Sabotage Reporting......................  Approve; direct modification.
COM-001-1.............................  Telecommunications......................  Approve; direct modification.
COM-002-2.............................  Communications and Coordination.........  Approve; direct modification.
EOP-001-0.............................  Emergency Operations Planning...........  Approve; direct modification.
EOP-002-2.............................  Capacity and Energy Emergencies.........  Approve; direct modification.
EOP-003-1.............................  Load Shedding Plans.....................  Approve; direct modification.
EOP-004-1.............................  Disturbance Reporting...................  Approve; direct modification.
EOP-005-1.............................  System Restoration Plans................  Approve; direct modification.
EOP-006-1.............................  Reliability Coordination--System          Approve; direct modification.
                                         Restoration.
EOP-007-0.............................  Establish, Maintain, and Document a       Pending.
                                         Regional Blackstart Capability Plan.
EOP-008-0.............................  Plans for Loss of Control Center          Approve; direct modification.
                                         Functionality.
EOP-009-0.............................  Documentation of Blackstart Generating    Approve.
                                         Unit Test Results.
FAC-001-0.............................  Facility Connection Requirements........  Approve.
FAC-002-0.............................  Coordination of Plans for New Facilities  Approve; direct modification.
FAC-003-1.............................  Transmission Vegetation Management        Approve; direct modification.
                                         Program.
FAC-004-0.............................  Methodologies for Determining Electrical  Withdrawn.
                                         Facility Ratings.
FAC-005-0.............................  Electrical Facility Ratings for System    Withdrawn.
                                         Modeling.
FAC-008-1.............................  Facility Ratings Methodology............  Approve; direct modification.
FAC-009-1.............................  Establish and Communicate Facility        Approve.
                                         Ratings.
FAC-012-1.............................  Transfer Capabilities Methodology.......  Pending.

[[Page 16599]]

 
FAC-013-1.............................  Establish and Communicate Transfer        Approve; direct modification.
                                         Capabilities.
INT-001-2.............................  Interchange Transaction Tagging.........  Approve; direct modification.
INT-002-0.............................  Interchange Transaction Tag               Withdrawn.
                                         Communication and Assessment.
INT-003-2.............................  Interchange Transaction Implementation..  Approve.
INT-004-1.............................  Interchange Transaction Modifications...  Approve.
INT-005-1.............................  Interchange Authority Distributes         Approve.
                                         Arranged Interchange.
INT-006-1.............................  Response to Interchange Authority.......  Approve; direct modification.
INT-007-1.............................  Interchange Confirmation................  Approve.
INT-008-1.............................  Interchange Authority Distributes Status  Approve.
INT-009-1.............................  Implementation of Interchange...........  Approve.
INT-010-1.............................  Interchange Coordination Exceptions.....  Approve.
IRO-001-1.............................  Reliability Coordination--                Approve; direct modification.
                                         Responsibilities and Authorities.
IRO-002-1.............................  Reliability Coordination--Facilities....  Approve; direct modification.
IRO-003-2.............................  Reliability Coordination--Wide Area View  Approve; direct modification.
IRO-004-1.............................  Reliability Coordination--Operations      Approve; direct modification.
                                         Planning.
IRO-005-1.............................  Reliability Coordination--Current Day     Approve; direct modification.
                                         Operations.
IRO-006-3.............................  Reliability Coordination--Transmission    Approve; direct modification.
                                         Loading Relief.
IRO-014-1.............................  Procedures, Processes, or Plans to        Approve.
                                         Support Coordination Between
                                         Reliability Coordinators.
IRO-015-1.............................  Notifications and Information Exchange    Approve.
                                         Between Reliability Coordinators.
IRO-016-1.............................  Coordination of Real-time Activities      Approve.
                                         Between Reliability Coordinators.
MOD-001-0.............................  Documentation of TTC and ATC Calculation  Pending; direct modification.
                                         Methodologies.
MOD-002-0.............................  Review of TTC and ATC Calculations and    Pending.
                                         Results.
MOD-003-0.............................  Procedure for Input on TTC and ATC        Pending.
                                         Methodologies and Values.
MOD-004-0.............................  Documentation of Regional CBM             Pending; direct modification.
                                         Methodologies.
MOD-005-0.............................  Procedure for Verifying CBM Values......  Pending.
MOD-006-0.............................  Procedures for Use of CBM Values........  Approve; direct modification.
MOD-007-0.............................  Documentation of the Use of CBM.........  Approve; direct modification.
MOD-008-0.............................  Documentation and Content of Each         Pending; direct modification.
                                         Regional TRM Methodology.
MOD-009-0.............................  Procedure for Verifying TRM Values......  Pending.
MOD-010-0.............................  Steady-State Data for Transmission        Approve; direct modification.
                                         System Modeling and Simulation.
MOD-011-0.............................  Regional Steady-State Data Requirements   Pending; direct modification.
                                         and Reporting Procedures.
MOD-012-0.............................  Dynamics Data for Transmission System     Approve; direct modification.
                                         Modeling and Simulation.
MOD-013-1.............................  RRO Dynamics Data Requirements and        Pending; direct modification.
                                         Reporting Procedures.
MOD-014-0.............................  Development of Interconnection-Specific   Pending; direct modification.
                                         Steady State System Models.
MOD-015-0.............................  Development of Interconnection-Specific   Pending; direct modification.
                                         Dynamics System Models.
MOD-016-1.............................  Actual and Forecast Demands, Net Energy   Approve; direct modification.
                                         for Load, Controllable DSM.
MOD-017-0.............................  Aggregated Actual and Forecast Demands    Approve; direct modification.
                                         and Net Energy for Load.
MOD-018-0.............................  Reports of Actual and Forecast Demand     Approve.
                                         Data.
MOD-019-0.............................  Forecasts of Interruptible Demands and    Approve; direct modification.
                                         DCLM Data.
MOD-020-0.............................  Providing Interruptible Demands and DCLM  Approve; direct modification.
                                         Data.
MOD-021-0.............................  Accounting Methodology for Effects of     Approve; direct modification.
                                         Controllable DSM in Forecasts.
MOD-024-1.............................  Verification of Generator Gross and Net   Pending.
                                         Real Power Capability.
MOD-025-1.............................  Verification of Generator Gross and Net   Pending; direct modification.
                                         Reactive Power Capability.
PER-001-0.............................  Operating Personnel Responsibility and    Approve.
                                         Authority.
PER-002-0.............................  Operating Personnel Training............  Approve; direct modification.
PER-003-0.............................  Operating Personnel Credentials.........  Approve; direct modification.
PER-004-1.............................  Reliability Coordination--Staffing......  Approve; direct modification.
PRC-001-1.............................  System Protection Coordination..........  Approve; direct modification.
PRC-002-1.............................  Define and Document Disturbance           Pending.
                                         Monitoring Equipment Requirements.
PRC-003-1.............................  Regional Requirements for Analysis of     Pending.
                                         Misoperations of Transmission and
                                         Generation Protection Systems.
PRC-004-1.............................  Analysis and Mitigation of Transmission   Approve.
                                         and Generation Protection System
                                         Misoperations.
PRC-005-1.............................  Transmission and Generation Protection    Approve; direct modification.
                                         System Maintenance and Testing.
PRC-006-0.............................  Development and Documentation of          Pending.
                                         Regional UFLS Programs.
PRC-007-0.............................  Assuring Consistency with Regional UFLS   Approve.
                                         Program.
PRC-008-0.............................  Underfrequency Load Shedding Equipment    Approve; direct modification.
                                         Maintenance Programs.
PRC-009-0.............................  UFLS Performance Following an             Approve.
                                         Underfrequency Event.
PRC-010-0.............................  Assessment of the Design and              Approve; direct modification.
                                         Effectiveness of UVLS Program.
PRC-011-0.............................  UVLS System Maintenance and Testing.....  Approve; direct modification.
PRC-012-0.............................  Special Protection System Review          Pending.
                                         Procedure.
PRC-013-0.............................  Special Protection System Database......  Pending.
PRC-014-0.............................  Special Protection System Assessment....  Pending.
PRC-015-0.............................  Special Protection System Data and        Approve.
                                         Documentation.
PRC-016-0.............................  Special Protection System Misoperations.  Approve.
PRC-017-0.............................  Special Protection System Maintenance     Approve; direct modification.
                                         and Testing.

[[Page 16600]]

 
PRC-018-1.............................  Disturbance Monitoring Equipment          Approve.
                                         Installation and Data Reporting.
PRC-020-1.............................  Undervoltage Load Shedding Program        Pending.
                                         Database.
PRC-021-1.............................  Undervoltage Load Shedding Program Data.  Approve.
PRC-022-1.............................  Undervoltage Load Shedding Program        Approve.
                                         Performance.
TOP-001-1.............................  Reliability Responsibilities and          Approve; direct modification.
                                         Authorities.
TOP-002-2.............................  Normal Operations Planning..............  Approve; direct modification.
TOP-003-0.............................  Planned Outage Coordination.............  Approve; direct modification.
TOP-004-1.............................  Transmission Operations.................  Approve; direct modification.
TOP-005-1.............................  Operational Reliability Information.....  Approve; direct modification.
TOP-006-1.............................  Monitoring System Conditions............  Approve; direct modification.
TOP-007-0.............................  Reporting SOL and IROL Violations.......  Approve.
TOP-008-1.............................  Response to Transmission Limit            Approve.
                                         Violations.
TPL-001-0.............................  System Performance Under Normal           Approve; direct modification.
                                         Conditions.
TPL-002-0.............................  System Performance Following Loss of a    Approve; direct modification.
                                         Single BES Element.
TPL-003-0.............................  System Performance Following Loss of Two  Approve; direct modification.
                                         or More BES Elements.
TPL-004-0.............................  System Performance Following Extreme BES  Approve; direct modification.
                                         Events.
TPL-005-0.............................  Regional and Interregional Self-          Pending.
                                         Assessment Reliability Reports.
TPL-006-0.............................  Assessment Data from Regional             Pending.
                                         Reliability Organizations.
VAR-001-1.............................  Voltage and Reactive Control............  Approve; direct modification.
VAR-002-1.............................  Generator Operations for Maintaining      Approve.
                                         Network Voltage Schedules.
Glossary..............................  Glossary of Terms Used in Reliability     Approve; direct modification.
                                         Standards.
Regional Difference...................  BAL-001:ERCOT:CPS2......................  Approve; direct modification.
Regional Difference...................  BAL-006: MISO RTO inadvertent             Approve.
                                         Interchange Accounting.
Regional Difference...................  BAL-006: MISO/SPP Financial Inadvertent   Approve.
                                         Settlement.
Regional Difference...................  INT-001/4: WECC Tagging Dynamic           Pending.
                                         Schedules and Inadvertent Payback.
Regional Difference...................  INT-001/3:MISO Energy Flow Information..  Approve.
Regional Difference...................  INT-003: MISO/SPP Scheduling Agent......  Approve.
Regional Difference...................  INT-003: MISO Enhanced Scheduling Agent.  Approve.
Regional Difference...................  IRO-006: PJM/MISO/SPP Enhanced            Pending.
                                         Congestion Management.
----------------------------------------------------------------------------------------------------------------


        Appendix B.--Commenters on Notice of Proposed Rulemaking
------------------------------------------------------------------------
           Abbreviation                            Entity
------------------------------------------------------------------------
Alberta ESO.......................  Alberta Electric System Operator.
ALCOA.............................  Alcoa, Inc. and Alcoa Power
                                     Generating Company.
Allegheny.........................  Allegheny Power and Allegheny Energy
                                     Supply Company, LLC.
AMP Ohio..........................  American Municipal Power--Ohio, Inc.
APPA..............................  American Public Power Association.
APPA/NRECA........................  APPA/NRECA.
ATC...............................  American Transmission Company, LLC.
Avista/Puget......................  Avista Corporation and Puget Sound
                                     Energy, Inc.
BPA...............................  Bonneville Power Administration.
CAISO.............................  California Independent System
                                     Operator Corporation.
California Cogernation............  Cogeneration Association of
                                     California and the Energy Producers
                                     and Users Coalition.
California PUC....................  Public Utilities Commission of the
                                     State of California.
CEA...............................  Canadian Electricity Association.
Cleveland Public Power............  City of Cleveland, Division of
                                     Cleveland Public Power.
Comverge..........................  Comverge, Inc.
Connecticut Attorney General*.....  Richard Blumenthal, Attorney General
                                     for the State of Connecticut.
Connecticut DPUC*.................  Connecticut Department of Public
                                     Utility Control.
Constellation.....................  Constellation Energy Group.
Dominion..........................  Dominion Resources Services, Inc.
Duke..............................  Duke Energy Corporation.
Dynegy............................  Dynegy, Inc.
EEI...............................  Edison Electric Institute.
ELCON.............................  Electricity Consumers Resource
                                     Council.
Entergy...........................  Entergy Services, Inc.
EPSA..............................  Electric Power Supply Association.
ERCOT.............................  Electric Reliability Council of
                                     Texas, Inc.
Fertilizer Institute..............  Fertilizer Institute.
FirstEnergy.......................  FirstEnergy Service Company.
Georgia Cities....................  City of Acworth.
                                    City of Adel.
                                    City of Blakely.
                                    City of Cairo.
                                    City of Calhoun.
                                    City of Camilla.
                                    City of College Park.

[[Page 16601]]

 
                                    City of Commerce.
                                    City of Doerun.
                                    City of Douglas.
                                    City of East Point.
                                    City of Ellaville.
                                    City of Fairburn.
                                    City of Forsyth.
                                    City of Fort Valley.
                                    City of Grantville.
                                    City of Hogansville.
                                    City of Lafayette.
                                    City of Lagrange.
                                    City of Lawrenceville.
                                    City of Mansfield.
                                    City of Monticello.
                                    City of Moultrie.
                                    City of Norcross.
                                    City of Oxford.
                                    City of Palmetto.
                                    City of Quitman.
                                    City of Sanderville.
                                    City of Sylvester.
                                    City of Thomaston.
                                    City of Thomasville.
                                    City of Washington.
                                    City of West Point.
                                    Crisp County Power Commission.
                                    City of Whigham.
                                    Fitzgerald Water, Light and Bond
                                     Commission.
                                    Marietta Power and Water.
Georgia Operators.................  Georgia System Operators Corp.
International Transmission........  International Transmission Company.
ISO/RTO Council...................  ISO/RTO Council.
ISO-NE............................  ISO New England, Inc.
KCP&L.............................  Kansas City Power and Light Company.
LPPC..............................  Large Public Power Council.
Manitoba..........................  Manitoba Hydro.
Marshall Municipal Utility Group    Massachusetts Department of
 Massachusetts DTE.                  Telecommunications and Energy.
MEAG Power........................  MEAG Power.
MidAmerican.......................  MidAmerican Electric Operating
                                     Companies.
Mid-Continent.....................  Mid-Continent Systems Group.
MISO-PJM..........................  Midwest Independent Transmission
                                     System Operator, Inc. and PJM
                                     Interconnection, L.L.C.
MRO...............................  Midwest Reliability Organization.
NARUC.............................  National Association of Regulatory
                                     Utility Commissioners.
National Grid.....................  National Grid USA.
NCPA..............................  Northern California Power Agency.
NERC..............................  North American Electric Reliability
                                     Corp.
New England Conference of Public    New England Conference of Public
 Utilities Commissioners*.           Utilities Commissioners, Inc.
New York Commission...............  New York State Public Service
                                     Commission.
New York Public Power.............  New York Association of Public
                                     Power.
New York TOs......................  New York Transmission Owners.
Nevada Companies..................  Nevada Power Company and Sierra
                                     Pacific Power Company.
Northeast Utilities...............  Northeast Utilities Service Company.
Northern Indiana..................  Northern Indiana Public Service
                                     Company.
Northwest Requirements Utilities..  Northwest Requirements Utilities.
NPCC..............................  Northeast Power Coordinating
                                     Council: Cross-Border Regional
                                     Entity, Inc.
NRC...............................  United States Nuclear Regulatory
                                     Commission.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
NYSRC.............................  New York State Reliability Council,
                                     LLC.
NY Major Consumers................  Multiple Intervenors, an
                                     unincorporated association of
                                     approximately 55 large industrial,
                                     commercial and institutional end-
                                     use energy consumers with
                                     facilities in New York.
Ontario IESO......................  Ontario Independent Electricity
                                     System Operator.
Otter Tail........................  Otter Tail Power Company.
PG&E..............................  Pacific Gas and Electric Company.
Portland General..................  Portland General Electric Company.
Process Electricity Committee.....  Process Gas Consumers Group
                                     Electricity Committee.
Progress Energy...................  Progress Energy, Inc.
ReliabilityFirst..................  ReliabilityFirst Corporation.
Reliant...........................  Reliant Energy, Inc.

[[Page 16602]]

 
Santa Clara.......................  City of Santa Clara, California.
SDG&E.............................  San Diego Gas and Electric Company.
SERC..............................  SERC Reliability Corporation.
Six Cities........................  Cities of Anaheim, Azusa, Banning,
                                     Colton, Pasadena, and Riverside,
                                     California.
SMA...............................  Steel Manufacturers Association.
Small Entities Forum..............  ReliabilityFirst Corporation Small
                                     Entities Forum.
SoCal Edison......................  Southern California Edison Company.
South Carolina E&G................  South Carolina Electric and Gas
                                     Company.
Southern..........................  Southern Company Services, Inc.
Southwest TDUs....................  Southwest Transmission Dependent
                                     Utility Group.
STI Capital.......................  STI Capital Company.
Tacoma............................  Tacoma Power.
TANC..............................  Transmission Agency of Northern
                                     California.
TAPS..............................  Transmission Access Policy Study
                                     Group.
TVA...............................  Tennessee Valley Authority.
Utah Municipal Power..............  Utah Associated Municipal Power
                                     Systems.
Valley Group......................  The Valley Group, Inc.
WECC..............................  Western Electricity Coordinating
                                     Council.
WIRAB advice......................  Western Interconnection Regional
                                     Advisory Body.
Wisconsin Electric................  Wisconsin Electric Power Company.
Xcel..............................  Xcel Energy Services.
------------------------------------------------------------------------
*Comments filed out-of-time.


               Appendix C: Abbreviations in This Document
------------------------------------------------------------------------
 
------------------------------------------------------------------------
ACE.....................................  Area Control Error.
AGC.....................................  Automatic Generation Control.
ANSI....................................  American National Standards
                                           Institute.
ATC.....................................  Available Transfer Capability.
BCP.....................................  Blackstart Capability Plan.
CBM.....................................  Capacity Benefit Margin.
CPS.....................................  Control Performance Standard.
DC......................................  Direct Current.
DCS.....................................  Disturbance Control Standard.
DSM.....................................  Demand-Side Management.
ERO.....................................  Electric Reliability
                                           Organization.
GWh.....................................  Gigawatt hour.
IEEE....................................  Institute of Electrical and
                                           Electronics Engineers.
IROL....................................  Interconnection Reliability
                                           Operating Limits.
LSE.....................................  Load-serving Entity.
MVAR....................................  Mega Volt Ampere Reactive.
MW......................................  Mega Watt.
ROW.....................................  Right of Way.
SOL.....................................  System Operating Limit.
SPS.....................................  Special Protection System.
TIS.....................................  Transmission Issues
                                           Subcommittee.
TLR.....................................  Transmission Loading Relief.
TRM.....................................  Transmission Reliability
                                           Margin.
TTC.....................................  Total Transfer Capability.
UFLS....................................  Underfrequency Load Shedding.
UVLS....................................  Undervoltage Load Shedding.
------------------------------------------------------------------------

[FR Doc. E7-5284 Filed 4-3-07; 8:45 am]
BILLING CODE 6717-01-P