Document ID: FERC-2006-0792-0004
Agency: ferc
Document Type: Proposed Rule
Title: Mandatory Reliability Standards for the Bulk-Power System
Posted Date: 2006-11-03T05:00Z

[Federal Register: November 3, 2006 (Volume 71, Number 213)]
[Proposed Rules]               
[Page 64769-64879]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr03no06-19]                         
 

[[Page 64769]]

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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; Proposed 
Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

Docket No. RM06-16-000]

 
Mandatory Reliability Standards for the Bulk-Power System

October 20, 2006.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: Pursuant to section 215 of the Federal Power Act (FPA), the 
Commission is proposing to approve 83 of 107 proposed Reliability 
Standards, including six of the eight regional differences, and the 
Glossary of Terms Used in Reliability Standards developed by the North 
American Electric Reliability Council, on behalf of its wholly-owned 
subsidiary, 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 by June 
2007, 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. We therefore propose, pursuant to section 215(d)(5), 
to require the ERO to make significant improvements to many of the 83 
Reliability Standards that are being approved as mandatory and 
enforceable. Appendix D provides a list of the Reliability Standards 
that should be given the highest priority when the ERO undertakes to 
make these improvements. With respect to the remaining 24 Reliability 
Standards, the Commission proposes that they remain pending at the 
Commission until further information is provided. The Commission is not 
proposing to remand any Reliability Standards.
    The Commission proposes to amend the text of its regulation to 
require that each Reliability Standard identify the subset of users, 
owners and operators to which that particular Reliability Standard 
applies. The Commission also is proposing to amend its regulations to 
require that each Reliability Standard that is approved by the 
Commission will be maintained in the Commission's Public Reference Room 
and on the ERO's Internet Web site for public inspection.

DATES: Comments are due January 2, 2007.

ADDRESSES: You may submit comments, identified by Docket No. RM06-16-
000, by one of the following methods:
     Agency Web site: http://ferc.gov. Follow the instructions 

for submitting comments via the eFiling link found in the Comment 
Procedures section of the Preamble.
     Mail: Commenters unable to file comments electronically 
must mail or hand deliver an original and 14 copies of their comments 
to: Federal Energy Regulatory Commission, Office of the Secretary, 888 
First Street. NE., Washington, DC 20426. Refer to the Comment 
Procedures section of the preamble for additional information on how to 
file paper comments.

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 Market and 
Reliability, Division of Policy Analysis and Rulemaking, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
(202) 502-8923.

SUPPLEMENTARY INFORMATION:

                                                               Paragraph
                                                               Numbers

I. Introduction............................................            1
II. Background.............................................           12
    A. Voluntary Reliability Standards.....................           12
    B. EPAct 2005 and Order No. 672........................           15
    C. The Electric Reliability Organization...............           21
    D. NERC Petition for Approval of Reliability Standards.           24
    E. Staff Preliminary Assessment........................           29
III. Discussion............................................           33
    A. The Commission's Reliability Standards Proposal.....           33
        1. Applicability...................................           35
        2. Mandatory Reliability Standards.................           37
        3. Availability of Reliability Standards...........           39
    B. Applicability Issues................................           42
        1. Definition of User of the Bulk-Power System.....           42
        2. Use of the NERC Functional Model................           44
        3. Applicability to Small Entities.................           49
        4. Regional Reliability Organizations..............           54
        5. Bulk-Power System v. Bulk Electric System.......           60
    C. Mandatory Reliability Standards.....................           72
        1. Legal Standard for Approval of Reliability                 72
         Standards.........................................
        2. Commission Options When Acting on a Reliability            76
         Standard..........................................
        3. Prioritizing Modifications to Reliability                  83
         Standards.........................................
        4. Trial Period....................................           90
        5. International Coordination of Remands...........           94
    D. Common Issues Pertaining to Reliability Standards...           96
        1. Blackout Report Recommendations.................           97

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        2. Measures and Levels of Non-Compliance...........          103
        3. Ambiguities and Potential Multiple                        108
         Interpretations...................................
        4. Technical Adequacy..............................          113
        5. Fill-in-the-Blank Standards.....................          116
    E. Discussion of Each Individual Reliability Standard..          124
        1. BAL: Resource and Demand Balancing..............          125
        2. CIP: Critical Infrastructure Protection.........          217
        3. COM: Communications.............................          232
        4. EOP: Emergency Preparedness and Operations......          263
        5. FAC: Facilities Design, Connections,                      343
         Maintenance, and Transfer Capabilities............
        6. INT: Interchange Scheduling and Coordination....          427
        7. IRO: Interconnection Reliability Operations and           497
         Coordination......................................
        8. MOD: Modeling, Data, and Analysis...............          588
        9. PER: Personnel Performance, Training and                  749
         Qualifications....................................
        10. PRC: Protection and Control....................          802
        11. TOP: Transmission Operations...................          951
        12. TPL: Transmission Planning.....................         1037
        13. VAR: Voltage and Reactive Control..............         1129
        14. Glossary of Terms Used in Reliability Standards         1151
IV. Information Collection Statement.......................         1157
V. Environmental Analysis..................................         1171
VI. Regulatory Flexibility Act Certification...............         1172
VII. Comment Procedures....................................         1177
VIII. Document Availability................................         1179
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Appendix A: Proposed Disposition of Standards, Glossary and Regional
 Differences
Appendix B: Commenters on Staff Preliminary Assessment
Appendix C: Abbreviations in this Document
Appendix D: High Priority List

I. Introduction

    1. Pursuant to section 215 of the Federal Power Act (FPA), the 
Commission is proposing to approve 83 of 107 proposed Reliability 
Standards, including six of the eight regional differences, and the 
Glossary of Terms Used in Reliability Standards (glossary) developed by 
the North American Electric Reliability Council, on behalf of its 
wholly-owned subsidiary, 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 by June 
2007, 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. We therefore propose, pursuant to section 215(d)(5), 
to require the ERO to make significant improvements to many of the 83 
Reliability Standards that are being approved as mandatory and 
enforceable. Appendix D provides a list of the Reliability Standards 
that should be given the highest priority when the ERO undertakes to 
make these improvements. With respect to the remaining 24 Reliability 
Standards, the Commission proposes that they remain pending at the 
Commission until further information is provided. The Commission is not 
proposing to remand any Reliability Standards.
    2. The Commission proposes to amend the text of its regulations to 
require that each Reliability Standard identify the subset of users, 
owners, and operators to which that particular Reliability Standard 
applies. The Commission also is proposing to amend its regulations to 
require that each Reliability Standard that is approved by the 
Commission will be maintained in the Commission's Public Reference Room 
and on the ERO's Internet Web site for public inspection.
    3. On August 8, 2005, The Electricity Modernization Act of 2005, 
which is Title XII of the Energy Policy Act of 2005 (EPAct 2005), was 
enacted into law.\1\ 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.
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    \1\ The 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 (2000).
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    4. On February 3, 2006, the Commission issued Order No. 672, which 
implements section 215 of the FPA and provides specific processes for 
the certification of one entity as the ERO, the development and 
approval of mandatory Reliability Standards, and the compliance with 
and enforcement of approved Reliability Standards.\2\ On April 4, 2006, 
NERC made two filings: (1) An application for certification of NERC 
Corporation as the ERO and (2) a petition for Commission approval of 
102 Reliability Standards, as well as eight regional differences and a 
glossary of terms.\3\ On July 20, 2006, the Commission issued an order 
certifying NERC Corporation as the ERO.\4\ This rulemaking proceeding 
addresses NERC's submission of Reliability Standards and represents the 
next

[[Page 64772]]

significant step toward achieving the statutory goal of mandatory and 
enforceable Reliability Standards.
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    \2\ 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).
    \3\ The April 4, 2006 filing contained 102 Reliability 
Standards, a Glossary of Terms Used in Reliability Standards and 
eight regional differences. On August 28, 2006, NERC filed an 
additional 19 Reliability Standards and withdrew three of the 102 
Reliability Standards. Eleven of the nineteen reliability Standards 
replace those filed on April 4, 2006.
    \4\ ERO Certification Order, 116 FERC ] 61,062.
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    5. The ERO's filing is comprehensive, and represents a significant 
effort by NERC, the industry representatives who serve on NERC's 
standards development teams, and the entities that participate in 
NERC's Reliability Standards development process. After the August 2003 
cascading blackout that affected large portions of the central and 
eastern United States and Canada, NERC revised many of the then-
existing NERC operating policies and planning standards to provide 
greater clarity and compliance guidance. These revised standards 
(referred to as ``Version 0'' and ``Version 1'') were developed using 
NERC's American National Standards Institute (ANSI)-accredited 
Reliability Standards development process and are what has been filed 
with the Commission for approval.
    6. The Commission believes that these Reliability Standards will 
form a solid foundation on which to develop and maintain the 
reliability of the North American Bulk-Power System. At the same time, 
the Commission recognizes, as does NERC,\5\ that the Version 0 and 
Version 1 standards were developed as an initial step in the transition 
to clear, enforceable Reliability Standards. As such, some technical, 
enforceability and policy aspects of the 107 proposed Reliability 
Standards submitted by the ERO can, and should, be improved.
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    \5\ See NERC Petition at 69.
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    7. Therefore, in evaluating NERC's proposal, the Commission 
recognizes that the Reliability Standards are in a state of transition 
and that NERC has ongoing plans to improve them. Thus, at this 
juncture, we will approve a proposed Reliability Standard that needs 
clarification, improvement, or strengthening, provided that we are 
confident that it satisfies the statutory requirement that a 
Reliability Standard must be ``just, reasonable, not unduly 
discriminatory or preferential, and in the public interest.'' \6\ 
Rather than remanding an imperfect Reliability Standard, the NOPR 
generally proposes to approve such a Reliability Standard. In addition, 
as a distinct action under the statute, the Commission proposes to 
direct that the ERO modify such a Reliability Standard, pursuant to 
section 215(d)(5) of the FPA, to address the identified issues or 
concerns. This approach would allow the proposed Reliability Standard 
to be enforceable while the ERO develops any required modifications.
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    \6\ 16 U.S.C. 824o(d)(2).
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    8. The Commission believes that, for this period of transition from 
a voluntary to a mandatory system of compliance, the above course of 
action is appropriate when reviewing the ERO's first set of proposed 
Reliability Standards. This action provides the benefit that mandatory 
and enforceable Reliability Standards will be in effect prior to the 
summer of 2007, the next anticipated peak season for the nation's Bulk-
Power System. Critical to our decision to propose to approve such 
Reliability Standards is NERC's representation to the Commission that 
approval of the existing Reliability Standards ``will reinforce the 
importance of these standards and will have an immediate positive 
benefit with regard to the reliability performance of all bulk power 
system owners, operator and users * * *.'' \7\
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    \7\ NERC Petition at 25.
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    9. Accordingly, the Commission proposes to approve the Reliability 
Standards based on recognizing this period of transition, the 
importance of making them mandatory before the summer of 2007, and by 
giving due weight to the technical expertise of the ERO with the 
expectation that the Reliability Standards will accomplish the purpose 
represented to the Commission by the ERO; and that they will improve 
the reliability of the Bulk-Power System by proactively preventing 
situations that can lead to blackouts. By taking this approach, we 
believe that the responsibility for the technical adequacy of the 
proposed Reliability Standards falls squarely on the ERO, and we expect 
the ERO to monitor the effectiveness of the proposed Reliability 
Standards and inform us if any Reliability Standard proves, in 
practice, to be inadequate in protecting and improving Bulk-Power 
System reliability.
    10. Further, the Commission proposes to request additional 
information with regard to 24 proposed Reliability Standards. These 
proposed Reliability Standards would not be approved or remanded by the 
Commission until further action is taken by the ERO. This group of 
Reliability Standards includes NERC's so-called ``fill-in-the-blank'' 
standards that require regional reliability organizations to develop--
and users, owners, or operators to comply with--regional criteria.\8\ 
Until the Commission receives this supplemental information to fill in 
the ``blanks'' \9\ and assurances that the processes to fill in the 
blanks satisfy our procedural requirements, the Commission is not in a 
position to approve or remand such Reliability Standards. Second, a 
proposed Reliability Standard that would apply only to regional 
reliability organizations will not be approved or remanded until the 
ERO identifies a user, owner or operator of the Bulk-Power System as 
the applicable entity.\10\
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    \8\ See id. at 87-90.
    \9\ The ERO is reminded when filling in these blanks that a 
regional difference is generally permitted when it is more stringent 
or when there is a geographical/physical reason for the difference. 
Consolidation of regional standards into a single continent-wide 
standard should not result in a lowest common denominator. Order No. 
672 at P 291.
    \10\ In addition, some of the proposed Reliability Standards 
overlap with other Commission regulatory initiatives. For example, 
in a recent Notice of Proposed Rulemaking, the Commission has 
proposed to direct public utilities, in conjunction with NERC and 
the North American Energy Standards Board to provide for greater 
consistency in Available Transmission Capacity (ATC) calculation. 
See Preventing Undue Discrimination and Preference in Transmission 
Service, 71 FR 32636 (June 6, 2006), 71 FR 39251 (July 12, 2006), 
FERC Stats. & Regs. ] 39,602 (May 19, 2006) (OATT Reform NOPR).
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    11. Although the proposed Reliability Standards for which the 
Commission is requesting additional information will not be enforceable 
under section 215, this does not mean that no standards governing a 
particular matter are in place. Rather, in the interim, though not 
enforceable under section 215, compliance with these Reliability 
Standards would be expected as a matter of good utility practice.

II. Background

A. Voluntary Reliability Standards

    12. In the aftermath of the 1965 blackout in the northeast United 
States, the electric utility industry established NERC, a voluntary 
reliability organization. Since its inception, NERC has developed 
Operating Policies and Planning Standards that provide voluntary 
guidelines for operating and planning the North American Bulk-Power 
System.
    13. A common cause of the past three major regional blackouts was 
violation of NERC's then existing Operating Policies and Planning 
Standards. During July and August 1996, the west coast of the United 
States experienced two cascading blackouts caused by violations of 
voluntary Operating Policies.\11\ In response to the outages, the 
Secretary of Energy convened a task force to advise the U.S. Department 
of

[[Page 64773]]

Energy (DOE) on issues needed to be addressed to maintain the 
reliability of the Bulk-Power System. In a September 1998 report, the 
task force recommended, among other things, that federal legislation 
should grant more explicit authority for the Commission to approve and 
oversee an organization having responsibility for bulk-power 
reliability standards.\12\ Further, the task force recommended that 
such legislation provide for Commission jurisdiction over reliability 
of the Bulk-Power System and Commission implementation of mandatory, 
enforceable reliability standards.
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    \11\ The Electric Power Outages in the Western United States, 
July 2-3, 1996, at 76 (ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/doerept.pdf
) and WSCC Disturbance Report, for the Power System 

Outage that Occurred on the Western Interconnection August 10, 1996, 
at 4 (ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/AUG10FIN.pdf).

    \12\ 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 25-27, 65-67.
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    14. On August 14, 2003, a blackout affected significant portions of 
the Midwest and Northeast United States, and Ontario, Canada. This 
blackout affected an estimated 50 million people and 61,800 megawatts 
of electric load. A joint U.S.-Canada task force studied the causes of 
the August 14, 2003 blackout and determined that several entities 
violated NERC's then-effective Operating Policies and Planning 
Standards, and that several of the standards contained ambiguities that 
rendered the standards ineffective. Those violations and ambiguities 
directly contributed to the blackout.\13\ The joint task force, in its 
recommendations to prevent or minimize the scope of future blackouts, 
identified the need for legislation to make reliability standards 
mandatory and enforceable, with penalties for non-compliance and 
identified specific ambiguities within the standards that should be 
corrected to make the standards effective.\14\
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    \13\ The joint team, known as the U.S.-Canada Power System 
Outage Task Force, issued a Final Report on the August 14, 2003 
Blackout in the United States and Canada: Causes and Recommendations 
(Blackout Report) on April 5, 2004, which presented an in-depth 
analysis of the causes of the blackout and recommendations for 
avoiding future blackouts.
    \14\ See id. at 140-42.
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B. EPAct 2005 and Order No. 672

    15. EPAct 2005 adds a new section 215 to the FPA, which provides 
for a system of mandatory and enforceable Reliability Standards. On 
February 3, 2006, the Commission issued Order No. 672, implementing 
section 215 of the FPA.\15\ Pursuant to Order No. 672, the Commission 
certified one organization, NERC, as the ERO. The ERO is required to 
develop Reliability Standards, which are subject to Commission review 
and approval.\16\ Once approved, the Reliability Standards may be 
enforced by the ERO, subject to Commission oversight.\17\ The 
Reliability Standards will apply to users, owners and operators of the 
Bulk-Power System. The ERO must submit each proposed Reliability 
Standard to the Commission for approval.
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    \15\ Order No. 672, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & 
Regs. ] 31,204 (2006), order on reh'g, Order No. 672-A, 71 FR 19814 
(Apr. 18, 2006), FERC Stats. & Regs. ] 31,212 (2006). Terms defined 
in Order No. 672 are capitalized in this order.
    \16\ 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).
    Section 215(a)(4) of the FPA defines the term ``reliable 
operation'' broadly to mean, ``* * * 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).
    \17\ The Commission can independently enforce Reliability 
Standards. 16 U.S.C. 824o(e)(3).
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    16. 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.\18\ According to this guidance, a proposed 
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 reliability goal and must contain a technically sound means 
to achieve this goal. The proposed Reliability Standard should be clear 
and unambiguous regarding what is required and who is required to 
comply. The possible consequences for violating a proposed Reliability 
Standard should be clear and understandable to those who must comply. 
There should be a clear criterion or measure of whether an entity is in 
compliance with a proposed Reliability Standard. While a proposed 
Reliability Standard does not necessarily need to reflect the optimal 
method for achieving its reliability goal, a proposed Reliability 
Standard should achieve its reliability goal effectively and 
efficiently. A proposed 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.\19\
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    \18\ Order No. 672 at P 262, 321-337.
    \19\ Order No. 672 at P 329.
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    17. A proposed Reliability Standard may take into account the size 
of the entity that must comply and the costs of implementation. 
However, the ERO should not propose standards that would achieve less 
than operational excellence or otherwise be inadequate to support Bulk-
Power System reliability. A proposed 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 
geographic variations in grid characteristics, terrain, weather, and 
other factors. It should 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 proposed Reliability Standard should 
have no undue negative effect on competition.\20\ Order No. 672 directs 
the ERO to explain how the proposal satisfies the factors the 
Commission identified and how the ERO balances any conflicting factors 
when seeking approval of a proposed Reliability Standard.\21\
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    \20\ Order No. 672 at P 332.
    \21\ Id. at P 337.
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    18. Pursuant to section 215(d)(2) of the FPA and section 39.5(c) of 
the Commission's regulations, the Commission is required to 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 is not 
required to defer to the ERO or a Regional Entity with respect to the 
effect of a proposed Reliability Standard or proposed modification to a 
Reliability Standard on competition.\22\
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    \22\ 18 CFR 39.5(c)(1), (3).
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    19. The Commission's regulations require the ERO to file with the

[[Page 64774]]

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.\23\
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    \23\ 18 CFR 39.5(a).
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    20. 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.\24\ 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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    \24\ 18 CFR 39.5(e).
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C. The Electric Reliability Organization

    21. NERC is a New Jersey nonprofit corporation with a membership 
comprised of the eight regional reliability councils covering the 
contiguous 48 States, several provinces in Canada and a portion of Baja 
California Norte, Mexico. NERC has operated as a voluntary, industry-
sponsored reliability organization formed to ensure the reliability of 
the North American Bulk-Power System.
    22. NERC filed an application with the Commission on April, 4, 2006 
seeking certification as the ERO. NERC stated that it expects NERC 
Council and NERC Corp. to merge upon being certified as the ERO by the 
Commission. NERC Corp. will be the surviving entity and will assume the 
assets and liabilities of NERC Council.
    23. In its July 20, 2006 order certifying NERC as the ERO, the 
Commission directed NERC to submit a compliance filing incorporating 
various clarifications and revisions to its bylaws and rules of 
procedure. Among the improvements the Commission has directed NERC to 
undertake as the ERO are changes to expedite the existing process for 
developing new Reliability Standards in response to a Commission 
deadline to deal with an urgent situation. The order also directs NERC 
to modify its proposed pro forma delegation agreement for delegating 
enforcement authority to a Regional Entity.\25\
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    \25\ Although the ERO Certification Order directs NERC to modify 
the pro forma delegation agreement, the pro forma agreement will not 
be re-filed with the Commission before negotiating the individual 
delegation agreements. The pro forma agreement will form the basis 
for the individual Regional Entity delegation agreements that will 
be filed with the Commission. ERO Certification Order, 116 FERC ] 
61,062 at P 518.
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D. NERC Petition for Approval of Reliability Standards

    24. 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 NOPR (NERC 
Petition).\26\ NERC states that 90 of these Reliability Standards, 
known as ``Version 0'' standards, became effective on a voluntary basis 
on April 1, 2005. It explains that the Version 0 standards ``are a 
translation, with certain improvements, of NERC's operating policies 
that were developed over several decades and its planning standards, 
which were approved in September 1997.'' \27\ In addition, the April 4, 
2006 filing includes 12 new Reliability Standards that were approved by 
the NERC board of trustees for implementation in February 2006. 
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 requests that the Reliability 
Standards become effective on January 1, 2007, or an alternative date 
determined by the Commission. NERC also states that it simultaneously 
filed the proposed Reliability Standards with governmental authorities 
in Canada.
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    \26\ The filed proposed Reliability Standards are not attached 
to this NOPR 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.

    \27\ See NERC Petition at 28.
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    25. Each proposed Reliability Standard follows a common format that 
includes five organizational elements:
a. Introduction
    1. Title: a phrase that describes the topic of the Reliability 
Standard.
    2. Number: A unique identification number that starts with three 
letters to identify the group followed by a dash and a three digit 
number, followed by a dash and the version number e.g., PRC-014-0.
    3. Purpose: One or more sentences that explicitly states the 
outcome to be achieved by the adoption of the Reliability Standard.
    4. Applicability:
    4.1 Each entity, as defined by the NERC Functional Model, that must 
comply with the Reliability Standard, such as Transmission Owner.
b. Requirements
    R1. A listing of explicitly stated technical, performance and 
preparedness requirements and who is responsible for achieving them.
c. Measures
    M1. A listing of the factors and the process NERC will use to 
assess performance and outcomes in order to determine non-compliance, 
and who is responsible for achieving the measures. Measures 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.'' \28\
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    \28\ NERC Comments at 104. NERC clarified its position that 
Measures did not include metrics after the Staff Preliminary 
Assessment interpreted the Measures section as including metrics.
---------------------------------------------------------------------------

d. Compliance
    1. Compliance Monitoring Process
    1.1 Compliance Monitoring Responsibility: NERC's explanation of who 
is responsible for assessing performance or outcomes.
    1.2 Compliance Monitoring Period and Reset Timeframe: The timeframe 
for each compliance monitoring period before it is reset for the next 
period.
    1.3 Data Retention: How long compliance documentation needs to 
remain on file.
    1.4 Additional Compliance Information: Any other information 
relating to compliance.
    2. Levels of Non-Compliance: Usually four levels of non-compliance 
are identified, with level 1 being used for the least severe non-
compliance and level 4 for the most severe non-compliance.
e. Regional Differences
    Identification of any regional differences that have been approved 
by the applicable NERC Committee (including Regions that are exempt).
    Version History: The chronological history of changes to the 
standard.
    26. In its April 4, 2006 petition, NERC requested ``unconditional'' 
approval of 77 proposed Reliability Standards and the glossary of 
terms. Further, NERC

[[Page 64775]]

requested ``conditional'' approval of 25 proposed Reliability 
Standards.
    27. In a June 26 filing, NERC revised its recommended action on the 
proposed Reliability Standards: (1) Unconditional approval of 51 
proposed Reliability Standards, to become enforceable in the U.S. on a 
date in 2007 to be determined by the Commission; (2) conditional 
approval of 26 proposed `fill-in-the-blank' Reliability Standards, to 
become enforceable in the U.S. on a date in 2007 to be determined by 
the Commission. NERC recommends that ``conditional approval'' shall 
mean ``that any limitation of the standard caused by the presence of a 
regional `fill-in-the-blank' requirement * * * would be considered as a 
factor in the evaluation of circumstances surrounding an alleged 
violation of the standard and the determination of a violation and 
setting of an appropriate penalty;'' and (3) conditional approval of 
another 25 proposed Reliability Standards lacking Measures or Levels of 
Non-Compliance, to become enforceable in the U.S. on a date in 2007 to 
be determined by the Commission. In addition, NERC plans to file 
modified Reliability Standards in early November 2006 that will add 
missing Measures and Levels of Non-compliance elements as well as risk 
factors. NERC recommends that the Commission act on the proposed 
modifications to Reliability Standards that are currently before the 
Commission in the same proceeding to achieve an initial set of 
Reliability Standards.
    28. On August 28, 2006, NERC submitted 27 new and revised 
standards. The Commission will address these proposed new and revised 
Reliability Standards in this rulemaking proceeding, except for eight 
proposed Reliability Standards 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.

E. Staff Preliminary Assessment

    29. 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 identified staff's 
preliminary 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 reviewed and identified issues regarding each individual Reliability 
Standard but did not make specific recommendations regarding the 
appropriate action on a particular proposal.
    30. The Staff Preliminary Assessment provided a basis for 
soliciting input regarding which of the proposed Reliability Standards 
should be approved, approved on an interim basis, or remanded to the 
ERO; established a platform from which to identify and prioritize 
potential problems with the proposed Reliability Standards; and 
provided a comprehensive and objective assessment of NERC's then-
current 102 Reliability Standards.
    31. Comments on the Staff Preliminary Assessment were due by June 
26, 2006. Entities that filed comments are listed in Appendix A to this 
NOPR. Approximately 50 persons filed comments in response to 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 and other related issues. 
The technical conference was transcribed, and is a part of the record 
in this docket.
    32. The written comments as well as the panel discussions at the 
technical conference have been very informative, and reference to the 
public comments is mentioned throughout the NOPR. Moreover, our 
proposed disposition of the Reliability Standards reflects our 
consideration of all comments that were submitted.

III. Discussion

A. The Commission's Reliability Standards Proposal

    33. The Commission's proposed reliability regulation is entitled 
Mandatory Reliability Standards for the Bulk-Power System. Section 
215(b) of the FPA obligates all users, owners and operators of the 
Bulk-Power System to comply with Reliability Standards that become 
effective pursuant to the processes set forth in the statute and in 
Part 39 of the Commission's regulations. The complete text of the 
proposed rule is provided in the Attachment to this notice of proposed 
rulemaking.
    34. The proposed regulation is organized into three sections:
    40.1--Applicability;
    40.2--Mandatory Reliability Standards; and
    40.3--Availability of Reliability Standards.
1. Applicability
    35. Section 40.1(a) of the proposed regulations provides 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 Sec.  215(b) of the FPA 
and section 39.2 of the Commission's regulations.
    36. Section 40.1(b) requires each Reliability Standard made 
effective under this Part to identify the subset of users, owners and 
operators to whom that particular Reliability Standard applies.
2. Mandatory Reliability Standards
    37. Section 40.2 (a) of the proposed regulations requires that each 
applicable user, owner or operator of the Bulk-Power System comply with 
Commission-approved Reliability Standards developed by the ERO, and 
provides 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.
    38. Section 40.2(b) of the proposed regulations provides that a 
proposed modification to a Reliability Standard proposed to become 
effective pursuant to Sec.  39.5 shall not be effective until approved 
by the Commission.
3. Availability of Reliability Standards
    39. Section 40.3 of the proposed regulations would require that the 
ERO maintain in electronic format that is accessible from the Internet 
the complete set of effective Reliability Standards that have been 
developed by the ERO and approved by the Commission. The Commission 
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 note that NERC currently maintains the existing, 
voluntary reliability standards on the NERC Web site.
    40. While the NOPR discusses each proposed Reliability Standard and 
identifies the Commission's proposed disposition for each Reliability 
Standard, neither the text nor the title of an approved Reliability 
Standard would be codified in the Commission's regulations. Rather, as 
indicated above, each applicable user, owner or operator of the Bulk-
Power System would be required to comply with Commission-approved 
Reliability Standards that are available in the Commission's Public 
Reference Room and on the Internet at the ERO's Web site.
    41. This approach would preserve the statutory options of approving 
a proposed Reliability Standard or modification to a Reliability 
Standard

[[Page 64776]]

``by rule or order.'' \29\ While we anticipate that the Commission 
would address through the rulemaking process most, if not all, new 
Reliability Standards proposed by NERC, certain modifications may be 
appropriately addressed by order.
---------------------------------------------------------------------------

    \29\ See 16 U.S.C. 824o(d)(2).
---------------------------------------------------------------------------

B. Applicability Issues

1. Definition of User of the Bulk-Power System
    42. In Order No. 672, the Commission acknowledged that, generally, 
a person directly connected to the Bulk-Power System selling, 
purchasing or transmitting electric energy over the Bulk-Power System 
is a ``User of the Bulk-Power System.'' However, the Commission 
declined to adopt a formal definition, explaining that, ``until we have 
proposed Reliability Standards before us, we will reserve further 
judgment on whether a definition of `User of the Bulk-Power System' is 
appropriate or whether the decision of who is a `User of the Bulk-Power 
System' should be made on a case-by-case basis.'' \30\
---------------------------------------------------------------------------

    \30\ Order No. 672 at P 99.
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    43. We do not propose a generic definition of the term ``User of 
the Bulk-Power System.'' Rather, the Commission will determine 
applicability on a standard-by-standard basis.\31\ The phrase ``user, 
owner or operator of the Bulk-Power System'' as used in section 215(b) 
of the FPA indicates the scope of the Commission's authority with 
regard to compliance with Reliability Standards. The proposed 
regulations would require that the ERO 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. In fact, this is NERC's current practice, and each of the 
107 proposed Reliability Standards submitted by NERC includes an 
``applicability'' provision that identifies the specific categories of 
applicable entities based on NERC's Functional Model.\32\ Parties 
concerned that a proposed Reliability Standard would apply more broadly 
than the statute allows may raise their concern in the context of the 
specific Reliability Standard. We believe that this approach provides 
sufficient notice regarding which entities are ``users of the Bulk-
Power System'' that must comply with a specific Reliability Standard.
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    \31\ Many of the proposed Reliability Standards apply to 
reliability coordinators and balancing authorities and other clearly 
appropriate entities. We believe that such Reliability Standards do 
not raise applicability issues. Thus, in our standard-by-standard 
analysis, the Commission's silence as to applicability issues means 
that it agrees with the ERO's proposed applicability of a 
Reliability Standard.
    \32\ See NERC Petition at 80-81. For information regarding the 
Functional Model, see NERC Reliability Functional Model, Function 
Definitions and Responsibility Entities, Version 2, February 10, 
2004. NERC is currently developing revisions to the Functional Model 
(referred to as ``Version 3'') that, among other things, changes the 
name of the reliability authority to ``reliability coordinator'' and 
explains its role in ``wide area'' reliability oversight. Both 
versions of the Functional Model are available on NERC's Web site 
at: http://www.nerc.com/~filez/functionalmodel.html.

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2. Use of the NERC Functional Model
    44. As mentioned above, each Reliability Standard proposed by the 
ERO identifies entities to which the Reliability Standard applies based 
on the NERC Functional Model.\33\ The Staff Preliminary Assessment 
observed that the Functional Model omits the categories of ``users, 
owners and operators,'' and includes other categories of entities that 
are not users, owners or operators of the Bulk-Power System.\34\
---------------------------------------------------------------------------

    \33\ The functional categories include: (1) Reliability 
coordinator, (2) balancing authority, (3) planning authority, (4) 
transmission planner, (5) transmission operator, (6) transmission 
service provider, (7) transmission owner, (8) resource planner, (9) 
distribution provider, (10) generator owner, (11) generator 
operator, (12) load-serving entity, (13) purchasing-selling entity, 
(14) compliance monitor. ERO Certification Order, 116 FERC ] 61,062, 
at n.247.
    \34\ Staff Preliminary Assessment at 24.
---------------------------------------------------------------------------

    45. NERC states that, while the term ``users, owners and 
operators'' defines the statutory applicability of the Reliability 
Standards, the Functional Model adds descriptive detail to reliability 
functions so the applicability of each Reliability Standard can be 
clearly defined. NERC explains that ``every entity class described in 
the Reliability Functional Model performs functions that are essential 
to the reliability of the bulk power system.'' \35\ Several commenters 
concur with NERC and suggest that the Commission approve the Functional 
Model so that future modifications would require Commission approval. 
MISO and Allegheny point to specific examples of what they consider 
ambiguities in the NERC Functional Model, primarily in the context of 
applicability to RTO or ISO functions.
---------------------------------------------------------------------------

    \35\ NERC Comments at 96. In addition to its April 4, 2006, 
Petition, NERC filed comments in response to the Staff Preliminary 
Assessment on June 26, 2006 (NERC Comments).
---------------------------------------------------------------------------

    46. The objective here is to make sure that each Reliability 
Standard is sufficiently clear with respect to applicability and 
specifically identifies each category of entities to which it applies. 
The NERC Functional Model represents a reasonable and practical 
approach to determining the applicability of a particular Reliability 
Standard. This approach is consistent with the ERO Certification Order, 
in which the Commission, in the context of addressing NERC's proposed 
compliance registry, found that ``NERC's functional approach provides 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.'' \36\ Thus, we agree with NERC that identifying 
specific functional categories of entities that comprise users, owners 
and operators of the Bulk-Power System provides a useful level of 
detail and appears to be more practical than simply identifying an 
applicable entity as a user, owner or operator. Accordingly, we propose 
to use the NERC functional model to identify the applicable entities to 
which each Reliability Standard applies.
---------------------------------------------------------------------------

    \36\ ERO Certification Order, 116 FERC ] 61,062, at P 689.
---------------------------------------------------------------------------

    47. We are mindful of the concerns of certain commenters that the 
Functional Model may contain ambiguities and add or omit certain 
entities or functions. Elsewhere in the NOPR we are proposing to 
require NERC to specifically address these concerns.\37\ Further we 
note that NERC's Rules of Procedure pertaining to the NERC compliance 
registry provide that NERC will notify an entity before it is formally 
registered and allow an opportunity for an entity to challenge its 
inclusion on the compliance registry.\38\ This process should resolve 
any specific disputes that may arise.
---------------------------------------------------------------------------

    \37\ For example, commenters' concerns regarding applicability 
to ISOs and RTOs are discussed in detail in the chapter on proposed 
communications Reliability Standards.
    \38\ See NERC Rule of Procedure section 501.1.3.
---------------------------------------------------------------------------

    48. Some commenters suggest that any future modification to the 
Functional Model could affect the categories of entities that must 
comply with a particular Reliability Standard, without the benefit of 
the open, stakeholder process required when the ERO develops a 
modification to a Reliability Standard. Because the Functional Model is 
so closely linked with applicability of the Reliability Standards, the 
Commission proposes to require the ERO to submit any future 
modifications to the Functional Model that may affect the applicability 
of the Reliability Standards for Commission approval.
3. Applicability to Small Entities
    49. NERC indicates that a Reliability Standard may identify 
limitations on

[[Page 64777]]

applicability based on electric facility characteristics ``such as 
generators with a nameplate rating of 20 MW or greater, or transmission 
facilities energized at 200 kV or greater.'' \39\ It explains that, 
``to ensure that the standards are applied in a cost effective manner 
and the applicability of the standards is focused on entities having a 
material impact on reliability of the bulk power system, it is 
necessary in the future to begin providing greater specificity in the 
applicability section of the standards.'' \40\ NERC, as the ERO, 
indicates that it plans to develop a set of guidelines on such 
limitations for the standard drafting teams and to require that a new 
Reliability Standard or a modification to an existing Reliability 
Standard, going forward, include this degree of specificity.
---------------------------------------------------------------------------

    \39\ NERC Petition at 9.
    \40\ Id. at 82.
---------------------------------------------------------------------------

    50. A number of commenters advocate that a mandatory Reliability 
Standard should not apply to entities that have no ``material impact'' 
on the Bulk-Power System.\41\ These commenters also ask that the 
Commission encourage and facilitate contractual arrangements for the 
delegation of compliance obligations faced by small entities to Joint 
Action Agencies (JAAs) and other organizations that have ongoing 
relationships with NERC.
---------------------------------------------------------------------------

    \41\ See, e.g., Alcoa, APPA, BPA and TAPS.
---------------------------------------------------------------------------

    51. While NERC has yet to submit a specific proposal, the 
Commission agrees 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, we do not 
believe that a ``blanket waiver'' approach that would exempt entities 
below a threshold level from compliance with all Reliability Standards 
would be appropriate because there may be instances where a small 
entity's compliance is critical to reliability. For instance, the 
reporting of a sabotage event required by CIP-001-0 may be important 
regardless of the size of the entity since such reporting helps others 
by putting them on notice of potential attacks to their own systems. 
For purposes of assessing compliance with a particular Reliability 
Standard, it may be appropriate to differentiate among certain subsets 
of users, owners, and operators. For example, the requirement to have 
adequate communications capabilities to address real-time emergency 
conditions (COM-001-0 and COM- 002-1) 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.\42\ Therefore, we propose to direct 
NERC to take such factors into account in determining applicability, as 
well as compliance requirements, for a particular Reliability Standard.
---------------------------------------------------------------------------

    \42\ For example, a dedicated phone line that would remain 
operative during a power failure may suffice for a small cooperative 
with minimal Bulk-Power System facilities, while a large investor-
owned utility may need a sophisticated communication system with 
redundancy and diverse routing requirements.
---------------------------------------------------------------------------

    52. In addition, the Commission solicits 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. If so, what if any process should the ERO or Regional 
Entity provide when making such a determination?
    53. NERC has proposed registration of joint action agencies or 
similar organizations that would register on behalf of their members. 
APPA asks that NERC permit a joint action agency or similar 
organization to accept compliance responsibilities on a standard-by-
standard basis. We propose to direct NERC to develop procedures which 
permit a joint action agency or similar organization to accept 
compliance responsibility on behalf of their members.
4. Regional Reliability Organizations
    54. NERC has proposed 28 Reliability Standards that would apply, in 
whole or in part, to a regional reliability organization.\43\ Many of 
the 28 Reliability Standards concern such matters as data gathering, 
data base maintenance, preparation of assessments and other ``process'' 
related responsibilities. Others are what have been referred to as 
``fill-in-the-blank'' Reliability Standards. Many of the proposed 
Reliability Standards that have compliance measures refer to the 
regional reliability organization as a compliance monitor.
---------------------------------------------------------------------------

    \43\ NERC states that the regional reliability organizations are 
the same as the existing eight regional reliability councils and 
that ``a regional reliability organization may or may not be the 
same organization that is providing statutory functions delegated by 
agreement with a regional entity.'' NERC Comments at 101. In the 
order certifying NERC as the ERO, the Commission asked that NERC 
provide additional information regarding the possible ongoing role 
of the regional reliability organizations and their relationship 
with Regional Entities. ERO Certification Order, 116 FERC ] 61,062, 
at P 76.
---------------------------------------------------------------------------

    55. The Staff Preliminary Assessment expressed concern as to 
whether a Reliability Standard that applies to a regional reliability 
organization is enforceable pursuant to section 215(e) of the FPA, 
since it is not clear whether a regional reliability organization is a 
user, owner or operator of the Bulk-Power System. NERC contends that 
such Reliability Standards are enforceable, and identifies several 
legal theories to support its position. Specifically, NERC contends 
that such Reliability Standards are enforceable because: (1) Each 
regional reliability organization will voluntarily register as a member 
of NERC and thereby be bound to comply; \44\ (2) a regional reliability 
organization performs functions on behalf of its members that are 
users, owners and operators of the Bulk-Power System; and (3) NERC is 
in the process of updating its functional model to provide a functional 
description of a regional reliability organization that includes 
functions that NERC believes are consistent with a system operator. EEI 
and other commenters question whether a Reliability Standard can be 
enforced against a regional reliability organization.
---------------------------------------------------------------------------

    \44\ Pursuant to NERC's ERO application, a member ``accepts the 
responsibility to promote, support, and comply with the Bylaws, 
Rules of Procedure, and Reliability Standards * * *.''
---------------------------------------------------------------------------

    56. The Commission is not persuaded that a regional reliability 
organization's compliance with a Reliability Standard can be enforced 
as proposed by NERC. Section 215 of the FPA does not appear to 
recognize a regional reliability organization as a user, owner or 
operator of the Bulk-Power System. Moreover, NERC's arguments assume 
that each regional reliability organization will voluntarily join as a 
member of NERC and be legally bound as a member to comply. Further, 
NERC's claim that a regional reliability organization will perform 
functions on behalf of its members that are users, owners and operators 
of the Bulk-Power System does not establish a binding agency 
relationship that would create a legal basis for requiring regional 
reliability organization compliance with Reliability Standards. 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, we do 
not understand why, once the transition is complete, a regional 
reliability organization should play a role separate from a Regional 
Entity whose function and

[[Page 64778]]

responsibility is explicitly recognized by section 215 of the FPA. We 
seek 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.
    57. At present, 28 of the proposed Reliability Standards are 
written to apply solely or partially to regional reliability 
organizations.\45\ We do not believe it is necessary or useful to 
remand those Reliability Standards simply because they refer to the 
regional reliability organization. For the five standards that apply 
partially to regional reliability organizations, the Commission 
proposes action similar to other Reliability Standards that need 
improvement, i.e., to approve them and direct modification.\46\ For the 
other Reliability Standards, as an interim measure, we propose 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 \47\ related to data 
gathering, data maintenance, reliability assessments and other 
``process''-type functions.\48\ 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.
---------------------------------------------------------------------------

    \45\ BAL-002, EOP-004, EOP-007, FAC-003, IRO-001, MOD-001, MOD-
002, MOD-003, MOD-004, MOD-005, MOD-008, MOD-009, MOD-011, MOD-013, 
MOD-014, MOD-015, MOD-016, MOD-024, MOD-025, PRC-002, PRC-003, PRC-
006, PRC-012, PRC-013, PRC-014, PRC-020, TPL-005, and TPL-006.
    \46\ BAL-002, EOP-004, FAC-003, IRO-001, and MOD-016. Three of 
these (EOP-004, FAC-003 and MOD-016) are ``data-gathering'' or 
``process-type'' Reliability Standards.
    \47\ 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.
    \48\ 18 CFR 39.2(d).
---------------------------------------------------------------------------

    58. Further, the Commission proposes 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.
    59. Finally, for the remaining seven Reliability Standards (fill-
in-the-blank standards),\49\ we propose to request additional 
information on these proposed Reliability Standards pending receipt of 
additional information, as detailed below in the discussion on fill-in-
the-blank standards.
---------------------------------------------------------------------------

    \49\ MOD-001, MOD-002, MOD-003, MOD-004, MOD-005, MOD-008, and 
MOD-009.
---------------------------------------------------------------------------

5. Bulk-Power System v. Bulk Electric System
    60. As noted above, Commission-approved Reliability Standards are 
to provide for the Reliable Operation of the Bulk-Power System. 
Generally speaking, the Nation's Bulk-Power System has been described 
as consisting of ``generating units, transmission lines and 
substations, and system controls.'' \50\ The 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. Essentially, whereas transmission lines 
and other parts of the transmission system, including control 
facilities serve to transmit electricity in bulk form from the 
generation sources to concentrated areas of retail customers, the 
distribution system moves the electricity to where these retail 
customers consume it at a home or business.
---------------------------------------------------------------------------

    \50\ 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.
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    61. Section 215(b)(1) of the FPA provides that all users, owners 
and operators of the Bulk-Power System must comply with Commission-
approved Reliability Standards. For purposes of section 215, the 
statute defines ``Bulk-Power System'' to mean:

    (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\
---------------------------------------------------------------------------

    \51\ 16 U.S.C. 824o(a)(1).

    62. Notably, the statutory definition of Bulk-Power System does not 
establish voltage threshold limits on applicable transmission 
facilities or electric energy from generating facilities. It does, 
however explicitly exclude facilities used in the local distribution of 
electricity. The NERC glossary, in contrast, states that Reliability 
Standards apply to the ``bulk electric system,'' which is defined in 
---------------------------------------------------------------------------
terms of a voltage threshold, 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.\52\

    \52\ See NERC Petition, Exhibit A, NERC glossary at 2.
---------------------------------------------------------------------------

    63. While NERC's definition generally excludes transmission 
facilities operated below 100 kV, NERC allows each regional reliability 
organization to add specificity to this general obligation.
    64. The Staff Preliminary Assessment expressed concern that 
differences between the statutory definition of Bulk-Power System and 
NERC's definition of bulk electric system create a discrepancy that 
could result in reliability gaps.\53\ Staff also expressed concern that 
allowing a regional reliability organization to define what facilities 
are included in the bulk electric system could result in conflicting 
definitions--potentially subjecting or excluding similar facilities 
from compliance with the Reliability Standards.
---------------------------------------------------------------------------

    \53\ Staff Preliminary Assessment at 25-26. For example, the two 
230 kV cables that connect Mirant's Potomac River Plant and the 69 
kV transmission facilities that supply portions of Washington, DC 
were not included in the MAAC definition of bulk electric system. 
New York City's 138 kV system is not included in NPCC's definition 
of bulk electric system.
---------------------------------------------------------------------------

    65. NERC recommends that, for the initial approval of proposed 
Reliability Standards, the continued use of NERC's definition of Bulk 
Electric System is appropriate. In the longer term, NERC suggests that 
change may be appropriate but that any global change at this juncture 
will affect many Reliability Standards and is best achieved through the 
Reliability Standards development process. Some commenters emphasize 
that all facilities necessary for Bulk-Power System reliability must be 
covered by the Reliability Standards, and none should be omitted by a 
discretionary act of a regional reliability organization. Many 
commenters, however, state that these excluded transmission systems 
have not been the cause of any of the large blackouts and therefore 
should not be considered as part of the Bulk-Power System.\54\

[[Page 64779]]

Furthermore, some commenters, including those representing small 
transmission owners, prefer the continued use of the NERC definition 
and caution against simply replacing all references to bulk electric 
system with Bulk-Power System because (1) the latter term as defined in 
section 215 of the FPA is ambiguous and (2) it would likely lead to an 
unintended substantive change in various Reliability Standards.
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    \54\ Staff review of selected Form No. 1 reports filed with the 
Commission indicates that 25 percent or more of many public 
utilities' total transmission line miles operate below 100 kV. Yet 
such facilities may well be as much a part of an entity's portion of 
the nation's integrated transmission system component of the Bulk-
Power System as the transmission facilities operating at or above 
100 kV because these lower voltage facilities support the higher 
voltage facilities. Indeed, it is not unusual to see outages of 69 
kV transmission facilities limiting the higher voltage transmission 
facilities with which they are networked.
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    66. We believe that Congress intended that the definitions of Bulk-
Power System and Reliable Operation \55\ in section 215 of the FPA to 
further the objective of maintaining the reliability of the entire 
Bulk-Power System, including maintaining the reliability of all of the 
elements of the transmission component of the Bulk-Power System. We 
believe that the transmission elements excluded under NERC's bulk 
electric system approach, including transmission that serves critical 
load centers, are subject to the Commission's jurisdiction under 
section 215.
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    \55\ As mentioned earlier, ``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 sudden disturbance, including a 
Cybersecurity Incident, or unanticipated failure of system 
elements.'' See Order No. 672 at P 64. See also 18 CFR 39.1.
---------------------------------------------------------------------------

    67. The term Bulk-Power System as defined in section 215 of the FPA 
is one determinant of the Commission's jurisdiction for reliability 
purposes (the phrase ``user, owner or operator'' being another). While 
we do not believe that it is appropriate to categorically exclude any 
class of facilities from the definition of Bulk-Power System, we 
recognize that a particular Reliability Standard may appropriately only 
need to apply to a subset of facilities that comprise the Bulk-Power 
System. Thus, the Commission may approve a Reliability Standard that 
applies to the bulk electric system as defined by NERC without limiting 
the ability of the ERO to develop and propose standards applicable to 
the broader set of facilities encompassed by the statutory definition 
as may be necessary.
    68. The Commission believes that the ERO has suggested a sensible 
transition approach. The Commission proposes 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.\56\ However, we interpret the term ``bulk electric 
system'' to apply to 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. It 
would also include transmission to all significant local distribution 
systems (but not the distribution system itself), load centers, and 
transmission connecting generation that supplies electric energy to the 
system. If there is a question concerning which underlying transmission 
system limits or supplements the operation of the higher voltage 
transmission system, the Commission proposed that the ERO would provide 
the final determination on a case by case basis.
---------------------------------------------------------------------------

    \56\ We note that the regional definitions have not been 
submitted to us and we are not determining the appropriateness of 
any regional definition in this proceeding.
---------------------------------------------------------------------------

    69. 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. We propose that 
NERC eventually 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, and that NERC's revision is 
consistent with the statutory term Bulk-Power System.
    70. While the approach outlined above may result initially in a 
Reliability Standard applying to a set of Bulk-Power System facilities 
that is less than that of the full reach of the Commission's 
jurisdiction pursuant to section 215 of the FPA (the ``gap'' to which 
the Staff Preliminary Assessment referred), we agree with the 
commenters that a wholesale substitution of one term for another could 
lead to unintended substantive changes within certain Reliability 
Standards.
    71. The Commission solicits comment on this 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.

C. Mandatory Reliability Standards

1. Legal Standard for Approval of Reliability Standards
    72. Section 215(d)(2) of the FPA states that the Commission may 
approve a Reliability Standard if it determines that a Reliability 
Standard is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest. In Order No. 672, the 
Commission addressed issues regarding the application of the statutory 
standard in our review of a proposed Reliability Standard. The 
Commission identified a series of factors it would consider when 
assessing whether to approve or remand a Reliability Standard.\57\ 
Further, Order No. 672 stated that the Commission would, consistent 
with the statute, give ``due weight'' to the technical expertise of the 
ERO with respect to the content of a proposed Reliability Standard. 
However, due weight does not equate to a rebuttable presumption that a 
proposed Reliability Standard meets the statutory requirement of being 
just, reasonable, not unduly discriminatory or preferential, and in the 
public interest.\58\ Further, the Commission review of a proposed 
Reliability Standard would balance any conflict between a proposed 
Reliability Standard and competition on a case-by-case basis.\59\
---------------------------------------------------------------------------

    \57\ Order No. 672 at P 262, 321-37.
    \58\ Id. at P 345.
    \59\ Id. at P 378.
---------------------------------------------------------------------------

    73. NERC suggests that a proposed Reliability Standard that has 
been developed through its Reliability Standards development process, 
which has been certified by ANSI as being open, inclusive, balanced and 
fair, is assured to be ``just, reasonable, and not unduly 
discriminatory or preferential.'' \60\ NERC also proposes 10 
``benchmarks'' for evaluating a proposed Reliability Standard that, 
according to NERC, ``may be helpful'' to the Commission in determining 
whether a Reliability Standard is ``just, reasonable and not unduly 
discriminatory or preferential'' if due process provided by the ANSI 
process alone does not suffice.\61\ In addition, NERC suggests that the 
Commission should consider the benchmarks when determining whether a 
proposed Reliability Standard ``is in the public interest.''
---------------------------------------------------------------------------

    \60\ NERC Petition at 6-8.
    \61\ Id. at 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.
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    74. In Order No. 672, the Commission rejected the notion that it 
would

[[Page 64780]]

presume that a proposed Reliability Standard developed through an ANSI-
certified process automatically satisfies the statutory standard of 
review.\62\ 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.
---------------------------------------------------------------------------

    \62\ Order No. 672 at P 338.
---------------------------------------------------------------------------

    75. Likewise, with regard to NERC's benchmarks, we will not 
constrain ourselves by approving or remanding a proposed Reliability 
Standard based on whether it satisfies the benchmarks. In our order 
certifying NERC as the ERO, we determined that the benchmarks and other 
factors would be useful for the ERO in developing proposed Reliability 
Standards.\63\ The Commission did not suggest that it would rely on the 
benchmarks in its review of a proposed Reliability Standard. Rather, as 
discussed above, Order No. 672 identified factors that the Commission 
will consider when determining whether a proposed Reliability Standard 
satisfies the statutory requirements.\64\
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    \63\ ERO Certification Order, 116 FERC ] 61,062, at P 241.
    \64\ Order No. 672 at P 262, 321-37.
---------------------------------------------------------------------------

2. Commission Options When Acting on a Reliability Standard
    76. NERC recommends that the Commission ``conditionally approve'' 
certain proposed Reliability Standards that it believes satisfy the 
statutory requirement but require improvement.\65\ The concept of 
conditional approval of a Reliability Standard was discussed at length 
in the July 6, 2006 technical conference.\66\ Many commenters 
responding to the Staff Preliminary Assessment support some form of 
conditional approval, while others oppose the concept out of concern 
that conditional approval will further complicate the understanding of 
mandatory Reliability Standards and present a ``moving target'' because 
NERC has proposed a plan to modify numerous proposed Reliability 
Standards before the Commission would approve them in a final rule.
---------------------------------------------------------------------------

    \65\ See NERC Petition at 109; NERC Comments at 14-19.
    \66\ July 6, 2006 technical conference, Tr. at 14-47. According 
to NERC, conditional approval means that the Commission would 
approve the Reliability Standards as mandatory and enforceable. In 
enforcing conditional standards, NERC and the Regional Entities 
would factor into the determination of violations and the imposition 
of penalties that certain requirements may be regional ``fill-in-
the-blank'' requirements or may be missing compliance information.
---------------------------------------------------------------------------

    77. The Commission believes that conditional approval may be a 
useful procedural tool that it may want to use when reviewing a 
Reliability Standard proposed at some future date. However, after 
careful consideration, the Commission is not proposing to conditionally 
approve any of the 107 Reliability Standards currently before us. 
Rather, as reflected in our substantive analysis of each Reliability 
Standard, we will propose one of four actions:
    78. Approve: Approval is appropriate for a proposed Reliability 
Standard that the Commission determines to be ``just, reasonable, not 
unduly discriminatory or preferential, and in the public interest,'' 
and as to which the Commission has not identified any additional issues 
that the ERO needs to address at this time to improve the Reliability 
Standard. Mandatory compliance with the Reliability Standard would be 
required as of the effective date of the Final Rule. The Commission has 
approved NERC's plan to review each Reliability Standard within five 
years from the effective date of the standard or its latest revision.
    79. Approve as mandatory and enforceable; and direct modification 
pursuant to section 215(d)(5): The Commission 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.\67\
---------------------------------------------------------------------------

    \67\ See ERO Certification Order at P 233, where the Commission 
also noted that, if a Reliability Standard is inadequate or has 
unintended consequences, it may order the ERO to submit a 
modification pursuant to section 215(d)(5) of the FPA, 16 U.S.C. 
824o(d)(5), which provides that ``[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.''
---------------------------------------------------------------------------

    80. This option is appropriate for a large number of proposed 
Reliability Standards where the Commission has identified improvements 
which are necessary or appropriate, but where the proposed Reliability 
Standard nonetheless satisfies the statutory requirement that it be 
just, reasonable, not unduly discriminatory or preferential, and in the 
public interest. This approach also allows us to give due weight to the 
technical expertise of the ERO in approving a Reliability Standard, yet 
also provides a mechanism to have the Commission's concerns addressed. 
Thus, where appropriate, we propose to approve these Reliability 
Standards as mandatory and enforceable, and direct modifications 
pursuant to section 215(d)(5). For these Reliability Standards, we 
provide guidance with regard to how and why they need to be improved 
and may establish a deadline by which a modification must be 
resubmitted to the Commission.
    81. Request additional information: There are some Reliability 
Standards that do not contain sufficient information to enable us to 
propose a disposition. For those Reliability Standards, we will 
identify the information that we require, and propose not to approve or 
remand these Reliability Standards until all the relevant information 
is received. For example, many of the fill-in-the-blank Reliability 
Standards will not be approved or remanded until the Commission has 
received all the necessary information. We may set a deadline by which 
NERC must submit the necessary information.
    82. Remand: Remand is appropriate for a proposed Reliability 
Standard that does not satisfy the statutory criteria that it be 
``just, reasonable, not unduly discriminatory or preferential, and in 
the public interest.'' The Commission may choose to set a deadline for 
NERC to submit a modified Reliability Standard.\68\ In the interim, the 
remanded standard would not be mandatory and enforceable. The 
Commission will not hesitate to remand a Reliability Standard that it 
finds does not provide for an adequate level of reliability.\69\
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    \68\ See 18 CFR 39.5(g) (``[t]he Commission, when remanding a 
Reliability Standard * * * may order a deadline by which the [ERO] 
must submit a * * * modified Reliability Standard'').
    \69\ Order No. 672 at P 329.
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3. Prioritizing Modifications to Reliability Standards
    83. As discussed above, the Commission is proposing to approve 
certain Reliability Standards and, as a separate action, is proposing 
to direct the ERO to modify many of the same Reliability Standards 
pursuant to section 215(d)(5) of the FPA. The

[[Page 64781]]

Commission recognizes that it is not reasonable to expect the 
modification of such a substantial number of Reliability Standards in a 
short period of time. Rather, the ERO will have to set priorities 
regarding the order and timing for developing modified Reliability 
Standards and resubmitting them to the Commission.
    84. Many commenters recognize the need for NERC to identify 
priorities in terms of which Reliability Standards are most critical to 
reliability and should be revised immediately, and which are of lesser 
priority. A number of commenters, including WIRAB, suggest detailed 
plans on how to set such priorities, focusing primarily on identifying 
those Reliability Standards that are most critical to maintaining 
reliability and those that are closest to being ready for 
implementation. Commenters suggest a staggered schedule, some 
suggesting several years for completion.
    85. We propose that NERC first focus its resources on modifying 
those Reliability Standards that have the largest impact on near term 
Bulk-Power System reliability. Many of the proposed modifications that 
reflect Blackout Report recommendations fit this description and should 
be a high priority. The Commission has identified a group of 
Reliability Standards that it believes should be given the highest 
priority by the ERO based on the above guidance.\70\ However, this is 
not meant to be an exclusive or inflexible list and ERO and commenter 
input is welcome. We propose that NERC address the modifications we 
propose for these high priority Reliability Standards within 1 year of 
the effective date of the Final Rule.
---------------------------------------------------------------------------

    \70\ See Appendix D (High Priority List).
---------------------------------------------------------------------------

    86. In addition, we propose that NERC address certain Reliability 
Standards that are not necessarily identified above as ``high 
priority'' may be modified in a relatively short time frame where the 
proposed modifications are relatively minor or ``administrative'' in 
nature. We believe that the ERO may complete such modifications 
relatively quickly with little diversion of ERO resources. Such 
modifications may include a proposal to modify a Reliability Standard 
to: (1) Identify the ERO as the compliance monitor rather than the 
regional reliability organization; (2) include Measures and Levels of 
Non-compliance; or (3) require other relatively minor clarifications or 
modifications.
    87. While the Commission has identified some modifications to 
Reliability Standards that it believes would be appropriate for the ERO 
to resubmit as high priority items, we believe that it is important 
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 should take a staggered approach and complete all the 
proposed modifications either within two or three years from the 
effective date of the final rule.
    88. The Commission believes that this proposal strikes a reasonable 
balance between the need to timely implement identified improvements to 
the existing Reliability Standards that will further Bulk-Power System 
reliability and the need for the ERO to develop modifications with 
industry input using its open, stakeholder process. The Commission may 
use its authority, pursuant to Sec.  39.5(g) of the Commission's 
regulations, to set a deadline for the ERO to submit a modified 
Reliability Standard if the Commission is not satisfied with the time 
frame proposed by the ERO work plan.
    89. The Commission solicits comment on its prioritization proposal.
4. Trial Period
    90. A number of commenters favor a phase-in of Reliability 
Standards with a trial period, during which Reliability Standards would 
be mandatory, but no penalties would be assessed.\71\ Various 
commenters suggest that the trial period should last for a range of six 
months to five years.
---------------------------------------------------------------------------

    \71\ See, e.g., Alberta, APPA, ISO/RTO Council, PSEG, WIRAB and 
WECC.
---------------------------------------------------------------------------

    91. NERC, in its application for ERO certification, proposed a six 
month ``notice period'' during which NERC would determine ``financial'' 
penalties and provide notice of the penalties to violating entities, 
but would not collect any penalties. NERC stated that it would submit a 
report on the effectiveness of the revised Sanction Guidelines to the 
Commission by May 31, 2007. In the ERO Certification Order, the 
Commission rejected requests to lengthen NERC's proposed six-month 
``notice period'' because it ``appropriately balances the time needed 
for NERC to implement the Sanction Guidelines with the countervailing 
interest in activating the mandatory Compliance Enforcement program as 
rapidly as possible.'' \72\
---------------------------------------------------------------------------

    \72\ ERO Certification Order, 116 FERC ] 61,062, at P 462.
---------------------------------------------------------------------------

    92. The Commission, however, is increasingly concerned that a trial 
period that commences with the effective date of mandatory Reliability 
Standards may interfere with mandatory and enforceable Reliability 
Standards being in effect by next summer. Moreover, the proposed 
Reliability Standards have already been in effect for a substantial 
period of time on a voluntary basis. Thus, the Commission proposes to 
eliminate a formal trial period. Entities that have complied with 
NERC's standards on a voluntary basis should be familiar with the 
proposed mandatory Reliability Standards and what is required for 
compliance. Therefore, an extensive trial period is unnecessary for 
such entities.
    93. The Commission recognizes that there are entities that have not 
historically participated in the voluntary system (including some 
relatively small entities) that may not be familiar with the proposed 
mandatory Reliability Standards and what is required for compliance. 
For such entities, we propose that the ERO and Regional Entities use 
their enforcement 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.
5. International Coordination of Remands
    94. Canadian commenters, such as the FPT Group, Alberta, CEA and 
Ontario IESO, request that the Commission affirm that it will seek to 
coordinate with authorities in Canada prior to any exercise of 
conditional approval, remand or rejection of a proposed Reliability 
Standard; and that each existing NERC standard will retain its present 
applicability until such time as the Commission approves it as a 
mandatory Reliability Standard.
    95. The Commission has recognized the importance of international 
coordination in both Order No. 672 \73\ and the ERO Certification 
Order.\74\ In the latter order, the Commission directed NERC to revise 
its proposed coordination process to: (1) Identify the relevant 
regulatory bodies and their respective standards approval and remand 
processes that will be implicated in any remand of a proposed standard; 
and (2) specify actual steps to coordinate all of these processing 
requirements, including those that may be necessary to expedite 
processing a proposed Reliability Standard that must be remanded. The 
Commission believes

[[Page 64782]]

that NERC's development of a coordination process, together with 
existing means of communication and coordination such as the U.S.--
Canada Bilateral Electric Reliability Oversight Group, will provide the 
necessary mechanisms for international coordination.
---------------------------------------------------------------------------

    \73\ See Order No. 672 at P 400.
    \74\ ERO Certification Order, 116 FERC ] 61,062, at P 286.
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D. Common Issues Pertaining to Reliability Standards

    96. As explained in the Staff Preliminary Assessment,\75\ certain 
issues are common to a number of proposed Reliability Standards. 
Immediately below, we discuss these common issues, followed by a 
discussion and determination of each individual proposed Reliability 
Standard.
---------------------------------------------------------------------------

    \75\ See Staff Preliminary Assessment at 17-26.
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1. Blackout Report Recommendations
    97. As explained in the Staff Preliminary Assessment, the Blackout 
Report identified a number of factors common to eight major blackouts 
experienced in North America since 1965 and made 46 specific 
recommendations to improve reliability based on the lessons learned 
from the August 2003 blackout and previous blackouts. These included 
specific recommendations to modify certain existing Reliability 
Standards. While recognizing the progress NERC has made, the Staff 
Preliminary Assessment also expressed concern that the proposed 
Reliability Standards continue to reflect several of the deficiencies 
identified by the Blackout Report.
    98. In its comments, NERC emphasizes that implementation of the 
Blackout Report recommendations has been its top priority since August 
2003 and describes the progress it has made in addressing specific 
recommendations and the status of ongoing work. It states that some of 
the hardest work on issues such as relay loadability and reactive power 
require extensive investigation before standards can be drafted. Other 
commenters suggest that the Blackout Report recommendations provide 
useful direction for areas where the Reliability Standards require 
modification and for setting priorities when determining which 
Reliability Standards to modify first. A few commenters ``downplayed'' 
the significance of the Blackout Report, noting that there is no 
statutory basis to accept all the Task Force's recommendations as 
absolute, infallible requirements and that not all recommendations 
translate into Reliability Standards.
    99. The Commission believes that the Blackout Report 
recommendations address key issues for assuring Bulk-Power System 
reliability. The Blackout Report recommendations were developed by and 
have received international support from both industry and regulators 
in the United States and Canada and we believe they represent a well-
reasoned and sound basis for action. Further, the Blackout Report 
recommendations address issues that caused or contributed to not only 
the August 2003 blackout, but multiple blackouts over the past 20 
years.\76\ Thus, in the discussion of a particular proposed Reliability 
Standard, we often will recognize the merit of a specific Blackout 
Report recommendation and reaffirm the reasoning behind such 
recommendation in proposing to approve with a directive to modify a 
specific Reliability Standard. Further, we believe that a modification 
to a proposed Reliability Standard that was recommended in the Blackout 
Report should receive the highest priority in terms of NERC's workplan 
to address identified deficiencies.
---------------------------------------------------------------------------

    \76\ Blackout Report at Chapter 10.
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    100. The Commission believes that prudent policy for Bulk-Power 
System reliability is to have Reliability Standards that are proactive. 
Such Reliability Standards would require actions be taken to prevent a 
blackout or outage and not simply address the undesirable outcomes. 
Therefore, it must first and foremost address the critical steps or 
actions that determine the achievement of the outcome. This proactive 
approach is necessary to ensure that the responsible entity is aware of 
and performs all of the necessary steps to achieve the ultimate 
reliability goal, rather than reacting to the implications of not 
achieving the outcome.
    101. Our concern is illustrated by an analogy provided by NERC in 
regard to commercial airline maintenance.\77\ A purely outcome-based 
standard on maintenance would require zero plane crashes due to failure 
of airplane components. But the public interest would not be well 
served if this were the only standard because the consequences of 
failing to meet the standard are immediate and unacceptable and 
provides no guidance on how to achieve the goal. The public interest 
dictates that there should be standards on maintenance procedures, 
frequency of testing and qualifications of personnel conducting the 
maintenance--not just a requirement that there be no accidents. This 
same concept applies to mandatory Reliability Standards pertaining to 
the Bulk-Power System.
---------------------------------------------------------------------------

    \77\ NERC Comments at 40.
---------------------------------------------------------------------------

    102. Accordingly, the Commission expects the ERO to include 
proactive Requirements in the Reliability Standards in addition to 
Requirements that identify a specific outcome.
2. Measures and Levels of Non-Compliance
    103. As noted above, the uniform format that NERC employs for each 
of its proposed Reliability Standards reflects five organizational 
elements: Introduction, Requirements, Measures, Compliance, and 
Regional Differences. The Staff Preliminary Assessment stated that 26 
of the proposed Reliability Standards do not contain Measures \78\ or 
Levels of Non-Compliance,\79\ or both. The Staff Preliminary Assessment 
emphasized that Reliability Standards would be less subject to variable 
implementation if they included the use of performance metrics, where 
applicable. The Staff Preliminary Assessment assumed that metrics used 
to determine non-compliance would be included in the Measures similar 
to BAL-001. NERC subsequently clarified that such metrics are not 
intended to be part of the Measure, but rather in the Requirements.\80\
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    \78\ 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 at 104.
    \79\ ``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.
    \80\ See NERC Comments at 105 (``Metrics of satisfactory 
performance are defined in the requirements. * * *'').
---------------------------------------------------------------------------

    104. NERC, in its Petition, identified 21 Reliability Standards 
that lack Measures or Levels of Non-Compliance and indicated that it 
plans to file modified Reliability Standards that include the missing 
Measures and Levels of Non-Compliance in November 2006. Further, NERC 
contends that a Reliability Standard lacking Measures or Levels of Non-
Compliance is still enforceable because the Measures should be viewed 
as the process to determine non-compliance during audits and 
investigations. According to NERC, the ``Requirements'' within a 
Reliability Standard define what an entity must do to be compliant and 
establish an enforceable obligation, and the presence or absence of 
Measures or Levels of Non-Compliance should not be the sole determining 
factor as to whether a Reliability Standard meets the statutory test 
for approval. Several

[[Page 64783]]

commenters take the opposite view, contending that Measures and Levels 
of Non-Compliance are necessary to ensure that a Reliability Standard 
is sufficiently clear to be fairly enforced.\81\
---------------------------------------------------------------------------

    \81\ See, e.g., National Grid and BPA.
---------------------------------------------------------------------------

    105. We agree that it is important to have Measures and Levels of 
Non-Compliance specified for each Reliability Standard, and recognize 
that NERC has plans to provide many of these elements in a November 
2006 filing. However, the absence of these two elements, which describe 
approaches that will be used to assess non-compliance, including the 
severity of a violation for penalty setting-purposes, is not critical 
to our determination of whether to approve a proposed Reliability 
Standard. 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.'' \82\ If properly drafted, a Reliability Standard may be enforced 
in the absence of specified Measures or Levels of Non-Compliance.
---------------------------------------------------------------------------

    \82\ NERC Comments at 104. See also NERC Petition at 83.
---------------------------------------------------------------------------

    106. 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 under 
the specific facts and circumstances of its use, ownership or operation 
of the Bulk-Power System. Therefore, we propose to approve a 
Reliability Standard that lacks 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 will 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 propose to approve the Reliability 
Standard and concurrently direct NERC to modify the Reliability 
Standard accordingly.
    107. The common format of NERC's proposed Reliability Standards 
calls for a ``data retention'' metric, generally in the ``Compliance'' 
section of the Reliability Standard. Yet, some proposed Reliability 
Standards do not contain a data retention requirement or state 
positively that no record retention period applies. The Commission 
seeks comment on whether the retention time periods specified in 
various Standards proposed by NERC are sufficient to foster effective 
enforcement.\83\ The Commission also seeks comment on what, if any, 
additional records retention requirements should be established for the 
proposed Reliability Standards.
---------------------------------------------------------------------------

    \83\ Notably, the Commission elsewhere imposes records retention 
requirements to facilitate effective enforcement. For example, in 
Order No. 677, FERC Stats. & Regs. 31,218 (2006), the Commission 
amended 18 CFR parts 35 and 284 by extending certain sellers' record 
retention requirement from three to five years so as to bring the 
record retention requirement in line with the five year limitations 
period applicable where the Commission might seek to impose civil 
penalties for violations of the anti-manipulation rule, 18 CFR part 
1c. In the reliability context, the civil penalty statute of 
limitations period for both the Commission and ERO and Regional 
Entities will also be five years. See Order No. 672 at P 487.
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3. Ambiguities and Potential Multiple Interpretations
    108. The Staff Preliminary Assessment indicated that ``various 
elements of numerous standards appear to be subject to multiple 
interpretations, especially with regard to the lack of specificity in 
the standards' requirements, measurability, and degrees of 
compliance.'' \84\ NERC agrees that there are many areas in which the 
Reliability Standards can be further improved and states that it is 
committed to review each Reliability Standard in the next few years, 
based on priorities coordinated with the Commission and applicable 
authorities in Canada.\85\ NERC adds that, while there are 
opportunities for improvement, the existing Reliability Standards 
contain the degree of clarity and specificity required to meet the 
statutory test for approval.
---------------------------------------------------------------------------

    \84\ Staff Preliminary Assessment at 18-19.
    \85\ NERC Petition at 90-91; NERC Comments at 101-02.
---------------------------------------------------------------------------

    109. Many commenters agree generally that ambiguities must be 
removed and mandatory Reliability Standards must be sufficiently clear 
with regard to who is responsible and what an entity must do to achieve 
compliance.\86\ Some commenters insist that a Reliability Standard 
should not go into effect until this is achieved. WECC and LPPC 
recommend that the Commission require NERC to institute a quality 
assurance program to ensure that Reliability Standards are clear, 
concise, and non-redundant.
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    \86\ See, e.g., LPPC, MISO, NEMA, SDG&E and WECC.
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    110. Our review of the Reliability Standards has confirmed staff's 
concern regarding the degree of ambiguity contained in certain Measures 
and Levels of Non-compliance portions of the proposed Reliability 
Standards. We are pleased that the ERO intends to review each 
Reliability Standard to identify and address ambiguous Measures and 
Levels of Non-Compliance language. While this is important, it is 
essential that the Requirements for each Reliability Standard, in 
particular, are sufficiently clear and not subject to multiple 
interpretations. Where the Requirements portion of a Reliability 
Standard is sufficiently clear (and no other issues have been 
identified), we propose to approve the Reliability Standard.
    111. 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, we propose to adopt that interpretation 
in the NOPR. For purposes of enforcement, the Commission proposes to 
implement any approved Reliability Standard consistent with our 
interpretation of any ambiguity as explained in the final rule. In some 
cases, we propose to direct NERC to supplement the language pursuant to 
section 215(d)(5) of the FPA.
    112. In summary, the Commission believes that a proposed 
Reliability Standard that has Requirements that are so ambiguous as to 
not be enforceable should be remanded. A Reliability Standard that has 
sufficiently clear Requirements, Measures, and Compliance language and 
is otherwise just and reasonable should be approved. A proposed 
Reliability Standard that has sufficiently clear and enforceable 
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 
Compliance language.
4. Technical Adequacy
    113. The Staff Preliminary Assessment stated that the Requirements 
specified in certain Reliability Standards may not be sufficient to 
ensure an adequate level of reliability.\87\ Staff explained that, 
while Order No. 672 noted that the ``best practice'' may be an 
inappropriately high standard, it also warned that a ``lowest common 
denominator'' approach is unacceptable if it is insufficient to ensure 
system reliability.
---------------------------------------------------------------------------

    \87\ Staff Preliminary Assessment at 19.
---------------------------------------------------------------------------

    114. NERC, EEI and others state that NERC's proposed Reliability 
Standards are technically sound and that compliance with them will 
assure reliability. NERC contends that each proposed Reliability 
Standard meets the statutory test of providing an adequate

[[Page 64784]]

level of reliability for the Bulk-Power System. Others share staff's 
concern that Reliability Standards not represent the lowest common 
denominator.\88\ One commenter suggested that there is a tendency for a 
standard drafting team to adopt a lowest common denominator approach to 
achieve a consensus on a standard.
---------------------------------------------------------------------------

    \88\ See, e.g., NPCC, SDG&E and NYSRC.
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    115. 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. While we are required under 
the statute to accord due weight to the technical expertise of the ERO, 
we are still required to independently assess the technical adequacy of 
any proposed Reliability Standard. 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.
5. Fill-in-the-Blank Standards
    116. Certain Reliability Standards developed by NERC require the 
regional reliability organizations to develop criteria for use by 
users, owners, or operators within the region. NERC refers to these as 
``fill-in-the-blank standards.'' \89\ NERC originally proposed 39 fill-
in-the-blank standards, which it said fell into three categories. The 
first 14 were Reliability Standards that require a regional reliability 
organization to set regional criteria or develop a regional 
procedure.\90\ The second group contained 10 Reliability Standards that 
require the regional reliability organization to develop such criteria 
or procedures, and also require entities within the region to follow 
those procedures or criteria.\91\ The third category consisted of 15 
Reliability Standards that require users, owners, and operators to 
follow criteria or procedures developed by the regional reliability 
organization, but did not (in the same Reliability Standard) require 
the development of such criteria or procedures.\92\ NERC indicated that 
the first category did not pose a problem because they were enforceable 
as written. The issue with the remaining 25 Reliability Standards was 
whether they could be enforced given that the regional criteria and 
procedures were not developed through an ERO-approved process and were 
not submitted to the Commission for approval. NERC acknowledged that 
the 25 fill-in-the blank Reliability Standards in categories two and 
three required further evaluation and proposed providing a work plan to 
the Commission by November 8, 2006 with a timetable for modifying, 
replacing, or withdrawing these standards.\93\
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    \89\ See NERC Petition at 87-90.
    \90\ EOP-007, IRO-001, MOD-003, MOD-011, MOD-013, MOD-014, MOD-
015, MOD-016, PRC-002, PRC-003, PRC-006, PRC-012, PRC-013, and PRC-
014.
    \91\ BAL-002, EOP-004, MOD-001, MOD-002, MOD-004, MOD-005, MOD-
008, MOD-009, MOD-024, and MOD-025.
    \92\ EOP-009, FAC-001, FAC-002, FAC-004, MOD-010, MOD-012, MOD-
017, MOD-019, PER-002, PRC-004, PRC-007, PRC-008, PRC-009, PRC-015, 
and PRC-016.
    \93\ NERC Petition at 89.
---------------------------------------------------------------------------

    117. The Staff Preliminary Assessment recognized that the fill-in-
the-blank standards raise two principal concerns: (i) Some are not 
enforceable against users, owners, and operators of the Bulk-Power 
System, but rather only provide broad direction to regional reliability 
organizations, and (ii) the specific implementing standards adopted by 
the regional reliability organizations have not undergone an approval 
process under section 215 and, thus cannot be enforced by the 
Commission or the ERO.
    118. In its June 26, 2006 comments to the Staff Preliminary 
Assessment, NERC amended its approach to the fill-in-the-blank 
standards. It recommends unconditional approval of the ``category one'' 
Reliability Standards, which place a requirement on a regional 
reliability organization to set criteria or procedures for reliability 
in the region, claiming that they are really not fill-in-the-blank 
standards. NERC then proposes to divide the remaining fill-in-the-blank 
standards into two new groups, the first group consisting of 26 
Reliability Standards.\94\ The remaining group consists of three fill-
in-the-blank standards that also are missing measures or compliance 
elements.\95\ NERC recommends conditional approval of these 29 
remaining fill-in-the-blank standards.
---------------------------------------------------------------------------

    \94\ This group includes 24 of the 25 standards originally 
included in categories two and three, plus two additional standards 
not originally designated as fill-in-the-blank standards: BAL-002-0, 
EOP-009-0, FAC-001-0, FAC-002-0, FAC-004-0, MOD-001-0, MOD-002-0, 
MOD-004-0, MOD-005-0, MOD-008-0, MOD-009-0, MOD-010-0, MOD-012-0, 
MOD-017-0, MOD-019-9, MOD-024-1, MOD-025-1, PER-002-0, PRC-004-1, 
PRC-007-0, RPC-008-0, PRC-009-0, PRC-015-0, PRC-016-0, TPL-002-0,* 
and TPL-004-0.* (* Newly identified as fill-in-the-blank standards.)
    \95\ EOP-004-0, EOP-006-0,* and IRO-005-1.* (* Newly identified 
as fill-in-the-blank standards.) NERC proposes that these 3 
standards, along with 23 others that are missing measures or 
compliance elements be conditionally approved with the understanding 
that the missing measures and compliance information will be filed 
in November 2006, after completion of stakeholder balloting in 
September and NERC board voting on November 1, 2006.
---------------------------------------------------------------------------

    119. Some commenters raised concerns that the fill-in-the-blank 
standards undermine uniformity, and may exacerbate differences or seams 
between the various ISO and RTO control areas. Several commenters 
support limited use of fill-in-the-blank standards, noting that they 
provide flexibility, which may facilitate development of a Reliability 
Standard in instances where a continent-wide approach may not work.
    120. NERC represents that it will submit an action plan and 
schedule in November 2006 for completing the fill-in-the-blank 
standards. NERC expects that it will take approximately three years to 
complete the process, and will be prioritizing Reliability Standards 
that require the most immediate revision.\96\ NERC anticipates three 
potential approaches to the fill-in-the-blank standards: (1) If NERC 
determines that there is insufficient justification for a regional 
difference, it may replace a Reliability Standard with a uniform 
continent-wide Reliability Standard; (2) where a regional difference is 
justified, NERC proposes to direct the regions to develop their 
regional criteria as a Reliability Standard to be filed for approval 
with the ERO and thereafter with the Commission and applicable 
authorities in Canada; (3) if mandatory enforcement of a fill-in-the-
blank standard is not necessary for reliability, NERC proposes to 
retire the Reliability Standard and allow a region to maintain 
voluntary criteria and procedures as needed.
---------------------------------------------------------------------------

    \96\ NERC Comments at 107.
---------------------------------------------------------------------------

    121. We share commenters' concerns regarding the potential for the 
fill-in-the-blank standards to undermine uniformity. Order No. 672 
stated that, while uniformity is the goal with respect to Reliability 
Standards, it may not be achievable overnight. Where NERC had directed 
the regions to develop a particular Reliability Standard, we noted that 
``[o]ver time, we would expect that the regional differences produced 
under this framework will decline and a set of best practices will 
develop.'' \97\ NERC's review states it will take uniformity concerns 
into consideration, only permitting regional differences where 
justified. In Order No. 672, we specified two instances where regional 
differences may be permitted: regional differences that are more 
stringent than the continent-wide Reliability Standard, including those 
addressing matters not

[[Page 64785]]

addressed by a continent-wide Reliability Standard, and regional 
differences necessitated by a physical difference in the Bulk-Power 
System.\98\ NERC's review must be consistent with these criteria.
---------------------------------------------------------------------------

    \97\ Order No. 672 at P 292.
    \98\ Id. at P 291. Our position was reiterated in the ERO 
Certification Order where we directed NERC to delete additional 
criteria contained in its Rules of Procedure and Reliability 
Standard development procedures. ERO Certification Order, 116 FERC ] 
61,062, at P 274.
---------------------------------------------------------------------------

    122. In addition, if after an appropriate review, NERC determines 
that regional differences are still warranted, we propose that any 
regional proposal to fill-in-the-blank must be developed in accordance 
with the NERC's ANSI-approved process, or through an alternative 
process approved by the ERO,\99\ and must be submitted to the ERO and 
the Commission for approval.
---------------------------------------------------------------------------

    \99\ NERC Rule of Procedure section 312.4 states that regional 
Reliability Standards ``may be developed through the NERC 
reliability standards development procedure, or alternatively, 
through a regional reliability standards development procedure that 
has been approved by NERC.''
---------------------------------------------------------------------------

    123. We propose to require supplemental information regarding any 
Reliability Standard that requires a regional reliability organization 
to fill in missing criteria or procedures. 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. Therefore, we 
propose to not approve or remand those Reliability Standards until all 
the necessary information has been provided.

E. Discussion of Each Individual Reliability Standard

    124. We have reviewed each of the proposed Reliability Standards, 
and our analysis is by chapter according to the categories of 
Reliability Standards defined in NERC's petition. Each chapter begins 
with an introduction to the category, followed by a discussion of each 
proposed Reliability Standard. The discussion includes summaries of 
NERC's proposal, the Staff Preliminary Assessment, and comments 
received, as well as a Commission proposal. The Commission proposal for 
each standard will include a proposed disposition. For Reliability 
Standards that are proposed to be approved with direction that NERC 
modify the Reliability Standard, specific instructions are provided 
regarding areas that need to be modified, and how they should be 
modified. Where additional information is needed in order for the 
Commission to propose a disposition, the information required will be 
detailed.
1. BAL: Resource and Demand Balancing
a. Overview of Category
    125. The six Balancing (BAL) Reliability Standards address 
balancing resources and demand to maintain interconnection frequency 
within prescribed limits.
i. General Comments
    126. LPPC comments generally that each Requirement contained in a 
Reliability Standard must be measurable to be mandatory. In this 
regard, LPPC identifies examples of Requirements in the BAL Standards 
that it claims are not measurable requirements but, rather, descriptive 
or explanatory statements. LPPC also identifies several Requirements in 
the BAL Standards that it claims are redundant to other Requirements in 
the BAL Standards.
    127. CenterPoint comments that significant regional variation ``is 
necessary in matters such as amount and composition of spinning reserve 
and calculation of the Frequency Bias component of ACE due to the 
different operating characteristics of the regions.'' \100\ CenterPoint 
suggests that customers' concerns are focused on ensuring that a 
Reliability Standard's performance requirements are met as opposed to 
concerns about specifically how these requirements are met. CenterPoint 
indicates that regional variation in the method to comply with the 
Reliability Standard is acceptable so long as the Reliability 
Standard's required level of performance is ultimately achieved. 
CenterPoint suggests that certain process-oriented Reliability 
Standards in this group should be eliminated because other BAL 
Reliability Standards already include metrics necessary to determine 
compliance.
---------------------------------------------------------------------------

    \100\ Center[fxsp0]Point Comments at 15.
---------------------------------------------------------------------------

ii. Commission Response
    128. With respect to LPPC's general comments, the Commission agrees 
that Reliability Standards must have clear and enforceable 
Requirements. LPPC correctly identifies a number of instances in the 
BAL Reliability Standards where a Requirement appears to entirely 
consist of, or contain, an explanatory statement rather than an 
actionable Requirement. While the Commission agrees with LPPC that 
explanatory statements should not be in the Requirements section of a 
Reliability Standard, the presence of an explanatory statement does not 
render the Reliability Standard unenforceable. The Commission has 
addressed the redundant Requirements identified by LPPC within the 
applicable Reliability Standards below.
    129. With respect to CenterPoint's comment, the Commission believes 
there are certain processes, such as the methods for calculating 
frequency bias, which are accepted industry practices and should be 
included as uniform requirements in the Reliability Standards. The 
Commission proposes to formalize the process across the regions. This 
will protect reliability by providing a common basis for analysis and 
corrective actions. CenterPoint also comments that ``some of the 
process-oriented standards should be eliminated,'' but because 
CenterPoint provided no further detail on this point, the Commission is 
unable to fully consider and respond to the comment.
b. Real Power Balancing Control Performance (BAL-001-0)
i. NERC Proposal
    130. 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. BAL-001-0 
establishes two requirements that are used to assess the proficiency of 
a balancing authority to maintain interconnection frequency by 
balancing real power (MW) demand, interchange, and supply. The proposed 
Reliability Standard would apply to balancing authorities.
ii. Staff Preliminary Assessment
    131. Staff commented that BAL-001-0 provides a good example of 
performance metrics useful for assessing the performance of Balancing 
Authorities and compliance with the standard.
iii. Comments
    132. ReliabilityFirst agrees with staff's comments, and ISO/RTO 
Council recommends that the Commission accept this Reliability 
Standard.
    133. LPPC asserts that Requirements R1 and R2 are not actual 
Requirements but instead only determine whether the balancing authority 
has adequate regulating reserves, without specifying a performance 
metric.
iv. Commission Proposal
    134. The Commission disagrees with LPPC's comment that Requirements 
R1 and R2 are not actual Requirements. To the contrary, Requirements R1 
and R2 state the bounds within which a balancing authority must control 
its area

[[Page 64786]]

control error (ACE).\101\ For example, Requirement R2 requires each 
balancing authority to operate such that its average ACE for at least 
90 percent of the time is within a specific limit. These Requirements 
set forth an effective means for maintaining Interconnection steady-
state frequency errors that are consistent with historic 
Interconnection frequency performance, which is the stated goal of BAL-
001-0. These Requirements also have associated Measures and Levels of 
Non-Compliance.
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    \101\ NERC defines ACE as ``The instantaneous difference between 
a Balancing Authority's net actual and scheduled interchange, taking 
into account the effects of frequency Bias and correction for meter 
error.''
---------------------------------------------------------------------------

    135. BAL-001-0 provides for an important function necessary to 
maintain Bulk-Power System reliability. Further, the Commission agrees 
with NERC's proposed applicability of this standard to balancing 
authorities.
    136. For the reasons discussed above, the Commission believes that 
Reliability Standard BAL-001-0 is just, reasonable, not unduly 
discriminatory or preferential, and in the public interest; and 
proposes to approve it as mandatory and enforceable.
c. Regional Difference to BAL-001-0: ERCOT Control Performance Standard 
2
i. NERC Proposal
    137. NERC approved a regional difference for ERCOT from Requirement 
R2 in BAL-001-0, which requires that the average area control error or 
``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.\102\ This Requirement is referred to as Control 
Performance Standard 2 (CPS2). NERC explains that ERCOT requested a 
waiver of CPS2 because: (1) ERCOT, as single control area \103\ 
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 which it performed 
showing that under the new market structure, the ten control areas in 
its region were able to meet CPS2 standards while the aggregate 
performance of the ten control areas was not in compliance.
---------------------------------------------------------------------------

    \102\ Each regional difference approved by NERC is provided as a 
separate ``waiver request'' document that identifies the entity 
requesting a waiver, the Reliability Standard or Requirements that 
are waived, and explanation and a statement of NERC approval. See 
NERC Petition, Exhibit A. In addition, each regional difference is 
identified in the Reliability Standard to which the waiver applies.
    \103\ 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.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    138. This regional difference was not addressed in the Staff 
Preliminary Assessment.
iii. Comments
    139. There were no comments regarding this regional difference.
iv. Commission Proposal
    140. Order No. 672 explains that ``uniformity of Reliability 
Standards should be the goal and the practice, the rule rather than the 
exception.'' \104\ 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.\105\ Regional differences must still be just, reasonable, not 
unduly discriminatory or preferential and in the public interest.\106\
---------------------------------------------------------------------------

    \104\ Order No. 672 at P 290.
    \105\ Id. at P 291.
    \106\ Id.
---------------------------------------------------------------------------

    141. ERCOT's Protocols concerning frequency control identify that 
the existing ERCOT approach to Interconnection frequency control is 
necessary to assure reliability in that interconnection.\107\ However, 
the existing waiver was filed prior to the formation of these 
procedures. ERCOT is both a single balancing authority and the smallest 
of the three Interconnections, approximately one tenth of the size of 
the Eastern Interconnection. As such, frequency control is more 
critical to its system reliability.\108\
---------------------------------------------------------------------------

    \107\ See ERCOT Protocols, section 5 (Dispatch) at 21-23 (May 1, 
2006), available at: http://www.ercot.com/mktrules/protocols/current.html
.

    \108\ The minimum frequency response as calculated by ERCOT for 
reliable operation is 420 MW/0.1 Hz, while the measured frequency 
response for the Eastern Interconnection is approximately 3,000 MW/
0.1 Hz. ERCOT has a requirement for a minimum frequency bias that is 
almost twice that of the Eastern Interconnection taken on the same 
total load basis.
---------------------------------------------------------------------------

    142. The Commission notes that the physical difference of ERCOT 
compared to the other two interconnections in terms of size is a 
sufficient reason for approving a regional difference. Also, ERCOT's 
approach of determining the minimum frequency response needed for 
reliability and requiring appropriate generators to have specific 
governor droop appears to be a more stringent practice than Requirement 
R2 in BAL-001-0. The calculation of the required frequency response 
will be discussed in BAL-002. However, neither reason is articulated in 
the proposed regional difference.
    143. The Commission proposes to approve the ERCOT regional 
difference. However, the Commission proposes to have the ERO submit a 
modification of the ERCOT regional difference to include the 
requirements concerning frequency response contained in the ERCOT 
Protocols, section 5.
d. Disturbance Control Performance (BAL-002-0)
i. NERC Proposal
    144. The reliability goal of this Reliability Standard is to 
utilize contingency reserves to balance resources and demand to return 
interconnection frequency to within defined limits following a 
reportable disturbance. BAL-002-0 establishes: (1) The generic 
requirements that each regional reliability organization should use to 
determine the amount and type of contingency reserves that will be 
needed to meet a metric called the Disturbance Control Standard (DCS); 
(2) how to calculate the DCS metric; (3) procedures to be used in 
calculating DCS for reserve sharing groups; (4) a 15 minute default 
disturbance recovery period; (5) a 90 minute default contingency 
reserve restoration period; and (6) the requirement that balancing 
authorities have access to contingency reserves to respond to loss of 
generation, but not loss of load. The proposed Reliability Standard 
would apply to balancing authorities, reserve sharing groups,\109\ and 
regional reliability organizations.
---------------------------------------------------------------------------

    \109\ 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 12.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    145. Requirement R3.1 requires that a balancing authority or 
reserve sharing group carry ``at least enough contingency reserves to 
cover the most severe single contingency.'' Staff noted that the 
Requirement could be subject to multiple interpretations, one limited 
to only the loss of generation, whereas the other considers the loss of 
supply resulting from a transmission or generation contingency.\110\ 
Further staff noted that specific requirements related to the 
composition of reserves and the restoration time are left to Regions 
and sub-Regions to determine. For example, Requirement R2 directs each 
regional reliability organization (or sub-regional

[[Page 64787]]

reliability organization or reserve sharing group) to specify its 
contingency reserve policies, including minimum reserve requirements 
and allocation and the permissible mix of reserves. Other provisions 
identified by staff as vague or missing include the definition as to 
which resources and demand side management are eligible to be counted 
as spinning reserves. Finally, staff stated that lower reporting 
thresholds for the size of the minimum disturbance, which may be 
required by certain regional reliability organizations, should be 
documented as a regional difference.
---------------------------------------------------------------------------

    \110\ Staff Preliminary Assessment at 30.
---------------------------------------------------------------------------

iii. Comments
    146. NERC states that, with regard to contingency reserves, the 
BAL-002-0 requirement that a balancing authority restore its resource-
demand balance with the rest of the Interconnection within 15 minutes 
is absolute, objective and measurable. To meet this requirement, the 
balancing authority must have available sufficient reserves to recover 
from the largest single contingency and deploy those reserves within 15 
minutes. It states that ``leaning on the system'' for up to 15 minutes 
is an appropriate use of the Interconnection. Thus, with regard to 
staff's comments that the Reliability Standard does not specify minimum 
reserve requirements and that the appropriate mix of reserves is not 
defined, NERC questions whether it is appropriate to measure the 
desired outcome (as BAL-002-0 does), or how that outcome is achieved 
(as staff suggests). NERC suggests that the existing approach is more 
appropriate because the ``how'' portion is driven by system design, 
resource mix and economics. Further, it adds that regional variation is 
appropriate in determining the amount of contingency reserves because 
it is driven by the specific system configuration and operating 
conditions; and adding greater specificity to the contingency reserve 
requirements to achieve uniformity will not enhance reliability but 
will likely increase costs of compliance. NERC states that it will 
review the potential reliability benefits and costs associated with 
more specific and uniform contingency reserve requirements.
    147. Many commenters agree with the Staff Preliminary Assessment 
that BAL-002-0 lacks specificity in certain areas. Most commenters also 
argue in favor of giving deference to regions or reserve sharing groups 
with regard to the requirements in Requirement R2 and certain other 
requirements of the standard. CPUC states that the corresponding WECC 
standards provide specificity in areas identified by staff and provide 
for a more stringent disturbance reporting threshold. It suggests that 
the Commission defer to and approve such regional standards already in 
place that correspond to NERC-proposed Reliability Standards, but add 
specificity and stringency without triggering a need for the regional 
reliability organization to provide extensive justification for a 
``regional difference.'' ISO/RTO Council states that ``the requirements 
to recover the loss of generation and returning Area Control Error to a 
specified value within a specific time period as stipulated in the 
standard provide the needed reliability performance yardstick.'' \111\ 
It continues, stating that once these performance-based requirements 
are in place, the regional reliability organization standards can 
provide the supplementary process requirements. MidAmerican advocates 
that the appropriate reserve sharing group should specify requirements 
for contingency reserves, while CenterPoint states that a significant 
amount of regional variation is necessary. ReliabilityFirst believes 
that NERC should provide a clear definition of spinning reserves for 
Interconnections.
---------------------------------------------------------------------------

    \111\ ISO-RTO Council Comments, Attachment A at 3.
---------------------------------------------------------------------------

    148. MidAmerican suggests that there should be specific 
requirements such as the percentage of reserves to load, the 
permissible mix of spinning reserves verses non-spinning generation to 
meet operating reserves, the maximum allowable interruptible load, and 
other pool rules. These requirements should be based on composite 
reliability studies such as a Loss-of-Load Expectation (LOLE) \112\ in 
the Interconnection. It also states that BAL-002-0 should contain a 
planning reserve requirement \113\ based on LOLE. MidAmerican suggests 
that BAL-002-0 should allow for differing regional reserve requirements 
due to differing generation mixes in each region.
---------------------------------------------------------------------------

    \112\ LOLE studies are probabilistic studies associated with 
determining the probability that there may not be sufficient 
generation to supply firm load.
    \113\ Contingency reserves are those reserves used during real 
time operation to accommodate uncertainties in generation failures. 
In contrast, planning reserves have a long-term perspective. While 
BAL-002-0 has a requirement pertaining to contingency reserve 
policy, the Reliability Standards are silent on planning reserve.
---------------------------------------------------------------------------

    149. ReliabilityFirst agrees with staff's assessment. It comments 
that the loss of supply is another contingency and suggests that the 
Reliability Standard should further define the criteria for 
contingencies and state the requirement for all types of contingencies 
to be assessed during recovery from a disturbance. ReliabilityFirst 
also agrees that lower thresholds should be defined as regional 
differences but any difference should be demonstrated as technically 
defensible and warranted. ReliabilityFirst agrees with the Staff 
Preliminary Assessment that the procedures developed by the individual 
regions to determine contingency reserves need to be merged to develop 
consistency.
    150. LPPC points out several Requirements it considers problematic. 
It states that Requirement R4.1 is not a requirement but rather a 
definition of some of the criteria for disturbance recovery. It further 
states that the statement in Requirement R4.1, is only true if the 
balancing authority is not utilizing a reserve sharing group to respond 
to the event, and the definition should be expanded to include reserve 
sharing groups. LPPC suggests that there is some redundancy between 
Requirements R4 and R5 and that they could be combined. Specifically, 
LPPC suggests that the first sentence of each Requirement is 
essentially stating the same thing. It also states the reference to the 
NERC Operating Committee should be removed from Requirements R4.2 and 
R6.2.
iv. Commission Proposal
    151. The Commission proposes to approve BAL-002-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard as discussed below.
    152. The issues identified by the commenters and staff can be 
grouped into three categories: (1) The measurement of the performance 
of the contingency reserves through Disturbance Control Standard; (2) 
the determination of the amount and makeup of contingency reserves; and 
(3) what contingencies are appropriate to consider.
(a) Disturbance Control Standard
    153. NERC contends that this standard is ``absolute, objective, and 
measurable'' in that it allows up to 15 minutes for the recovery from a 
disturbance.\114\ The Commission agrees with allowing up to 15 minutes 
for recovery from a disturbance. To achieve NERC's measurement 
approach, we propose that NERC modify Requirement R3.1, which currently 
requires that a balancing authority carry at least enough contingency 
reserve to cover ``the most severe single contingency,'' to include 
enough contingency reserve to cover any event or single contingency,

[[Page 64788]]

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.\115\ We believe that this approach would 
address staff's concern with Requirement R3.1 while giving due weight 
to the ERO's position. Further, NERC should consider 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. The Commission is aware that this approach is consistent 
with the Balancing Authority ACE Limit (BAAL) presently being field 
tested. The major difference between the proposal and the BAAL is that 
the proposal is aimed at preserving the historic frequency performance 
of the system.
---------------------------------------------------------------------------

    \114\ NERC Comments at 41.
    \115\ 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 should have adequate 
frequency response to ensure recovery immediately following an 
event.
---------------------------------------------------------------------------

    154. The Commission agrees with ReliabilityFirst that lower 
reporting thresholds for the size of the minimum disturbance should be 
defined as a regional difference. However, the above approach 
eliminates that concern because any event or single contingency that 
causes a frequency deviation above the defined threshold would be 
included in the DCS calculation.
(b) Determination of Amount and Makeup of Contingency Reserves
    155. The Commission notes that Requirement R2 of BAL-002-0 is a 
``fill-in-the-blank'' requirement, as it directs each regional 
reliability organization (or sub-regional reliability organization or 
reserve sharing group) to specify its contingency reserve policies, 
including minimum reserve requirements and allocation and the 
permissible mix of reserves. NERC and many other commenters state that 
the regional determination of contingency reserves is appropriate.
    156. While 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. The appropriate mix of operating reserves, 
spinning reserves and non-spinning reserves should be addressed on a 
consistent basis. As identified by the ERCOT and WECC whitepapers,\116\ 
due consideration should be given to the amount of frequency response 
from generation or load needed to assure reliability. We propose that 
this policy be neutral as to the source of the contingency reserves in 
terms of ownership or technology. Accordingly, the Commission proposes 
to require NERC to develop a continent-wide contingency reserve policy.
---------------------------------------------------------------------------

    \116\ See WECC Frequency Response Standard White Paper (2005), 
available at http://www.wecc.biz/documents/library/RITF/FRR_White_Paper_v12_1-27-06.pdf
; ERCOT Energy Market Technical Paper 1C, 

Defining, Measuring and Valuing Frequency Response (January 2004).
---------------------------------------------------------------------------

    157. As identified in the Staff Preliminary Assessment, the types 
of resources that can be used for contingency reserves should be 
consistent across the country and not have some regions allow the 
curtailment of irrigation pumps (one form of DSM) to be used as part of 
contingency reserves while other regions do not.\117\ Demand Side 
Management or Direct Control Load Management should be on the same 
basis as conventional generation or any other technology. Accordingly, 
the Commission proposes to direct NERC to modify BAL-002-0 to include a 
Requirement that explicitly allows demand side management as a resource 
for contingency reserves.
---------------------------------------------------------------------------

    \117\ See also Assessment of Demand Response and Advanced 
Metering: Staff Report (Aug. 2006) (Demand Response Report), 
available at http://www.ferc.gov/legal/ staff-reports/demand-

response.pdf.
---------------------------------------------------------------------------

    158. With regard to MidAmerican's suggestion that the BAL-002-0 
Reliability Standard should contain a planning reserve requirement 
based on LOLE, the Commission disagrees noting that BAL-002-0 deals 
with operating reserves and not planning reserves.
(c) Contingencies
    159. Staff's concern regarding transmission contingencies is 
resolved by the above approach in measuring response for frequency 
deviation.
    160. With regard to LPPC's concerns, the Commission disagrees with 
its suggestion that the applicability of Requirement R4.1 should be 
extended to reserve sharing groups, noting that reserve sharing groups 
typically do not calculate a combined ACE. With regard to LPPC's 
comment regarding the redundancy of R4 and R5 and the suggestion that 
these requirements be combined, we leave that to the discretion of the 
ERO.
    161. We agree with LPPC's suggestion to modify Requirements R4.2 
and 6.2 of BAL-002 to replace references to the NERC Operating 
Committee with the ERO.\118\
---------------------------------------------------------------------------

    \118\ LPPC raises the same concern regarding references to the 
NERC Operating Committee in other Reliability Standards. We agree 
that the term should be removed and replaced with the term ERO in 
all such places.
---------------------------------------------------------------------------

    162. While the Commission has identified concerns with regard to 
BAL-002-0, we believe that the proposal serves an important purpose in 
ensuring a balancing authority is able to utilize its contingency 
reserves to balance resources and demand and return interconnection 
frequency within defined limits following a reportable disturbance. 
Further, the proposed Requirements set forth in BAL-002-0 are 
sufficiently clear and objective to provide guidance for compliance.
    163. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard BAL-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 
proposes to direct that NERC submit, a modification to BAL-002-0 that: 
(1) Includes a Requirement that explicitly allows demand side 
management as a resource for contingency reserves; (2) develop a 
continent-wide contingency reserve policy; \119\ (3) includes a 
Requirement that measures response for any event or contingency that 
causes a frequency deviation; (4) substitutes ERO for regional 
reliability organization as the compliance monitor; \120\ and (5) 
change references to the NERC Operating Committee in Requirements R4.2 
and R6.2 to ERO.
---------------------------------------------------------------------------

    \119\ This could be accomplished by modifying Requirement R2 or 
developing a new Reliability Standard.
    \120\ The proposal to require that the ERO be identified as the 
compliance monitor (which may then choose to delegate compliance 
monitor responsibility to a Regional Entity) applies to each 
Reliability Standard that currently identifies the regional 
reliability organization as the compliance monitor. However, we will 
not repeat this proposal throughout the NOPR.
---------------------------------------------------------------------------

e. Frequency Response and Bias (BAL-003-0)
i. NERC Proposal
    164. The purpose of BAL-003-0 is to ensure that a balancing 
authority's frequency bias setting \121\ is accurately

[[Page 64789]]

calculated to match its actual frequency response.\122\ Among other 
things, BAL-003-0 establishes: (1) A Requirement for balancing 
authorities to review their frequency bias calculation on an annual 
basis to reflect any changes in their frequency response and to update 
the frequency bias to reflect changes to any factors used in the 
calculation, and to report frequency bias setting and methodology used 
to the NERC Operating Committee; (2) general Requirements on how 
balancing authorities should calculate frequency bias, including which 
factors or parameters to include in the calculation; (3) a Requirement 
which establishes a default frequency bias setting of 1 percent of 
yearly peak demand per 0.1 Hz for balancing authorities that serve 
native load; and (4) for balancing authorities that do not serve native 
load, a Requirement which establishes a default frequency bias setting 
of 1 percent of its estimated maximum generation level in the coming 
year per 0.1 Hz. The proposed Reliability Standard would apply to 
balancing authorities.
ii. Staff Preliminary Assessment
---------------------------------------------------------------------------

    \121\ Frequency bias setting is a value expressed in MW/0.1 Hz, 
set into a balancing authority ACE algorithm that allows the 
balancing authority to contribute its frequency response to the 
Interconnection. See NERC glossary at 5.
    \122\ The actual frequency response is the increase in output 
from generators after loss of a generator and determines the 
frequency at which generation and load come in balance again.
---------------------------------------------------------------------------

    165. Staff raised the concern that use of a frequency bias setting 
that is different from the natural frequency response of the balancing 
authority's area could result in less control actions than are 
appropriate to preserve system reliability.\123\ In addition, staff 
noted that several metrics, such as ACE, CPS1, and CPS2, use frequency 
bias setting as an input and the use of an incorrect value of frequency 
bias setting would result in incorrect measurement of actual 
performance with respect to ACE, CPS1, and CPS2.
---------------------------------------------------------------------------

    \123\ Staff Preliminary Assessment at 28-30.
---------------------------------------------------------------------------

    166. Staff noted that BAL-003-0 does not specify the actual minimum 
frequency response needed for reliable operation and how the frequency 
response should vary with the types of generation used to ensure that 
all types of generators are contributing their share of frequency 
response to assure the reliability of the Bulk-Power System.\124\ 
Further, staff expressed concern that data from actual events show that 
the natural frequency response for Eastern and Western Interconnections 
have been declining every year for the past decade.\125\ NERC's 
Frequency Response White Paper discusses these issues in detail.
---------------------------------------------------------------------------

    \124\ For example, certain generating units such as combined 
cycle units are not capable of increasing their output to restore 
the frequency back to 60 Hz and, in fact, their frequency responses 
tend to be opposite of what is required and thus aggravate a 
situation even further.
    \125\ According to NERC's Frequency Response White Paper (dated 
April 6, 2004), the frequency response in the Eastern 
Interconnection has declined at a rate of 70 MW/0.1 Hz annually.
---------------------------------------------------------------------------

    167. Staff noted that BAL-003-0 does not include Levels of Non-
Compliance and has only one Measure. Staff pointed out limitations in 
the single Measure contained in BAL-003-0, which requires balancing 
authorities to conduct frequency response surveys only when NERC 
specifically requests that such surveys be performed.
iii. Comments
    168. NERC states that it is important to distinguish between 
frequency bias and frequency response. With regard to the use of a 
frequency bias setting that is different from actual frequency 
response, NERC states that BAL-003-0 allows a balancing authority to 
set its frequency bias setting to match its actual frequency response. 
For some balancing authorities that are unable to calculate their 
frequency response dynamically, BAL-003-0 establishes a minimum of 1 
percent of the balancing authority's peak demand to ensure sufficient 
frequency response from its generators. Southern states that the sum of 
frequency bias setting for all of the balancing authorities in the 
Eastern Interconnection is 6,700 MW/0.1 Hz, whereas the actual 
frequency response is 2,800 MW/0.1 Hz. In sum, it claims that the 
Eastern Interconnection is over-biased by a factor of 2.4 and the 
matter of frequency bias setting should not be taken lightly.
    169. ReliabilityFirst agrees with staff that use of an 
inappropriate frequency bias setting may have an adverse impact on 
reliability and adds that this should be addressed by a team of 
experts. ReliabilityFirst also states that the Reliability Standard 
should include Levels of Non-Compliance. It states that, although the 
referenced surveys are intended to monitor deviations in frequency 
response, the survey should be used more regularly. In addition, 
ReliabilityFirst and CenterPoint state that it is appropriate to allow 
balancing authorities to continue to define their own methodology for 
calculating frequency bias setting.
    170. Southern expresses concern regarding staff's statement that 
``the frequency response of both the Eastern and Western 
Interconnections has decreased over the last 10 years'' \126\ and 
asserts that the Eastern Interconnection frequency bias setting is 
actually over-biased. In particular, Southern states that the NERC 
Operating Committee purposely chose to over-bias the frequency bias 
setting of the interconnections when it established the 1 percent floor 
and that the Eastern Interconnection frequency bias setting is 
currently over-biased by a factor of 2.4. Southern believes that some 
clarification and industry feedback may be useful in considering issues 
and concerns raised by staff with regard to frequency bias and the way 
it is used to maintain reliability.
---------------------------------------------------------------------------

    \126\ Staff Preliminary Assessment at 28.
---------------------------------------------------------------------------

iv. Commission Proposal
    171. The Commission proposes to approve BAL-003-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard as discussed below.
    172. NERC claims that BAL-003-0 allows a balancing authority to set 
its frequency bias setting to match its actual frequency response. 
Similarly, NERC's Petition describes the reliability goal of BAL-003-0 
is to: ``maintain interconnection frequency by * * * ensuring that the 
balancing authority's frequency bias setting is appropriately matched 
to its actual frequency response (governor plus load response).'' 
However, Southern asserts that the Eastern Interconnection is over-
biased. The Commission agrees that the frequency bias setting at peak, 
as compared to the actual frequency response of the system, is larger. 
The Commission is concerned that over-biasing is an approach to 
compensate for the low or no actual frequency response from some 
balancing authorities. In addition, Southern's assertion that the 
system is over-biased is inconsistent with NERC's stated reliability 
goal and highlights staff's concern that data from actual events 
suggest an overall decline in the actual frequency response in the 
Eastern and Western Interconnection.
    173. In response to ReliabilityFirst and CenterPoint, the 
Commission notes that the Requirement R2 of BAL-003-0 allows balancing 
authorities to choose a methodology for calculating frequency bias 
setting from at least two different ways. In addition, Requirement R2 
requires that each balancing authority shall establish its frequency 
bias setting that is as close as practical to, or greater than, its 
actual frequency response.
    174. In addition, the Commission notes that BAL-003-0 addresses 
frequency response only during normal conditions and does not establish 
the frequency bias setting that will be required during an emergency, 
black

[[Page 64790]]

start or system restoration using ``islanding'' schemes. Without proper 
frequency response, restoration of an isolated area using black start 
generation will be very difficult. Moreover, ``islanding'' schemes used 
in some areas of the country may not be stable without proper frequency 
response. The Commission is aware that WECC is addressing the need for 
proper frequency response during all operating conditions, including 
emergencies, and that ERCOT has a procedure in place.\127\
---------------------------------------------------------------------------

    \127\ See WECC's Frequency Response Standard White Paper (2005), 
at http://www.wecc.biz/documents /library/RITF /FRR--White--Paper-- 

v12--1-27-06.pdf
---------------------------------------------------------------------------

    175. Therefore, the Commission invites comments whether BAL-003-0 
appropriately addresses frequency bias setting during normal as well as 
emergency conditions and should a requirement 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.
    176. Further, the surveys mentioned in Measure M1 are only 
conducted when NERC requests such surveys. The Commission proposes that 
yearly surveys should be performed to compare the calculated frequency 
bias values against actual frequency response to refine the balancing 
authorities' frequency bias setting. While the Commission has 
identified concerns with regard to BAL-003-0, we believe that the 
Reliability Standard serves an important purpose in ensuring that 
balancing authorities accurately calculate their frequency bias setting 
to match their frequency response. While we have proposed a number of 
improvements to the Reliability Standard, we nonetheless, believe that 
the proposed Requirements set forth in BAL-003-0 are sufficiently clear 
and objective to provide guidance for compliance.
    177. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard BAL-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, the Commission 
proposes to direct that NERC submit a modification to BAL-003-0 that 
(1) includes Levels of Non-Compliance and (2) modifies Measure M1 to 
include yearly surveys.
f. Time Error Correction (BAL-004-0)
i. NERC Proposal
    178. 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.\128\ The Reliability Standard 
requires that: (1) Only a reliability coordinator is eligible to serve 
as time monitor and that the NERC Operating Committee shall designate a 
single reliability coordinator in each Interconnection to serve as time 
monitor for that Interconnection; (2) the time monitor shall monitor 
time error and initiate and terminate all corrective action orders in 
accordance with the North American Energy Standards Board (NAESB) Time 
Error Correction Procedure; (3) each balancing authority shall 
participate in time error corrections; and (4) any reliability 
coordinator in an Interconnection may request the time monitor to 
terminate a time error correction for reliability reasons, and that 
balancing authorities may request termination of a time error 
correction through their respective reliability coordinator for 
reliability reasons. The proposed Reliability Standard would apply to 
reliability coordinators and balancing authorities.
---------------------------------------------------------------------------

    \128\ 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 14. Time error is caused by the accumulation of 
frequency error over a given period.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    179. Staff noted that this Reliability Standard does not contain 
any Measures or Levels of Non-Compliance. Staff highlighted the 
importance of developing Measures to assure that each balancing 
authority and reliability coordinator participates in achieving time 
error corrections since an analysis of time error correction data 
available on the ERO's Web site indicates that participation may be 
lacking.
iii. Comments
    180. ReliabilityFirst agrees with staff that BAL-004-0 lacks 
Measures and Levels of Non-Compliance.
iv. Commission Proposal
    181. Although Requirement R3 requires that all balancing 
authorities participate in time error corrections, data from the NERC 
time error Web page indicates that the efficiency of the time error 
correction has significantly decreased over the last 10 years.\129\ 
This decrease in efficiency is an indication that not all of the 
balancing authorities are fully participating in time error 
corrections. The Commission expects the ERO will ensure compliance with 
this Requirement.
---------------------------------------------------------------------------

    \129\ NERC, Time Error Reports, at http://www.nerc.com/~filez/~timerror.html.
 Yearly data for total efficiency was 117 percent for 

1996 and 65 percent for 2005. If there is more participation than 
needed, the efficiency can be greater than 100 percent. The goal is 
to be near 100 percent.
---------------------------------------------------------------------------

    182. In addition, the Commission notes that WECC has implemented an 
automatic time error correction procedure \130\ that, according to data 
on the NERC Web site, is more effective in minimizing both time error 
corrections and inadvertent interchange.\131\ Although the WECC time 
error correction procedure is not before us for consideration, since 
the WECC procedure appears more effective, the Commission seeks comment 
whether it should require that NERC adopt Requirements similar to those 
in the WECC automatic time error correction procedure.
---------------------------------------------------------------------------

    \130\ See http://www.wecc.biz/documents/library/procedures/Time_Error_
 Procedure--10-04-02.pdf.

    \131\ See http://www.nerc.com/~filez/~inadv.html (regarding inadvertent interchange data) and http://www.nerc.com/~filez/

~timerror.html (regarding time error correction).
---------------------------------------------------------------------------

    183. While the Commission has identified concerns with regard to 
BAL-004-0, we believe that the Reliability Standard serves an important 
purpose in ensuring that time error corrections are conducted in a 
manner that does not adversely affect the reliability of the 
Interconnection. NERC should include Levels of Non-Compliance and 
additional Measures. Nonetheless, the proposed Requirements set forth 
in BAL-004-0 are sufficiently clear and objective to provide guidance 
for compliance.
    184. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC submit a modification to BAL-004-0 that 
includes Levels of Non-Compliance and additional Measures. Further, as 
discussed above, the Commission seeks comment whether it should require 
that NERC adopt Requirements similar to those in

[[Page 64791]]

the WECC automatic time error correction standard.
g. Automatic Generation Control (BAL-005-0)
i. NERC Proposal
    185. The reliability 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. BAL-005-0 requires that: (1) All generation, 
transmission, and load operating within an Interconnection must be 
included within the metered boundaries of a balancing authority area; 
(2) each balancing authority shall maintain regulating reserve to meet 
the control performance standard; and (3) adequate metering, 
communication and control equipment are employed in the provision of 
regulation service. In addition, the Reliability Standard includes a 
series of requirements pertaining to the operation of automatic 
generation control and a series of requirements pertaining to the 
calculation of ACE. The proposed Reliability Standard would apply to 
balancing authorities, generator operators, transmission operators, and 
load serving entities.
ii. Staff Preliminary Assessment
    186. Staff stated that this Reliability Standard does not require a 
generation operator or load-serving entity to provide automatic 
generation control capabilities to its balancing authority. Nor does it 
require the calculation of the amount of automatic generation control 
the generation operators or load-serving entities must have at all 
times. Without these requirements, it is not possible to determine 
whether there are adequate resources to maintain system frequency close 
to 60 Hz. Staff also noted that this Reliability Standard does not 
contain Measures or Levels of Non-Compliance.
iii. Comments
    187. ReliabilityFirst agrees with Staff that Measures and Levels of 
Non-Compliance need to be added to this Reliability Standard.
    188. CPUC expresses concern regarding a statement in the Staff 
Preliminary Assessment that BAL-005-0 does not require generator 
operators or load-serving entities to provide automatic generation 
control capabilities to the balancing authority.\132\ It suggests that, 
in lieu of requiring generators to provide automatic generation control 
units, balancing authorities should have a specified percentage of 
their load subject to automatic generation control. CPUC also states 
that the characteristics of the load in the area and the amount of 
generation that is responsive to changes in voltage and frequency 
should also be considered.
---------------------------------------------------------------------------

    \132\ Staff Preliminary Assessment at 32.
---------------------------------------------------------------------------

    189. LPPC states that Requirement R17, which provides that each 
balancing authority must periodically calibrate its time error and 
frequency devices, should be moved to a ``facility'' (FAC) Reliability 
Standard and should also apply to the transmission operations and 
reliability coordinators. LPPC states that balancing authorities do not 
have time error devices and the reliability coordinator is responsible 
for monitoring time error. It also states that the requirement to 
calibrate time error devices should be deleted.
iv. Commission Proposal
    190. The Commission proposes to approve Reliability Standard BAL-
005-0 as mandatory and enforceable. In addition, we propose to direct 
that NERC modify the Reliability Standard to address the Commission's 
concerns discussed below.
    191. Currently, the title of the Reliability Standard implies that 
only generators can participate in regulation control portion of 
contingency reserves. The title should be changed from Automatic 
Generation Control to clearly indicate that it includes the systems 
necessary to implement Demand Side Management and Direct Control Load 
Management as part of contingency reserves and not just conventional 
generation.
    192. The stated goal of this Reliability Standard is to assure that 
all generation and load is under the control of a balancing authority. 
Ideally, the balancing authority would have control over adequate 
amounts and types of generation reserves and controllable load 
management resources under all operating conditions and at all 
times.\133\ The Commission notes that Requirement R2 of BAL-005-0 
requires a balancing authority to obtain sufficient regulating reserves 
controlled by automatic generation control to meet the CPS requirements 
of BAL-001-0. However, the balancing authority may not itself have 
generation or control over loads that are the sources of regulating 
reserves. In contrast, a generation operator or load-serving entity 
typically has (or could have) the facilities to provide automatic 
generation control capabilities to the balancing authority. Recognizing 
that insufficient automatic generation control would constitute a 
violation of this Reliability Standard, the Commission is interested in 
understanding if any balancing authority is experiencing or is 
predicting any difficulty in obtaining sufficient automatic generation 
control.
---------------------------------------------------------------------------

    \133\ NERC Resources Subcommittee (Frequency Task Force), 
Frequency Response Standard Whitepaper (2004), at http://www.nerc.com/pub/sys/all_updl/oc/rs/Frequency_Response_White_Paper.pdf.
 See also WECC Reserve Issues Task Force, Frequency 

Response Standard White Paper (2005), at http://www.wecc.biz/documents/library/RITF/FRR_White_Paper_v12_1-27-06.pdf
.

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

    193. With regard to CPUC's concern, the Commission does not propose 
a requirement that all generators provide automatic generation control 
capabilities. The Commission recognizes that, due to unit 
characteristics or operating restrictions, certain types of resources 
may not be capable of operation with automatic generation control, or 
automatic generation control may not be economically feasible. With 
regard to CPUC's suggestion that the Reliability Standard require a 
balancing authority to have a certain percentage of its load subject to 
automatic generation control, the Commission notes that this may be one 
method of determining the amount of regulating reserve necessary to 
meet Requirement R2.
    194. The Commission notes that there are frequency excursions 
without loss of generation on a regular basis. Also, significant 
frequency excursions, without loss of generation are becoming more 
frequent.\134 \The Commission proposes that BAL-005-0 include a 
Requirement that addresses the amount of automatic generation control a 
balancing authority must have, prior to a contingency, to ensure that 
load variations and changes in schedules can be accommodated without 
frequency deviations beyond an appropriate threshold.
---------------------------------------------------------------------------

    \134\ See PJM RTO White Paper, Frequency Excursions, by Koza, 
Williams and Herbsleb.
---------------------------------------------------------------------------

    195. Requirement R17 requires balancing authorities to calibrate 
time error and frequency devices annually according to the accuracy 
levels detailed in the Reliability Standard. The Commission disagrees 
with LPPC that the reference to the calibration of time error devices 
should be removed from Requirement R17 of this Reliability Standard. 
The Commission prefers that Requirements intended to achieve a specific 
reliability goal be in the same Reliability Standard or group of 
Reliability Standards. Since the BAL

[[Page 64792]]

group of Reliability Standards contains reliability goals concerning 
frequency, the Commission believes that Requirement R17 is 
appropriately placed in BAL-005-0.
    196. While we have identified concerns with regard to BAL-005-0, we 
believe that the proposal serves an important purpose in ensuring that 
the functional requirements of a balancing authority's regulation 
service are met. The Commission believes it is important that NERC 
include Measures, including a Measure that would provide for 
verification of minimum automatic generation control or regulating 
reserves, and Levels of Non-Compliance. Nonetheless, the proposed 
Requirements set forth in BAL-005-0 are sufficiently clear and 
objective to provide guidance for compliance.
    197. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC 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 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.
h. Inadvertent Interchange (BAL-006-1)
i. NERC Proposal
    198. BAL-006-1\135\ requires that: (1) Each balancing authority 
calculate and record inadvertent interchange on an hourly basis; (2) 
all AC tie lines with adjacent balancing authority areas be included in 
a balancing authority's inadvertent account, and the balancing 
authority take into account interchange from jointly-owned generation; 
(3) all Interconnection points be equipped with common megawatt-hour 
meters with readings provided to adjacent balancing authorities; (4) 
adjacent balancing authorities compute and record inadvertent 
interchange on an hourly basis using common net scheduled interchange 
and net actual interchange values, and use the agreed-to data to 
compile their monthly accumulated inadvertent interchange; and (5) 
balancing authorities make after the fact corrections to the agreed-to 
inadvertent amount as needed to reflect actual operating conditions. 
The proposed Reliability Standard would apply to balancing authorities.
---------------------------------------------------------------------------

    \135\ On August 28, 2006, NERC submitted BAL-006-1 for approval, 
which replaces BAL-006-0. BAL-006-1 is the same as BAL-006-0 except 
that it includes a regional difference for SPP under an urgent 
action procedure. The comments submitted in response to the Staff 
Preliminary Assessment on BAL-006-0 apply equally to BAL-006-1.
---------------------------------------------------------------------------

    199. This Reliability Standard does not contain Measures but does 
contain a compliance monitoring process which requires a balancing 
authority to submit monthly inadvertent interchange reports to its 
regional reliability organization. The regional reliability 
organization is then required to submit a monthly inadvertent 
interchange summary for its region to NERC. This Reliability Standard 
contains one Level of Non-Compliance which states that if a balancing 
authority does not timely submit its inadvertent interchange report to 
the regional reliability organization, it shall be considered non-
compliant.
ii. Staff Preliminary Assessment
    200. Staff found that this Reliability Standard does not contain 
any Requirement that would prevent a balancing authority from 
excessively depending on other balancing authorities over time. This 
makes it possible for balancing areas to lean on other balancing areas 
and not settle their inadvertent accounts on a timely basis. Data 
available from the NERC Web site indicates that the magnitudes of 
inadvertent interchange for some regional reliability organizations in 
the Eastern Interconnection are increasing.\136 \
---------------------------------------------------------------------------

    \136\ See Staff Preliminary Assessment at 32 n.63.
---------------------------------------------------------------------------

    201. Staff also noted that this standard does not contain Measures 
and contains a single Level of Non-Compliance which is only associated 
with a Requirement for submission of a monthly report on inadvertent 
interchange.
iii. Comments
    202. NERC contends that inadvertent imbalances do not affect the 
real-time operations of the Bulk-Power System. Rather, they represent 
accumulation of the real-time imbalances over hours, days and weeks. A 
separate NAESB standard, referred to as ``Inadvertent Interchange 
Payback Standard--WEQ-007'' deals with how balancing authorities should 
eliminate their inadvertent interchanges. According to NERC, real-time 
imbalances between the generation and load are appropriately dealt with 
in BAL-001-0 and BAL-002-0.
    203. TAPS argues that the treatment afforded to balancing 
authorities under NERC's proposed Reliability Standards and NAESB rules 
is not comparable to the treatment afforded to non-control-area 
utilities under the Commission's OATT. In particular, TAPS states that, 
under the NERC standards, no penalties are assessed on a balancing 
authority for inadvertent interchange whereas under the OATT, penalties 
are assessed on non-control-area utilities for energy imbalances. TAPS 
is concerned that the OATT Reform NOPR does not adequately address the 
disparate treatment of imbalances.
    204. ReliabilityFirst agrees with staff that requirements should be 
added to prevent balancing authorities from depending excessively on 
other balancing authorities.
    205. LPPC states that Requirement R2 of BAL-006-0, which provides 
that each balancing authority shall include all AC tie lines that 
connect to its adjacent balancing authority areas in its inadvertent 
interchange account, should apply to ``physical'' adjacent balancing 
authorities. It explains that the NERC glossary explains that an 
``adjacent balancing authority'' is interconnected to another balancing 
authority either directly or via a multi-party agreement or 
transmission tariff. Thus, according to LPPC, the meaning of this 
Requirement changed when the word ``physical'' was removed during the 
conversion to the Version 0 standards. LPPC also contends that 
Requirements R4.1, R4.1.1, R4.1.2, R4.2, R4.3, and R5 are after-the-
fact energy accounting practices and should be incorporated into the 
NAESB business practices. LPPC also suggests that Requirement R3 of 
BAL-006 is redundant with Requirement R12.1 in BAL-005-0.
iv. Commission Proposal
    206. The Commission proposes to approve Reliability Standard BAL-
006-1 as mandatory and enforceable. In addition, we propose to direct 
that NERC modify the Reliability Standard to address the Commission's 
concerns discussed below.
    207. The Commission agrees with NERC that inadvertent imbalances do 
not affect the real-time operations of the Bulk-Power System. While 
large inadvertent imbalances pose no immediate threat to grid 
reliability, they

[[Page 64793]]

represent dependence by some balancing authorities on their neighbors. 
The Commission notes that WECC has placed a limit on the inadvertent 
accumulation based on the bias of the balancing authority. We invite 
comments as to whether accumulation of large amount of inadvertent 
imbalances is a concern to the industry and if so, options to address 
the accumulation.
    208. With respect to TAPS concerns regarding disparate treatment of 
imbalances for non-control area utilities, the Commission is addressing 
this issue in the OATT Reform NOPR, and TAPS should pursue its concerns 
in that proceeding. Moreover, the issues raised by TAPS do not impact 
reliability of the Bulk-Power System, but instead are economic in 
nature.
    209. We disagree with LPPC's comment that Requirement R2 should be 
applicable only to ``physical'' adjacent balancing authorities because 
it is reasonable to include those balancing authorities that are not 
physically adjacent but are connected by a multi-party agreement or 
transmission tariff.
    210. With regard to LPPC's comment that several of the Requirements 
should be incorporated into NAESB business practices, the Commission 
notes that there is currently an industry process in place between NERC 
and NAESB to determine which standards or portions of standards should 
be developed as business practices. The Commission prefers to use that 
process to resolve issues with the particular Requirements highlighted 
by LPPC. With respect to LPPC's comment that Requirement R3 of BAL-006-
0 is redundant with Requirement R12.1 in BAL-005-0, the Commission 
observes that the two Requirements, although worded somewhat 
differently, are very similar. We propose to require NERC to review 
these Requirements and remove any unnecessary duplication.
    211. As mentioned above, the Reliability Standard includes a single 
Level of Non-Compliance that is triggered if a balancing authority 
fails to report its inadvertent interchange on time. There are no 
specific Measures concerning the accumulation of large inadvertent 
imbalances. Nor are there Measures and Levels of Non-Compliance 
associated with each of the Requirements. While the Commission has 
identified concerns with regard to BAL-006-1, we believe that the 
proposal serves an important purpose in defining a process to ensure 
that balancing areas do not excessively depend on other balancing areas 
in the Interconnection for meeting their demand or interchange 
obligations. The Commission believes that it is important for NERC to 
provide Measures and additional Levels of Non-Compliance. Nonetheless, 
the proposed Requirements set forth in BAL-006-1 are sufficiently clear 
and objective to provide guidance for compliance.
    212. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes 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.
i. Regional Differences to BAL-006-1: Inadvertent Interchange 
Accounting and Financial Inadvertent Settlement
i. NERC Petition
    213. BAL-006-1 provides for two regional differences. First, NERC 
explains that a regional difference is needed 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 LMP could be 
implemented to meet their Commission directed market obligations. 
Subsequently, Southwest Power Pool (SPP) requested, and NERC approved, 
that the same regional difference apply to SPP as well.\137\
---------------------------------------------------------------------------

    \137\ BAL-006-1, filed on August 28, 2006, would extend the 
regional difference to SPP.
---------------------------------------------------------------------------

    214. Second, a regional difference would apply to the control area 
participants of MISO and SPP that would allow the 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 as such 
would not affect the accumulation of net-interchange by non-participant 
control areas.
ii. Comments
    215. These regional differences were not addressed in the Staff 
Preliminary Assessment and, consequently, no comments were received.
iii. Commission Proposal
    216. The two proposed regional differences relate solely to 
facilitating financial settlements of accumulated inadvertent 
interchange and have minimal, if any, reliability implications. These 
regional differences allow coordination with the current RTO market 
tariffs and promote incentives that would deter balancing authorities 
from depending excessively on other balancing authorities. Accordingly, 
the Commission proposes to approve these regional differences.
2. CIP: Critical Infrastructure Protection
a. Overview
    217. The Critical Infrastructure Protection group of Reliability 
Standards, as filed, consists of two standards aimed at reporting 
occurrences of sabotage to the proper authorities and establishing 
security for critical cyber assets. The first standard is CIP-001-0 
(Sabotage Reporting). The second standard is Urgent Action 1200 (UA-
1200), which addresses the cyber security of bulk electric system 
assets. UA-1200 was filed by NERC for informational purposes only and 
is therefore not the subject of Commission action in this proposed 
rule.
b. NERC Proposal
    218. CIP-001-0 requires that each reliability coordinator, 
balancing authority, transmission operator, generation operator and 
load-serving entity: (1) Have procedures for recognizing and for making 
their operating personnel aware of sabotage events; (2) have procedures 
for communicating information concerning sabotage events to appropriate 
``parties'' in the interconnection; (3) provide operating personnel 
with guidelines for reporting disturbances due to sabotage events; and 
(4) establish communications contacts with applicable government 
officials and develop appropriate reporting procedures. The reliability 
goal of the standard is to ensure that operating entities recognize 
sabotage events and inform appropriate authorities and each other to 
properly respond to the sabotage (via cyber or physical means) to 
minimize the impact on the Bulk-Power System.
c. Staff Preliminary Assessment
    219. Staff noted that CIP-001-0 does not require an entity to 
actually contact a governmental or regulatory body in the event of 
sabotage (though staff acknowledged that Standard EOP-004-0 does 
contain such a requirement). Staff also found that there is no

[[Page 64794]]

definition of ``sabotage'' in the Reliability Standard, which could 
lead to inconsistent application. Finally, staff stated that CIP-001-0 
does not contain Measures or Levels of Non-Compliance.
d. Comments
    220. In response to the Staff Preliminary Assessment, NERC comments 
that a requirement for reporting to government agencies is a matter of 
jurisdiction of the respective government agencies and not one of 
reliability. NERC states that it will consider developing a definition 
of sabotage, though it believes there is no confusion within industry 
regarding the meaning of ``sabotage'' in CIP-001-0.
    221. ReliabilityFirst comments that language in CIP-001-0 is 
ambiguous but does not identify any specific examples. It states that 
CIP-001-0 is a ``Version 0'' standard, which means that it was not 
developed using NERC's ANSI-accredited standards development process. 
ReliabilityFirst further comments that, during the development process 
for standards CIP-002 through CIP-009, the drafting team generally 
considered that standard CIP-001-0 dealt only with physical sabotage 
reporting and, therefore, addressed cyber incident reporting 
requirements in CIP-008.
    222. With regard to the lack of metrics, CenterPoint observes that 
metrics would be difficult to develop.\138\
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    \138\ Many commenters address concerns that staff raised with 
UA-1200. Those comments ran the gamut from support to disagreement 
with the Staff Preliminary Assessment. Since UA-1200 was submitted 
for informational purposes only, we will not address this 
Reliability Standard or related comments in the NOPR.
---------------------------------------------------------------------------

e. Commission Proposal
    223. The Commission proposes to approve CIP-001-0 as mandatory and 
enforceable. In addition, we propose directing that NERC develop 
modifications to the Reliability Standard, as discussed below.
    224. Order No. 672 explained that one of the factors that the 
Commission considers when reviewing a proposed Reliability Standard is 
whether the proposal is clear and unambiguous.\139\ The Requirements of 
CIP-001-0 refer to a ``sabotage event'' but do not define that term. 
Generally, we believe that ``sabotage'' is a commonly understood term 
\140\ and the Requirements of CIP-001-0 are enforceable. While the 
common understanding of the term sabotage should suffice in most 
circumstances, we are concerned that situations may arise in which it 
is not clear whether action pursuant to CIP-001-0 is required. For 
example, a break-in that gains access to a control room but does not 
cause damage, or a physical attack that results in minor damage, may be 
reported as sabotage by one entity but not another. Thus, the ERO 
should provide guidance clarifying the triggering event for an entity 
to take action pursuant to CIP-001-0.
---------------------------------------------------------------------------

    \139\ Order No. 672 at P 325
    \140\ The American Heritage Dictionary defines ``sabotage'' as 
``1. Destruction of property or obstruction of normal operations, as 
by civilians or enemy agents in time of war. 2. Treacherous action 
to defeat or hinder a cause or an endeavor; deliberate subversion.'' 
The American Heritage Dictionary of the English Language, (Houghton 
Mifflin Co., 4th Ed. 2000).
---------------------------------------------------------------------------

    225. CIP-001-0 requires that an applicable entity have procedures 
for recognizing sabotage events and making its operating personnel 
aware of sabotage events. However, it does not establish baseline 
requirements regarding what issues should be addressed by the developed 
procedures. For example, a procedure could identify a chronological 
``checklist'' of minimum actions that would apply if a sabotage event 
occurs, such as the timing and chain of communication, the preservation 
of evidence, repairing damage and contacting the appropriate law 
enforcement officials.
    226. As stated above, while an applicable entity must establish 
communication contacts, there is no Requirement in CIP-001-0 that an 
applicable entity actually contact the appropriate governmental or 
regulatory body in the event of sabotage consistent with the purpose of 
the standard, which states that ``[d]isturbances or unusual 
occurrences, suspected or determined to be caused by sabotage, shall be 
reported to the appropriate systems, governmental agencies, and 
regulatory bodies.'' \141\ We believe that mandatory reporting of a 
sabotage event is important to achieve the reliability goal of this 
proposed Reliability Standard. Further, since sabotage is an 
intentional action directed at a specific entity, the timely reporting 
of such events is of the utmost importance as a tool to warn other 
entities of potential problems.
---------------------------------------------------------------------------

    \141\ Reference in CIP-001-0 to Standard EOP-004-0, which 
requires entities to report actual or suspected physical or cyber 
attacks to the U.S. Department of Energy Operations Center would 
improve CIP-001-0.
---------------------------------------------------------------------------

    227. With regard to NERC's comments, NERC has not adequately 
explained its statement that reporting of sabotage is an issue of 
jurisdiction instead of reliability. It may be necessary for NERC to 
lay the groundwork with the appropriate government agencies, such as 
the Federal Bureau of Investigation or Department of Homeland Security, 
on an appropriate protocol for a report of sabotage. For example, NERC 
may want to consider the requirements for timely reporting developed by 
the Department of Homeland Security found in the Electric Sector 
Information Sharing & Analysis Center (ESISAC) Indications, Analysis 
and Warning Program (IAW) Standard Operating Procedure (SOP).\142\ 
Accordingly, the Commission proposes to direct NERC to 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.
---------------------------------------------------------------------------

    \142\ ESISAC IAW SOP requires a preliminary report to be filed 
within 60 minutes, a follow-up report to be filed within four to six 
hours after the preliminary report and a final report to be filed 
within 60 days.
---------------------------------------------------------------------------

    228. The Commission is further concerned that CIP-001-0 does 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. The Commission believes that a periodic review is appropriate 
because appropriate methods of responding to a sabotage event may 
change or become more sophisticated. Also, contacts for reporting an 
incident should be periodically updated.
    229. As mentioned above, CIP-001-0 does not contain Measures or 
Levels of Non-Compliance. Though CenterPoint believes that compliance 
elements would be difficult to develop, the Commission believes that 
Measures and Levels of Non-Compliance are important in this Reliability 
Standard to assure the consequences of failure to comply with the 
requirements are clear and unambiguous.
    230. While the Commission has identified concerns with regard to 
CIP-001-0, 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. The Commission 
believes that it is important for NERC to provide Measures and Levels 
of Non-Compliance for this proposed Reliability Standard, and that a 
definition of ``sabotage'' will provide desired clarity. Nonetheless, 
the proposed Requirements set forth in CIP-001-0 are sufficiently clear 
and objective to provide guidance for compliance.
    231. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission

[[Page 64795]]

by the ERO and that it will improve the reliability of the nation's 
Bulk-Power System, the Commission proposes 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 proposes 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.
3. COM: Communications
a. Introduction
    232. The Communications group contains two Reliability Standards. 
The first Reliability Standard 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 for addressing real-
time emergencies and that operating personnel carry out effective 
communications.

General Issues

Performance Metrics

    233. CenterPoint comments that ``some or all'' of the Communication 
group of Reliability Standards should be replaced by establishing 
performance metrics. It suggests that the Commission refer these 
Reliability Standards back to NERC with a directive to explore 
replacing process-oriented requirements with performance metrics. 
CenterPoint points to ERCOT as an example of a region that is 
developing performance metrics for telemetry and telecommunication 
infrastructure necessary to ensure situational awareness and address 
commercial considerations associated with a planned transition to a 
nodal market design.
    234. The Commission believes that including performance metrics 
within a Reliability Standard in specific instances would be an 
improvement. However, we do not see the development of performance 
metrics, lagging and/or forward-looking, as an adequate substitute for 
a mandatory and enforceable Reliability Standard.
    235. Accordingly, while the Commission encourages the use of 
performance metrics in conjunction with Measures and Requirements, we 
reject CenterPoint's suggestion that the proposed Communications 
Reliability Standards be replaced with performance metrics.

Local Control Centers

    236. The terms transmission operator and generator operator in 
NERC's functional model include the activities that those operators 
would perform to achieve their specific reliability goals. As 
identified by MISO and Allegheny, confusion can arise when using these 
terms in the context of an ISO or RTO or in any organization that pools 
resources. In such organizations, decision making and implementation 
are performed by separate groups. The decision-making portion of the 
transmission operator and, to a lesser extent, the generation operator 
function typically is completed by the ISO or RTO. The actual 
implementation is performed by either local transmission control 
centers or independent generation control centers. For example, the 
transmission and generation owners usually operate and maintain the 
individual facilities, control systems, SCADA systems, etc. The data 
from these locations are sent to the ISO or RTO control center either 
directly or through the entity's local control center. Upon receipt, 
the operators in the ISO or RTO control center make decisions that are 
transmitted to the local transmission and generation control centers. 
In some ISO or RTO arrangements, the request for action may be further 
divided and sent to individual generation facilities or transmission 
switching stations where it is actually implemented.
    237. The Commission proposes 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. 
All of the requirements for telecommunication would apply to all of 
these entities as appropriate to their respective functions within the 
transmission or generation operation functional model. Further, we note 
that this proposed definition of responsibility within a function would 
apply to other Reliability Standards that address such activities as 
training, operator certification, transmission operations, and cyber 
and physical security.
b. Telecommunications (COM-001-0)
i. NERC Proposal
    238. NERC states that COM-001-0 ensures coordinated 
telecommunications among operating entities, which is 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.
    239. NERC indicates that it will modify this proposed Reliability 
Standard to address the lack of Measures and Levels of Non-Compliance 
and resubmit the proposal for Commission approval in November 2006.
ii. Staff Preliminary Assessment
    240. The Staff Preliminary Assessment pointed out that the COM-001-
0 contains a general requirement to provide ``adequate and reliable'' 
telecommunications facilities for all applicable operating entities, 
but does not provide specific or minimum requirements on adequacy, 
redundancy and diverse routing of the telecommunications facilities 
necessary to ensure the exchange of operating information, both 
internally and among the operating entities.\143\
---------------------------------------------------------------------------

    \143\ Staff Preliminary Assessment at 45.
---------------------------------------------------------------------------

    241. Staff also indicated that the Requirements set forth in the 
proposed Reliability Standard do not differentiate between operating 
entities with different needs. Staff explained that, for example, 
reliability coordinators need telecommunication facilities beyond those 
required by other operating entities. In addition, staff noted that 
generator operator is not designated as an applicable entity.
iii. Comments
    242. NERC states with respect to Blackout Report Recommendation No. 
26, which called for a tightening of its communications protocols and 
upgrading its communication hardware, that it has installed a new 
conference bridge, approved a new set of hotline procedures for 
reliability coordinator hotline calls and is working on an upgrade of 
its Reliability Coordinator Information System that provides real-

[[Page 64796]]

time information to reliability coordinator control areas. NERC also 
states that it is not aware of any operating problems this Reliability 
Standard is causing. It explains that the methods chosen by operating 
entities to provide adequate and reliable communications facilities 
``will drive their needs for backup communications facilities and 
communications circuits with diverse routing.'' \144\
---------------------------------------------------------------------------

    \144\ NERC Comments at 118.
---------------------------------------------------------------------------

    243. MRO generally agrees with staff's assessment of COM-001-0 and 
suggests that the Reliability Standard be reviewed and modified in its 
entirety. It believes the Reliability Standard must balance the 
capability that the telecommunications industry can realistically 
provide against what is needed for reliability. MRO provides an example 
of a situation where an electric utility makes a good faith effort to 
comply with a dual communication path mandate by contracting with a 
third party vendor without knowing that this path contains a single 
point of failure for both communication paths.
    244. ReliabilityFirst comments on the need for expedited 
development of missing Measures and Levels of Non-Compliance.
iv. Commission Proposal
    245. The Commission proposes to approve Reliability Standard COM-
001-0 as mandatory and enforceable. In addition, we propose to direct 
that NERC develop modifications to the Reliability Standard, as 
discussed below.
    246. With regard to MRO's concern about redundancy, we believe that 
the Reliability Standard is sufficiently clear that the functional 
entity is responsible for achieving redundancy and diverse routing 
requirements.
    247. The Staff Preliminary Assessment expressed concern that COM-
001-0 does not provide specific or minimum requirements on adequacy, 
redundancy and diverse routing of the telecommunications facilities 
necessary to ensure the exchange of operating information. While MRO 
concurs with staff, NERC suggests that the methods chosen to comply 
with COM-001-0 will ``drive'' the applicable entities' need for 
redundant telecommunication facilities and diversely routed 
telecommunication circuits. The Commission believes that the 
Reliability Standard might be improved if NERC was to provide specific 
or minimum requirements for adequacy, redundancy and diverse routing. 
At the same time, we are concerned that the addition of specific or 
minimum requirements may result in a Reliability Standard that reduces 
the flexibility of applicable entities in achieving compliance or 
implementing new technologies and motivates applicable entities to 
simply achieve compliance with the minimum requirement. Accordingly, we 
seek comment on the specific requirements or performance criteria for 
telecommunications facilities.\145\
---------------------------------------------------------------------------

    \145\ Loss of data from some entities may result in errors or 
non convergence of state estimators and security analysis, which may 
result in loss of a wide area view, situational awareness, and 
economic information such as LMP.
---------------------------------------------------------------------------

    248. Further, assuming we direct NERC to develop such specific 
requirements, the Commission also seeks comment whether the modified 
Reliability Standard should provide requirements that also consider the 
relative role of applicable entities. While the Commission believes 
that applicable entities of all roles should have adequate 
telecommunications equipment, the needs will likely vary based on role. 
We would expect a modification to COM-001-0, if directed, to develop 
sufficient information so that transmission owners and other applicable 
entities of all sizes will have some specific guidance as to what is 
required to maintain an acceptable telecommunications facility.
    249. The Commission notes that this Reliability Standard is 
applicable to transmission operators, balancing authorities, 
reliability coordinators, and NERCNet user organizations. However, 
during normal and emergency operations, communications with additional 
entities are required. For example, during a blackstart when normal 
communications may be disrupted, it is essential that the transmission 
operator, balancing authority, and reliability coordinator have 
communications with the generator operators and distribution providers. 
The Commission proposes that NERC modify the applicability section of 
COM-001-0 to make generator operators and distribution providers as 
applicable entities and modify the requirements of this Reliability 
Standard as necessary to account for this change.
    250. Telecommunication facilities for emergency operations 
including restoration require special provisions which are lacking in 
COM-001-0. Inadequate telecommunication facilities during emergency 
operations would aggravate the duration and extent of the emergency and 
delay the subsequent restoration. Periodic testing of telecommunication 
facilities will insure that these facilities are functional when 
required. Accordingly, the Commission proposes to direct NERC to modify 
COM-001-0 to include requirements for communication facilities for use 
during emergency situations and periodic testing of these facilities.
    251. While the Commission has identified a number of concerns with 
regard to COM-001-0, this proposed Reliability Standard serves an 
important purpose by requiring transmission operators and others to 
have necessary telecommunication equipment. Further, NERC should 
provide Measures and Levels of Non-Compliance for this proposed 
Reliability Standard. Nonetheless, the Requirements set forth in COM-
001-0 are sufficiently clear and objective to provide guidance for 
compliance.
    252. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard COM-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 propose 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 provider as applicable entities; and (3) includes 
requirements for communication facilities for use during emergency 
situations.
c. Communications and Coordination (COM-002-1)
i. NERC Proposal
    253. The stated purpose of COM-002-1 is 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 authority and transmission 
operators to notify others through pre-determined communication paths 
of any condition that could threaten the reliability of its area or 
when firm load shedding is anticipated. NERC has indicated that it will 
modify this Reliability Standard to address the lack of Measures and 
Levels of Non-Compliance and resubmit it for Commission approval in 
November 2006.
ii. Staff Preliminary Assessment
    254. Staff explained that COM-002-1 does not require that ``the 
appropriate

[[Page 64797]]

operating actions in normal and emergency operating conditions that may 
have reliability impact beyond a local area or Reliability 
Coordinator's area * * * be assessed and approved by the Reliability 
Coordinator, before being implemented by the operating entities.'' 
\146\ Staff noted that Blackout Report Recommendation No. 26 calls for 
effective communications, but COM-002-1 does not provide for 
``tightened communication protocols.''
---------------------------------------------------------------------------

    \146\ Staff Preliminary Assessment at 44.
---------------------------------------------------------------------------

iii. Comments
    255. NERC agrees with the need to develop additional Reliability 
Standards addressing consistent communications protocols among 
personnel responsible for the reliability of the Bulk-Power System. 
However, NERC does not believe that ``tightened communication 
protocols'' required by the Blackout Report should include the 
requirement that operating actions in normal and emergency conditions 
must be assessed and approved by the reliability coordinator before 
being implemented by the operating entities. Other Reliability 
Standards require coordination and communications among all operating 
entities, and transmission operators and balancing authorities have 
adequate authority to restore imbalances and mitigate transmission (SOL 
and IROL) violations.
    256. National Grid agrees with the Staff Preliminary Assessment 
that tighter communications protocols are needed with respect to 
assessment and approval of operating actions under normal and emergency 
conditions, but it believes any new requirements belong in COM-002-1, 
which deals with coordination rather than COM-001-0, which sets forth 
requirements for telecommunication facilities. National Grid states 
that this Reliability Standard for communication protocols should not 
be intermixed with Reliability Standards for communication facilities.
    257. ReliabilityFirst and MRO maintain that, without specific 
Measures and Levels of Non-Compliance, NERC will not be able to 
implement consistent and effective enforcement of COM-002-1. MRO states 
that the Reliability Standard should clarify the role of the Regional 
Entities and clarify any distinctions between COM-001-0 and COM-002-1.
iv. Commission Proposal
    258. COM-002-1 requires communications with the reliability 
coordinator through predetermined paths when a condition could threaten 
``the reliability of [the reliability coordinator's] area.'' \147\ As 
noted above, several commenters are of the opinion that this 
Reliability Standard does not recognize that operating actions can have 
reliability impacts beyond the local area for which a particular 
reliability coordinator is responsible. NERC disagrees on this issue 
and points out that other Reliability Standards require coordination 
and communications among operating entities. However, the Reliability 
Standards to which NERC refers require such coordination and 
communications only in limited, specified circumstances. Further, while 
NERC states that other Reliability Standards require coordination and 
communications among all operating entities, the Commission notes that 
transmission operators have unilateral authority to mitigate 
transmission (SOL and IROL) violations within their jurisdictions. 
Thus, those entities can take actions that place others at risk because 
they do not have a wide area view. Accordingly, we propose directing 
NERC to add a Requirement that the reliability coordinator assess and 
approve actions that have impacts beyond the area views of transmission 
operators and balancing authorities.
---------------------------------------------------------------------------

    \147\ COM-002-1, Requirement R1.1.
---------------------------------------------------------------------------

    259. In addition, we also believe that tightened protocols are 
necessary. The Blackout Report identifies ineffective communication as 
one of the common factors among major cascading outages.\148\ The 
Commission recognizes NERC for its efforts in following up on Blackout 
Report Recommendation No. 26, especially with respect to specific 
communication protocols implemented to date. We encourage NERC to 
continue its effort in working with industry with the goal to 
incorporate their work into the Reliability Standards to achieve 
technical excellence as part of NERC's stated goal. In addition, these 
efforts should include priorities that target improving the Reliability 
Standards in the near future. Specifically, NERC should modify COM-002-
0 to ``tighten'' communications, especially for communications during 
alerts and emergencies. Staff explained in the Staff Preliminary 
Assessment that this can be understood to include two key components: 
(1) Effective communications that are delivered in clear language via 
pre-established communications paths among pre-identified operating 
entities; and (2) communications protocols which clearly identify that 
any operating actions with reliability impact beyond a local area or 
beyond a reliability coordinator's area must be communicated to the 
appropriate reliability coordinator for assessment and approval prior 
to implementation to ensure reliability of the interconnected 
systems.\149\ NERC should work from these components to develop 
modifications to COM-002-0 that will implement Blackout Report 
Recommendation No. 26.
---------------------------------------------------------------------------

    \148\ Blackout Report at 107.
    \149\ Staff Preliminary Assessment at 43-44.
---------------------------------------------------------------------------

    260. The Commission notes that this Reliability Standard is 
applicable to transmission operators, balancing authorities, 
reliability coordinators, and generator operators. However, during 
normal and emergency operations, communications with additional 
entities are required. For example, during emergency situations, it is 
essential that the transmission operator, balancing authority, and 
reliability coordinator have communications with distribution 
providers. The Commission proposes that NERC modify the applicability 
section of COM-002-1 to make distribution providers applicable entities 
and modify the requirements of this Reliability Standard as necessary 
to account for this change.
    261. While the Commission has identified concerns regarding COM-
002-1, this proposed Reliability Standard serves an important purpose 
by requiring users, owners and operators of the Bulk-Power System to 
implement the necessary communications and coordination among entities. 
NERC should provide Measures and Levels of Non-Compliance. Nonetheless, 
the Requirements set forth in COM-002-1 are sufficiently clear and 
objective to provide guidance for compliance.
    262. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
The Commission proposes to approve Reliability Standard COM-002-1 as a 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose 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

[[Page 64798]]

balancing authorities; \150\ (3) includes distribution providers as 
applicable entities; and (4) requires tightened communications 
protocols, especially for communications during alerts and emergencies. 
Alternatively, with respect to this final issue, we propose to direct 
NERC to develop a new Reliability Standard that responds to Blackout 
Report Recommendation No. 26 in the manner just described.
---------------------------------------------------------------------------

    \150\ This Requirement could be included in this communication 
Reliability Standard or in an operating Reliability Standard(s), at 
NERC's option.
---------------------------------------------------------------------------

4. EOP: Emergency Preparedness and Operations
a. Overview
    263. 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.
b. Emergency Operations Planning (EOP-001-0)
i. NERC Proposal
    264. 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. The Reliability Standard 
applies to balancing authorities and transmission operators and 
identifies the regional reliability organization as responsible for 
monitoring compliance. It also requires the regional reliability 
organization to review and evaluate emergency plans every three years 
to ensure that these plans consider the elements that the Reliability 
Standard specifies should be considered when developing an emergency 
plan, e.g., system energy use, load management and, environmental 
constraints.
ii. Staff Preliminary Assessment
    265. Staff noted that while EOP-001-0 requires a transmission 
operator and balancing authority to develop, maintain, and implement a 
set of plans to mitigate operating emergencies resulting from either 
insufficient generation or transmission, there is no similar 
requirement for a reliability coordinator, which is the highest level 
of authority responsible for the Bulk-Power System. Staff also found 
the requirement that transmission operators have emergency load 
reduction plans capable of being implemented within 30 minutes after 
declaration of an operating emergency to be ambiguous. According to 
staff, the requirement could be read to imply that load-shedding 
capability with an implementation time of up to 30 minutes is 
acceptable to address system emergencies. Staff deemed this conclusion 
to be inappropriate. It could expose the system to higher risk because 
load shedding is the option of last resort and must be capable of being 
implemented much sooner than 30 minutes. Finally, staff noted that the 
Reliability Standard does not define transmission-related ``normal,'' 
``alert,'' and ``emergency'' states, does not provide criteria for 
entering into these states, nor does it identify authority for 
declaring these states.
iii. Comments
    266. NERC maintains that staff's concerns regarding reliability 
coordinator involvement are addressed in other Reliability Standards. 
It states that proposed Reliability Standard IRO-001-0 requires a 
reliability coordinator to have plans and coordination agreements to 
mitigate capacity and energy emergencies. Proposed Reliability Standard 
IRO-005-0 provides more details on handling emergencies and mitigating 
SOL and IROL violations. Further, Attachment 1 to proposed Reliability 
Standard EOP-002-1 provides procedures that a load-serving entity can 
use to work with its reliability coordinator to obtain capacity and 
energy when it has exhausted all other options and can no longer 
provide its customers' expected energy requirements. NERC also states 
that the NERC Operating Committee approves every reliability 
coordinator reliability plan and posts those plans on its Web site. 
Finally, NERC states that the 30-minute limit for mitigating IROL 
violations is one of many standards gleaned from decades of 
interconnected systems operation experience, and concludes that 
requiring SOL and IROL mitigation ``as soon as possible'' but within no 
longer than 30 minutes is reasonable because it allows the system 
operator to decide on what course of action to take.
    267. MRO agrees with staff that the reliability coordinator should 
be required to have an emergency plan. The requirement that load 
reduction plans be capable of implementation within 30 minutes should 
be clarified, and the Reliability Standard should include the 
definitions for ``normal,'' ``alert'' and ``emergency states.'' 
However, MRO notes that these definitions were not finalized at the 
time the Staff Preliminary Assessment was issued.
    268. ReliabilityFirst agrees that the reliability coordinator is 
the highest authority on the bulk electric system with regard to real 
time, coordinated operations. The plans mentioned in the Reliability 
Standard are intended for operators within each reliability 
coordinator's respective area. ReliabilityFirst states that the 30 
minute load-shedding requirement establishes a maximum threshold. It is 
expected that action that can be taken prior to that deadline will be 
implemented as soon as possible.
    269. The ISO/RTO Council and Alberta agree that EOP-001-0 should 
apply to reliability coordinators. ISO/RTO Council notes that NERC's 
Reliability Coordinator Working Group is conducting a pilot program in 
the summer of 2006 to define terms to be used in ``normal,'' ``alert'' 
and ``emergency'' conditions. The ISO/RTO Council recommends that NERC 
adopt these terms as part of the NERC glossary following completion of 
the pilot program.
    270. CPUC comments that it is reasonable to state that expeditious 
load shedding must be available, if that is the intent of Commission 
staff's discussion of the load-shedding timing requirement in EOP-001-
0. However, the CPUC takes the position that it is not reasonable to 
require that all load shedding capability be available within 30 
minutes. That would entail very significant, and possibly unnecessary, 
costs to the detriment of ratepayers.
iv. Commission Proposal
    271. The Commission proposes to approve proposed Reliability 
Standard EOP-001-0 as mandatory and enforceable. In addition, the 
Commission proposes to direct that NERC develop modifications to the 
Reliability Standard, as discussed below.
    272. The proposed Reliability Standard applies to transmission 
operators and balancing authorities. The Commission believes that the 
applicability portion of the Reliability Standard is sufficiently clear 
as to who must comply with the filed version of the standard and can be 
enforced on these entities. However, commenters express concern that it 
does not assign a role to the reliability coordinator. NERC states that 
the 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

[[Page 64799]]

and procedures, including the authority to prevent or mitigate 
emergency operating situations in both next-day analysis and real-time 
operations.'' \151\ Given the importance NERC attributes to the 
reliability coordinator in connection with matters covered by EOP-001-
0, the Commission is persuaded that this Reliability Standard should 
also apply to the reliability coordinator and proposes that it be 
modified to include the reliability coordinator as an applicable 
entity.
---------------------------------------------------------------------------

    \151\ NERC glossary at 11.
---------------------------------------------------------------------------

    273. The proposed Reliability Standard allows load reduction within 
30 minutes of IROL violations. NERC maintains that requiring SOL and 
IROL mitigation ``as soon as possible'' but within no longer than 30 
minutes is reasonable because it allows the system operator to decide 
on what course of action to take. The Commission understands that it is 
not the intent of this Reliability Standard to require that shedding of 
all available load occur within 30 minutes, but rather only the amount 
necessary to correct system emergencies. However, NERC's conclusion 
that IROL or SOL mitigation within no longer than 30 minutes is 
reasonable does not address the Commission's concern. That concern is 
rooted in the view that load shedding must be capable of being 
implemented as soon as possible and much sooner than 30 minutes. The 
reference to 30 minutes in EOP-001-0 could suggest that anything up to 
that limit is acceptable. Consistent with NERC's comments, the 
Commission proposes that this Reliability Standard should be modified 
to clarify that load shedding should be capable of being implemented as 
soon as possible and much less than 30 minutes.
    274. Recommendation No. 20 of the Blackout Report called for 
establishing ``clear definitions for the normal, alert, and emergency 
operational system conditions,'' and stated that the ``roles, 
responsibilities and authorities of Reliability Coordinators and 
control areas under each condition'' should be clarified.\152\ In the 
Commission's view, the inability to identify clearly when the system is 
operating outside of the normal/secure system state, and the resulting 
inability to recognize the level of reliability deterioration 
experienced under all system conditions (other than the normal/secure 
system state), represents a deficiency that should be resolved. Some 
ISOs and RTOs clearly define multiple operating system states ranging 
from normal to restoration. System metering data and computer software 
that identify for system operators the current system state and clear 
procedures have been established to assist the operator in returning 
the system to the normal state as quickly as possible. Indeed, the 
overall operational objective is to proactively operate the Bulk-Power 
System to achieve a normal system state as contemplated by FPA section 
215.
---------------------------------------------------------------------------

    \152\ Blackout Report at 158.
---------------------------------------------------------------------------

    275. The Commission believes that there is a need for clearly 
defined system states to be incorporated into real-time operation that 
can significantly improve operator recognition of emergency conditions, 
rapid and accurate response, and recovery to normal system conditions. 
In addition, a clearly defined set of system states implemented in 
real-time will help the operator proactively avert escalation of system 
disturbances and thus avert cascading outages and reliability standard 
violations. Moreover, statistics surrounding operating states based on 
the duration and frequency of excursions to non-normal system states 
can provide understanding for the operator, management, the ERO and 
regulators on how reliably the system is being operated, how reliable 
it was operated over historic periods, trends in reliability 
performance and metrics that can provide part of the foundation for 
defining ``an adequate level of reliability'' that we required in our 
Order certifying the ERO.
    276. We therefore propose that the ERO modify this Reliability 
Standard to include clearly defined system states for capacity, energy, 
and transmission to be implemented in real-time operations. We note 
that some control areas define and effectively use more than the 
``normal,'' ``alert'' and ``emergency'' system states included in the 
Blackout Report recommendations. The ERO should determine the optimum 
number of system states to be employed continent-wide for consistency 
in the development of reliability performance metrics and should 
consider the addition of the restoration state.
    277. While the Commission has identified concerns with regard to 
EOP-001-0 that call for improvements, we believe that the Reliability 
Standard in its present form serves an important purpose in promoting 
appropriate planning for operating emergencies. For instance, while we 
believe clarifying the terms ``normal,'' ``alert,'' and ``emergency'' 
will provide for clearer metrics for measuring performance, the 
Commission believes that system operators generally understand when the 
system is in each of these states. The Requirements are sufficiently 
clear and objective to provide guidance for compliance.
    278. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission therefore proposes 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, we propose 
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.
c. Capacity and Energy Emergencies (EOP-002-1)
i. NERC Proposal
    279. EOP-002-1 applies to balancing authorities and reliability 
coordinators and is intended to ensure that they are prepared for 
capacity and energy emergencies. NERC states that the proposed 
Reliability Standard requires that balancing authorities have the 
authority to bring all necessary generation on line, communicate the 
energy and capacity emergency with the reliability coordinator, and 
coordinate with other balancing authorities. NERC also states that the 
Reliability Standard limits a balancing authority's use of any other 
balancing authority's bias contribution to the Interconnection, 
referred to as ``leaning on the ties.'' EOP-002-1 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 load serving entity.
ii. Staff Preliminary Assessment
    280. The Staff Preliminary Assessment explained that while EOP-002-
1 addresses responsibility, authority and actions to be taken to 
alleviate a generation capacity and energy emergency, it does not 
address an emergency resulting from insufficient

[[Page 64800]]

transmission capability, nor is this issue addressed elsewhere in other 
proposed Reliability Standards. Staff noted that transmission loading 
relief (TLR) procedures discussed in Reliability Standard IRO-006-3 are 
not appropriate for addressing actual transmission emergencies since, 
as stated in the Blackout Report, they are ``not fast and predictable 
enough for use in situations in which an Operating Security Limit is 
close to or actually being violated.'' \153\
---------------------------------------------------------------------------

    \153\ Id. at 163.
---------------------------------------------------------------------------

iii. Comments
    281. NERC states that, while EOP-002-1 does not address emergencies 
resulting from insufficient transmission capability, a number of other 
proposed Reliability Standards related to transmission operation and 
reliability coordination address the need to operate within facility 
limits, SOL and IROL. NERC states that collectively the proposed 
Reliability Standards address emergencies resulting from insufficient 
transmission capability.
    282. MRO and ReliabilityFirst state that they agree with staff's 
assessment of EOP-002-1. In addition, MRO states that TLRs are not 
appropriate for addressing actual transmission emergencies for the 
reasons stated in the Blackout Report.
    283. The ISO/RTO Council states that before approving EOP-002-1, 
the Commission should direct NERC to include in that Reliability 
Standard a requirement to assess whether sufficient transmission 
capability exists to allow the capacity and energy emergency plan 
mandated by the Reliability Standard to be ``robust enough to ensure 
adequate resources.'' The ISO/RTO Council also agrees with staff's 
concerns that TLRs are not appropriate for addressing actual 
transmission emergencies for the reasons stated in the Blackout Report. 
It notes that ISOs and RTOs use redispatch to correct SOL and IROL 
instead of TLR procedures. Moreover, the ISO/RTO Council states that 
ISOs and RTOs that redispatch to protect system reliability do not get 
credit for such actions when another entity declares a TLR event. It 
also states that redispatch allows for a far more targeted, and thus 
effective, tool to resolve an imminent reliability threat than does a 
TLR, which can trigger additional TLRs on neighboring systems. As a 
result, the applicability of any Reliability Standard that relies on 
TLRs as the specific reliability tool to be used in an ISO or RTO 
region could be detrimental to system reliability.
iv. Commission Proposal
    284. The Commission shares the concern expressed by MRO and the 
ISO/RTO Council that the Emergency Plan required by EOP-002-1 addresses 
only generation capacity and energy emergencies and does not address 
emergencies resulting from inadequate transmission capability. NERC 
states that other Reliability Standards address mitigation of SOL and 
IROL violations due to loss of transmission facilities. While we agree 
with NERC that other Reliability Standards address mitigation of SOL 
and IROL violations, we remain concerned that neither EOP-002-1 nor any 
other Reliability Standard addresses the impact of inadequate 
transmission during generation emergencies.
    285. Requirement R6 of EOP-002-1 identifies various remedies that a 
balancing authority should use to comply with Control Performance and 
Disturbance Control Standards including loading all available 
generating capacity and deploying all available operating reserve. The 
Commission proposes that the ERO modify Requirement R6 to include use 
of demand side management as one of the possible remedies.
    286. MRO and the ISO/RTO Council express concern that the TLR 
method is inappropriate for addressing actual transmission emergencies. 
The Commission's proposal to address this concern is discussed fully in 
relation to Reliability Standards IRO-006-3 where the use of TLRs to 
mitigate potential or actual SOL and IROL violations is specified in 
these standards. The Commission shares the concerns of commenters about 
the use of TLR procedures for reasons stated in the Blackout Report, 
i.e., they 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. The Commission therefore proposes to instruct the ERO 
to include a clear warning that the TLR procedure is an inappropriate 
and ineffective tool to mitigate IROL violations or for use in 
emergency situations.
    287. While the Commission has identified concerns with regard to 
EOP-002-1 that call for improvements, we believe that the proposed 
Reliability Standard serves an important purpose in promoting the goal 
of ensuring that balancing authorities and reliability coordinators are 
prepared for capacity and energy emergencies. In addition, the 
Requirements of the proposed Reliability Standard are sufficiently 
clear and objective to provide guidance for compliance. Accordingly, 
giving due weight to the technical expertise of the ERO and with the 
expectation that the Reliability Standard will accomplish the purpose 
represented to the Commission by the ERO and that it will improve the 
reliability of the nation's Bulk-Power System, the Commission proposes 
to approve Reliability Standard EOP-002-1 as mandatory and enforceable. 
In addition, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) 
of our regulations, we propose to direct that NERC submit a 
modification to EOP-002-1 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 demand side management in Requirement R6 
as one possible remedy that a balancing authority should use to bring 
it in compliance with Control Performance and Disturbance Control 
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.
d. Load Shedding Plans (EOP-003-0)
i. NERC Proposal
    288. EOP-003-0 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. The proposed Reliability Standard 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. NERC indicates that it plans to 
modify EOP-003-0 to include Measures and Levels of Non-Compliance.
ii. Staff Preliminary Assessment
    289. Staff stated that EOP-003-0 does not specify the minimum load-
shedding capability that should be provided and the maximum amount of 
delay before load shedding can be implemented. Staff noted that this 
Reliability Standard does not require that safeguards be provided to 
shield operators from retaliation when they declare an emergency or 
shed load in accordance with previously approved guidelines, as

[[Page 64801]]

the Blackout Report recommends.\154\ In addition, the Staff Preliminary 
Assessment observed that the Reliability Standard does not require 
periodic drills of simulated load shedding. It stated that such drills 
are important to test the effectiveness of the processes, 
communications and protocols, and to familiarize operators from 
reliability coordinators, transmission operators and load serving 
entities with their respective roles and responsibilities in connection 
with the load shedding plans.
---------------------------------------------------------------------------

    \154\ Id. at 147.
---------------------------------------------------------------------------

iii. Comments
    290. NERC states that it considers operator liability to be a 
regulatory rather than a reliability issue, but that it has taken 
relevant action on two fronts. First, Version 0 of the proposed 
Reliability Standards provides direction to operators on when they 
should manually initiate load shedding, and expects operators to be 
empowered to take whatever action is necessary to ensure the 
reliability of the Bulk-Power System without fear of liability claims. 
Second, the regional reliability organizations are reviewing the 
applicability of automatic load-shedding plans in specific geographic 
areas, and are to present their recommendations to NERC.
    291. MRO states that the requirement that the balancing authority 
and transmission operator have the capability and authority to shed 
load rather than risk an uncontrolled failure is sufficient to meet the 
intent of this Reliability Standard and that the additional information 
suggested by staff is unnecessary. MRO maintains that the amount of 
load to be shed and the timeframe for shedding it is directly related 
to the system problem or condition at the time of the event. Adding an 
expected percentage and timeframe will not improve the Reliability 
Standard and would likely not meet every situation or system condition. 
MRO also concurs with staff that the Reliability Standard should 
require periodic drills of simulated load shedding and suggests that 
NERC better identify the type of training that should include load shed 
drills.
    292. MidAmerican shares staff's concerns and suggests that the 
Reliability Standard should mandate regional studies to determine the 
appropriate minimum requirements for load shedding, recognizing the 
regional network is a portion of the interconnected network. It notes 
that certain portions of the Eastern Interconnection are not 
susceptible to instability, uncontrolled separation and cascading, 
while other portions of the Eastern Interconnection are very 
susceptible to these events. MidAmerican states that it may be more 
important to provide additional load-shedding capabilities in the 
portion of the Interconnection that is more susceptible to instability.
    293. Southern, ReliabilityFirst and MRO agree with staff that 
transmission operators who initiate load shedding pursuant to 
guidelines should be shielded from liability or retaliation. Southern 
states that it seems more appropriate to also address limitation of 
liability in each transmission owner's OATT. Southern also submits that 
the role of the reliability coordinator as currently established under 
EOP-003-0 is appropriate and is consistent with its role in maintaining 
reliability. Southern states that while the reliability coordinator 
should be aware of the restoration plan required by the Reliability 
Standard, approval of that plan would have no clear benefit.
iv. Commission Proposal
    294. As discussed above, EOP-003-0 does not specify the minimum 
load-shedding capability that should be provided and the maximum amount 
of delay before load shedding can be implemented. The Commission 
disagrees with MRO's position that adding a minimum load shedding 
capability and timeframe will not improve the Reliability Standard 
because the Reliability Standard does not specify amount or timeframe 
to shed load. The actual amount of load to be shed, location and 
timeframe will be at the discretion of the system operator based on the 
nature of the system problem and his assessment of corrective actions 
required. 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 due to no or delayed actions 
to shed load. The Commission agrees with MidAmerican that specifying a 
minimum capability and maximum allowable delay is necessary to ensure 
an adequate load-shedding plan to contain a disturbance and prevent 
system cascading. The Commission proposes that the Reliability Standard 
should be modified to address this matter. We recognize that this issue 
may be addressed on a regional basis if it meets the requirements for a 
regional difference as suggested by MidAmerican.
    295. Blackout Report Recommendation No. 8, which is addressed to 
``legislative bodies and regulators,'' recommends that operators who 
initiate load shedding pursuant to approved guidelines should be 
shielded from ``liability suits or other forms of retaliation, provided 
their action is pursuant to previously approved guidelines.'' \155\ 
Neither the Commission nor the ERO has authority under section 215 of 
the FPA to shield operators from liability suits for actions that they 
take or fail to take. Further, the Commission believes that an added 
Requirement to shield operators from retaliation would be vague and 
beyond the scope of the Reliability Standard. As explained by NERC, the 
proposed Reliability Standards provide direction to operators on when 
they should manually initiate load shedding. The goal of EOP-003-0 is 
to ensure that a transmission operator ``must have the capability and 
authority to shed load'' and the Requirements provide the specifics on 
how this is to be achieved. We believe that this is sufficient to 
empower operators to take necessary action to ensure the reliability of 
the Bulk-Power System. The Commission notes that NERC has required each 
transmission operator post a letter from its CEO stating that there 
will be no retaliation against system operators that shed load in 
accordance with approved corporate policies and procedures. A review of 
such letters is included in NERC Readiness Reviews. The Commission 
believes that this is an acceptable approach.
---------------------------------------------------------------------------

    \155\ Id. at 147.
---------------------------------------------------------------------------

    296. MRO concurs with staff that the Reliability Standard should 
require periodic drills of simulated load shedding. It suggests that 
NERC better identify the type of training that is required to include 
load shed drills. Load shedding drills will improve the operator 
response to emergencies, including timely implementation of load 
shedding. The Commission therefore proposes to direct the ERO to modify 
this Reliability Standard to require periodic drills of simulated load 
shedding.
    297. The Reliability Standard does not contain any Measures or 
Levels of Non-Compliance. The Commission proposes that it be modified 
to address this deficiency.
    298. While the Commission has identified concerns with regard to 
EOP-003-0, we believe that the proposal serves an important purpose in 
ensuring load-shedding plans are developed and that appropriate 
capability and authority for load shedding exists. As noted above, EPO-
003-0 raises several issues that require NERC's attention.

[[Page 64802]]

Nonetheless, the proposed Requirements set forth in EOP-003-0 are 
sufficiently clear and objective to provide guidance for compliance.
    299. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard EOP-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, the Commission 
proposes 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.
e. Disturbance Reporting (EOP-004-0)
i. NERC Proposal
    300. Proposed Reliability Standard EOP-004-0 establishes 
requirements for reporting system disturbances to the regional 
reliability organization and the ERO. It also establishes requirements 
for the analysis of these disturbances. NERC indicates that the 
Reliability Standard's purpose is to minimize the likelihood of similar 
events in the future. NERC states that EOP-004-0 is linked to DOE 
disturbance reporting requirements and Energy Information 
Administration (EIA) Form 417.
ii. Staff Preliminary Assessment
    301. Commission staff noted that EOP-004-0 does not address the 
Blackout Report's recommendation that a standing framework be 
established for conducting future blackout and disturbance 
investigations. Staff noted that the U.S. Department of Energy (DOE) 
made a presentation to the NERC Board of Trustees on preparing for an 
investigation, priority actions following a blackout, and the 
investigation process. Staff also noted that NERC has prepared a 
procedure for responding to major events that affect the bulk electric 
system. Staff indicated it believes that the DOE presentation and the 
NERC procedure provide a reasonable basis for revising EOP-004-0. In 
addition, staff noted that the Reliability Standard does not contain 
any Measures or Levels of Non-Compliance. Staff acknowledged that NERC 
has indicated this deficiency will be addressed and that the 
Reliability Standard will be resubmitted for Commission approval in 
November 2006.
iii. Comments
    302. NERC states that procedures to conduct future blackout and 
disturbance investigations should not be included in the Reliability 
Standards. NERC states that it has developed these procedures and that 
they are provided as an appendix to its proposed ERO Rules of 
Procedure.
    303. MRO supports staff's conclusion that this Reliability Standard 
does not address the Blackout Report's recommendation that a standing 
framework be established for conducting future blackout and disturbance 
investigations. MRO maintains that NERC and the DOE procedures provide 
a formal process for investigating disturbances.
iv. Commission Proposal
    304. The Commission agrees with the MRO that this Reliability 
Standard does not address the Blackout Report's Recommendation No. 14 
to establish a standing framework for conducting of future blackout and 
disturbance investigations and proposes that the Reliability Standard 
be modified to specify those requirements included in the ERO Rules of 
Procedure that apply to users, owners and operators of Bulk-Power 
System. NERC states that it has developed these procedures, and they 
are provided as an appendix to its proposed ERO Rules of Procedure. 
Although the Commission acknowledges that, under Sec.  39.2 of our 
regulations, all users, owners and operators of the Bulk-Power System 
must comply with the ERO Rules, which includes its Rules of Procedure, 
we believe that requirements outlined in these procedures that apply to 
users, owners and operators of the Bulk-Power System must be included 
in this Reliability Standard, but not the rules of procedure 
themselves, so that they become mandatory and enforceable. The 
Commission believes that including these requirements in this 
Reliability Standard will promote system reliability by ensuring that 
users, owners and operators of the Bulk-Power System provide data to 
assist NERC investigations and ensuring that the Reliability Standard 
is clear and complete. Such requirements include the provision of 
system disturbance data, voice recordings and other information 
collected during the event to support the analysis of the event after 
the fact. Therefore, we propose to direct that NERC modify EOP-004-0 to 
include 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.
    305. While the Commission has identified concerns with regard to 
EOP-004-0, we believe that the proposal serves an important purpose in 
establishing requirements for reporting and analysis of system 
disturbances. While the Commission believes that additional 
Requirements are needed, the proposed Requirements set forth in EOP-
004-0 are sufficiently clear and objective to provide guidance for 
compliance.
    306. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard EOP-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 
proposes to direct that NERC submit a modification to EOP-004-0 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.
f. System Restoration Plans (EOP-005-1)
i. NERC Proposal
    307. Proposed Reliability Standard EOP-005-1 \156\ 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.
---------------------------------------------------------------------------

    \156\ On August 28, 2006, NERC submitted EOP-005-1 for approval, 
which replaces EOP-005-0. EOP-005-1 is the same as EOP-005-0 except 
for the changes noted above. Thus, comments submitted in response to 
the Staff Preliminary Assessment on EOP-005-0 apply equally to EOP-
005-1.
---------------------------------------------------------------------------

    308. NERC's August 28, 2006 Supplemental Filing included a revised 
version of EOP-005, designated EOP-005-1. The revised Reliability 
Standard includes two new Requirements, R9 and

[[Page 64803]]

R10, and two revised requirements, R4 and R8. The new Requirement R9 
requires that the transmission operator document the cranking paths, 
including initial switching requirements, between each blackstart 
generating unit and the unit(s) to be started. The new Requirement R10 
requires the transmission operator to demonstrate through simulation or 
testing, the blackstart units can perform their intended function and 
that simulation or testing be performed at least once every five years. 
The revised Requirement R4 requires the transmission operator to 
coordinate its restoration plans with the generator owners in addition 
to others. The revised Requirement R8 requires transmission operators 
to verify that the number, size, availability, and location of system 
blackstart generating units are sufficient to meet regional reliability 
organization restoration plan requirements for the transmission 
operator's area.
ii. Staff Preliminary Assessment
    309. Staff noted that, while EOP-005-0 requires that operators be 
trained in the implementation of the restoration plan, it does not 
require this to be done periodically. In addition, the Reliability 
Standard contains Levels of Non-Compliance but no Measures. Staff noted 
that NERC has not identified this Reliability Standard as one that 
would be modified and resubmitted for Commission approval in November 
2006.
iii. Comments
    310. MRO comments that EOP-005-0 should identify the timeframes for 
operator training and restoration plan review. National Grid comments 
that the Staff Preliminary Assessment does not offer any specific time 
interval over which periodic training of operators should occur and 
that the Commission and NERC should work together to establish a 
balanced training interval when establishing requirements for periodic 
training on restoration plan procedures.
    311. Alcoa states that two Requirements of EOP-005-0 either overlap 
with or are duplicative of Requirements contained in other proposed 
Reliability Standards, in particular COM-001-0. Alcoa states that any 
overlapping or duplicative requirements that can lead to multiple 
interpretations regarding compliance which could hinder system 
reliability. Alcoa suggests that the Reliability Standard can be 
improved by defining minimum requirements relating to the periodic 
monitoring of telecommunications facilities and by giving some 
attention to the technical requirements of ``essential 
telecommunications facilities.''
    312. Alberta states that EOP-005-0 is an example of a Reliability 
Standard that should not be approved but should continue as a voluntary 
Reliability Standard unless it is determined that the Reliability 
Standard would have an adverse effect on system reliability. Alberta 
states that Requirement R1 of the Reliability Standard is missing 
elements--although it does not identify them--and lacks measurability, 
and it therefore should remain voluntary until it is revised.\157\
---------------------------------------------------------------------------

    \157\ Requirement R1 provides that ``[e]ach Transmission 
Operator shall have a restoration plan to reestablish its electric 
system in a stable and orderly manner in the event of a partial or 
total shutdown of its system, including necessary operating 
instructions and procedures to cover emergency conditions, and the 
loss of vital telecommunications channels. Each Transmission 
Operator shall include the applicable elements listed in Attachment 
1-EOP-005-0 in developing a restoration plan.''
---------------------------------------------------------------------------

iv. Commission Proposal
    313. The Commission agrees with MRO and National Grid that the 
Reliability Standard should identify time frames for training, drills 
and review of restoration plan requirements to simulate contingencies 
and prepare operators for anticipated and unforeseen events. Periodic 
training, drills and plan review is necessary to ensure that the 
Reliability Standard effectively promotes Bulk-Power System 
reliability, and specific training and review time frames will enhance 
the effectiveness of the Reliability Standard.
    314. The Commission does not agree with Alcoa that the 
telecommunication testing requirements in COM-001-0 and EOP-005-0 can 
lead to multiple interpretations regarding compliance.
    315. The Commission believes that new Requirements R9 and R10 
included in EOP-005-1 would contribute to maintaining or enhancing 
system reliability and therefore proposes to accept them.
    316. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard EOP-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 
proposes 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.
g. Reliability Coordination-System Restoration (EOP-006-0)
i. NERC Proposal
    317. Proposed Reliability Standard EOP-006-0 deals with reliability 
coordination and system restoration. 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.
ii. Staff Preliminary Assessment
    318. The Staff Preliminary Assessment noted that EOP-006-0 requires 
only that reliability coordinators, which are the highest authority 
responsible for overall system restoration, are aware of the 
restoration plan of each transmission operator in its reliability 
coordination area, but it does not require that they be involved in the 
plan's development or approval. Staff also noted that the Reliability 
Standard does not contain any Measures, metrics or processes to assess 
compliance with its requirements or any Levels of Non-Compliance. Staff 
acknowledged that NERC has indicated that the Reliability Standard will 
be modified to address these deficiencies and resubmitted for 
Commission approval in November 2006.
iii. Comments
    319. NERC states that Requirement R3 of EOP-006-0 requires the 
reliability coordinator to have an area restoration plan. NERC asserts 
that the reliability coordinator will have input into the transmission 
operators' restoration plans to ensure those plans are coordinated. 
NERC acknowledges that there may be merit in requiring reliability 
coordinators to approve the restoration plans.
    320. MRO agrees with staff in that reliability coordinators should 
be required to be involved in the development and approval of 
restoration plans. MRO supports the inclusion of Measures and Levels of 
Non-Compliance.
    321. Southern submits that the role of the reliability coordinator 
as currently established is appropriate and is consistent with the role 
of the reliability coordinator in maintaining reliability. It states 
that while the reliability coordinator should be aware of the

[[Page 64804]]

restoration plan required by the Reliability Standard, approval of that 
plan would have no clear benefit.
iv. Commission Proposal
    322. The Commission agrees with MRO and NERC that the reliability 
coordinators should be involved in the development and approval of the 
restoration plans. The reliability coordinator's position as the 
highest authority responsible for system reliability and system 
restoration justifies its involvement in the development and approval 
of these plans. The Commission thus disagrees with Southern that the 
reliability coordinator's involvement would have no clear benefit. The 
Commission proposes that the Reliability Standard be modified to 
require that the reliability coordinator be involved in the development 
and approval of restoration plans. The Commission also proposes to 
direct NERC to include Measures and Levels of Non-compliance.
    323. While the Commission has identified concerns with regard to 
EOP-006-0, we believe that the proposal serves an important purpose in 
promoting reliability coordination and system restoration. Further, the 
proposed Requirements set forth in EOP-006-0 are sufficiently clear and 
objective to provide guidance for compliance. Accordingly, giving due 
weight to the technical expertise of the ERO and with the expectation 
that the Reliability Standard will accomplish the purpose represented 
to the Commission by the ERO and that it will improve the reliability 
of the nation's Bulk-Power System, the Commission proposes to approve 
Reliability Standard EOP-006-0 as mandatory and enforceable. In 
addition, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of 
our regulations, we propose to direct that NERC submit a modification 
to EOP-006-0 that: (1) requires that the reliability coordinator be 
involved in the development and approval of restoration plans; and (2) 
includes Measures and Levels of Non-Compliance.
h. Establish, Maintain, and Document a Regional Blackstart Capability 
Plan (EOP-007-0)
i. NERC Proposal
    324. NERC states that proposed Reliability Standard 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.
ii. Staff Preliminary Assessment
    325. Staff noted in the Staff Preliminary Assessment that 
Reliability Standard EOP-007-0 lists only the regional reliability 
organization as the applicable entity and stated that the 
appropriateness of designating the regional reliability organization as 
the applicable entity is a concern in the new mandatory Reliability 
Standard structure.
iii. Comments
    326. ReliabilityFirst states that the blackstart procedures 
developed by the individual regions need to be merged to develop 
consistent procedures.
    327. EEI states that, for the most part, the Reliability Standard 
involves collection management and reporting requirements, although it 
notes that blackstart generation plans have reliability operation 
implications. MRO expresses concern that EOP-007-0 is an operating 
function rather than a Reliability Standard. MRO states that if EOP-
007-0 remains a Reliability Standard, it should be revised to require 
that operating entities have a restoration and blackstart capability 
plan, and EEI states that it should be redrawn so that compliance 
obligations are assigned directly to those entities that provide the 
data and other information. In addition, MRO states that the regional 
reliability organization should be removed as an applicable entity.
iv. Commission Proposal
    328. Consistent with our discussion in the Common Issues section 
above, the Commission will not propose to accept or remand EOP-007-0, 
as it applies only to regional reliability organizations. The 
Commission believes that, in the long-run, the Regional Entities should 
be responsible for establishing, maintaining and documenting regional 
blackstart capability plans. However, during the current period of 
transition, the regional reliability organizations should continue to 
perform this role as they have in the past.
i. Plans for Loss of Control Center Functionality (EOP-008-0)
i. NERC Proposal
    329. Proposed Reliability Standard EOP-008-0 deals with plans for 
loss of control center functionality. It requires that each reliability 
coordinator, transmission operator and balancing authority have a plan 
to continue reliable operations and to maintain situational awareness 
in the event its control center is no longer operable.
ii. Staff Preliminary Assessment
    330. Staff noted that EOP-008-0 requires the applicable entities to 
have a backup plan, but it does not specifically require that backup 
capabilities be provided. The Reliability Standard does not address 
requirements for independence from the primary control center, provide 
for prolonged operation or provide the minimum tools and facilities 
consistent with the roles, responsibilities and tasks of the different 
entities to which it applies.
iii. Comments
    331. NERC agrees with Commission staff that the proposed 
Reliability Standard does not adequately address the requirements for 
backup of critical control center functionality, and it proposes that 
such a Reliability Standard should be developed. NERC states that the 
possible solutions for providing backup of critical Bulk-Power System 
operating functionality are not limited to a redundant control center. 
Neighboring systems can provide such functionality as contracted 
services, or they can be provided through backup equipment within a 
separate existing facility.
    332. EEI supports EOP-008-000 as technically sound. It states that 
the Reliability Standard requires implementation of the plan by 
defining as a Level 4 violation a failure to implement the plan. This 
clearly establishes that backup capabilities must exist as reflected in 
the plan. According to EEI, entities must have communications 
facilities that do not rely on the primary control center; and that 
procedures must be in place for monitoring and controlling critical 
facilities, and for maintaining voice communications capability with 
other areas.\158\
---------------------------------------------------------------------------

    \158\ EEI Comments at 10.
---------------------------------------------------------------------------

    333. MRO, ReliabilityFirst and the ISO/RTO Council agree with 
staff's evaluation of EOP-008-0. MRO states that this Reliability 
Standard requires a backup plan, but does not address the requirements 
for independence from the primary control center, does not provide for 
prolonged operation, does not provide the minimum tools and facilities 
consistent with the roles, responsibilities and tasks of the different 
entities. MRO suggests that NERC should modify this Reliability 
Standard accordingly. MRO notes that today many companies simply have a 
plan and do not have an actual backup

[[Page 64805]]

facility. It states that the new requirements would have to take effect 
at some time in the future and that this Reliability Standard needs to 
make clear that the backup site should be capable of withstanding 
anticipated disasters, such as the hurricanes in Florida. 
ReliabilityFirst states that EOP-008-0 should include additional detail 
on dealing with prolonged primary control center inoperability. The 
ISO/RTO Council states that meeting the shortcomings staff identified 
in EOP-008-0 will require identification of minimum required tools and 
facilities and definition of the appropriate entities responsibilities.
iv. Commission Proposal
    334. Staff raised the concern that EOP-008-0 requires the 
applicable entities to have a backup plan, but it does not specifically 
require that backup capabilities be available. EEI comments that the 
Reliability Standard implicitly requires backup capabilities because a 
Level 4 violation occurs when an entity fails to implement such a plan. 
The Commission disagrees with EEI that such a Requirement can be 
discerned from Level 4 Non-Compliance. As we explained in our policy 
discussion in Measures and Levels of Non-Compliance, NERC has stated 
that the ``Requirements'' within a Reliability Standard define what an 
entity must do to be compliant and establish an enforceable obligation, 
and the presence or absence of Measures or Levels of Non-Compliance 
should not be the sole determining factor as to whether a Reliability 
Standard meets the statutory test for approval.
    335. Thus, the Commission believes that provision for backup 
capabilities should be an explicit Requirement. Such backup capability, 
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.\159\ The 
Commission proposes that NERC modify the standard accordingly. In 
addition to the three capability requirements identified above, the 
Commission is interested in comments from industry concerning other 
specific capabilities.
---------------------------------------------------------------------------

    \159\ Facilities examples include telecommunications, backup 
power supplies, computer systems, and security systems
---------------------------------------------------------------------------

    336. The Commission understands that backup control facilities can 
be costly but, when needed, are essential for reliability. To address 
the balance between cost and reliability benefits, there needs to be 
some flexibility on how the capability is achieved. For example, the 
mechanism to provide these capabilities may include building fully 
redundant physical back up control centers or, as NERC suggests, 
contracting back up control services or through backup equipment within 
a separate existing facility. However, the Commission proposes 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. Further, the Commission proposes to direct NERC to 
modify the standard to include a Requirement that all reliability 
coordinators have full backup control centers since they are essential 
to Bulk-Power System reliability. In addition, the Commission is 
interested in comments on what other entities should have full backup 
centers for reliability such as balancing authorities and large 
transmission operators.
    337. While the Commission has identified concerns with regard to 
EOP-008-0, we believe that the proposal serves an important purpose in 
ensuring that applicable entities have a backup plan in the case of 
loss of control center functionality. While the Commission believes 
that additional Requirements are needed, the proposed Requirements set 
forth in EOP-008-0 are sufficiently clear and objective to provide 
guidance for compliance. Accordingly, giving due weight to the 
technical expertise of the ERO and with the expectation that the 
Reliability Standard will accomplish the purpose represented to the 
Commission by the ERO and that it will improve the reliability of the 
nation's Bulk-Power System, the Commission proposes 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, we propose to direct that NERC submit a modification 
to this Reliability Standard that includes a Requirement that provides 
for backup capabilities, as described above.
j. Documentation of Blackstart Generating Unit Tests Results (EOP-009-
0)
i. NERC Proposal
    338. Proposed Reliability Standard EOP-009-0 deals with 
documentation of blackstart generating unit test results. NERC states 
that this Reliability Standard ensures that the quantity and location 
of system blackstart generators are sufficient and that these 
generators can perform their expected functions as specified in overall 
coordinated regional system restoration plans.
ii. Staff Preliminary Assessment
    339. Staff noted in the Staff Preliminary Assessment that this 
Reliability Standard requires that the start-up and operation of each 
generating blackstart unit be tested and that the results be submitted 
to the regional reliability organization. However, it does not require 
that blackstart units be periodically tested to ensure that they will 
be available when required to restore the system.
iii. Comments
    340. NERC and other commenters point out that Reliability Standard 
EOP-007-0 requires the routine testing, i.e., minimum testing of one-
third of blackstart units each year, suggested by staff.
iv. Commission Proposal
    341. The Commission is satisfied with the explanation of NERC and 
other commenters that Reliability Standard EOP-007-0 requires periodic 
testing of blackstart units.
    342. The Commission believes that the proposal serves an important 
purpose in ensuring adequate blackstart generation capability. Further 
the proposed Requirements set forth in EOP-009-0 are sufficiently clear 
and objective to provide guidance for compliance. Accordingly, the 
Commission believes that Reliability Standard EOP-009-0 is just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest; and proposes to approve it as mandatory and 
enforceable.
5. FAC: Facilities Design, Connections, Maintenance, and Transfer 
Capabilities
a. Overview
    343. The nine Facility (FAC) Reliability Standards address topics 
such as facility connection requirements, facility ratings, system 
operating limits, and transfer capabilities. The standards also 
establish requirements for maintaining equipment and rights-of-way, 
including vegetation management.
    344. How transmission local control centers are incorporated into 
the transmission operator definition will be the same as is described 
in the COM Chapter.
b. Facility Connection Requirements (FAC-001-0)
i. NERC Proposal
    345. Proposed Reliability Standard FAC-001-0 is intended to ensure 
that

[[Page 64806]]

transmission owners establish facility connection and performance 
requirements to avoid adverse impacts to the Bulk-Power System.
 ii. Staff Preliminary Assessment
    346. The Staff Preliminary Assessment did not identify any issues 
related to this Reliability Standard.
iii. Comments
    347. No specific comments were received.
iv. Commission Proposal
    348. This Reliability Standard is necessary to ensure standard 
procedures and performance assessments for new interconnection 
facilities. Further, the Requirements in FAC-001-0 are sufficiently 
clear and objective to provide guidance for compliance. Thus, the 
Commission proposes to approve Reliability Standard FAC-001-0 as just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest.
c. Coordination of Plans for New Generation, Transmission, and End-User 
Facilities (FAC-002-0)
i. NERC Proposal
    349. Proposed Reliability Standard FAC-002-0 requires that each 
generation owner, transmission owner, distribution provider, load-
serving entity, transmission planner, and planning authority assess the 
impact of integrating generation, transmission, and end-user facilities 
into the interconnected transmission system.
ii. Staff Preliminary Assessment
    350. Requirement R1 of FAC-002-0 requires system performance 
assessments in accordance with Standard TPL-001-0,\160\ which relates 
only to normal system conditions. Staff pointed out that performance 
requirements for new generation interconnection in Order No. 2003 \161\ 
require assessment for both normal and post-contingency conditions and 
is therefore more rigorous than TPL-001-0.
---------------------------------------------------------------------------

    \160\ Standard TPL-001-0 (Requirement 1 states that ``The 
Planning Authority and Transmission Planner shall each demonstrate 
through a valid assessment that its portion of the interconnected 
transmission system is planned such that, with all transmission 
facilities in service and with normal (pre-contingency) operating 
procedures in effect, the Network can be operated to supply 
projected customer demands * * *'').
    \161\ Standardization of Generator Interconnection Agreements 
and Procedures, Order No. 2003, 68 FR. 49845 (Aug. 19, 2003), FERC 
Stats. & Regs. ] 31,146 (2003), order on reh'g, Order No. 2003-A, 69 
FR 15932 at P 89 and 145 (Mar. 26, 2004), FERC Stats. & Regs. ] 
31,160 (2004), order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 
2005), FERC Stats. & Regs. ] 31,171 (2004), order on reh'g, Order 
No. 2003-C, 70 FR 37661 (June 30, 2005), FERC Stats. & Regs. ] 
31,190 (2005); see also Notice Clarifying Compliance Procedures, 106 
FERC 1,009 (2004).
---------------------------------------------------------------------------

iii. Comments
    351. NERC comments that, while the staff evaluation of FAC-002-0 is 
valid, the Reliability Standard should nonetheless be approved. NERC 
offers that it will continue to improve the Reliability Standard. 
Likewise, MRO and ISO/RTO Council agree with staff's evaluation of FAC-
002-0. MRO adds that an effort should be made to align or combine the 
requirements of Order No. 2003 and the NERC Reliability Standards into 
a single set of standards. ISO/RTO Council expresses concern that the 
Reliability Standard does not identify parties responsible for 
particular tasks, stating that it should be reviewed to ensure that 
tasks are correctly assigned.
    352. NERC and others state that Requirement R1 of FAC-002-0 should 
require not only the use of TPL-001-0, but also TPL-002-0, and TPL-003-
0. Similarly, ReliabilityFirst believes that FAC-002-0 contains an 
error in Requirement R1.4. It alleges that the requirement should have 
been translated to refer to standards TPL-001-0 through TPL-004-0 
instead of only referencing TPL-001-0. Similarly, ISO/RTO Council 
submits that Requirements R1.1 through R1.5 need to include a reference 
to standard TPL-002-0.
    353. Alcoa points out that Requirements R1.1 and R1.2 lack metrics. 
Alcoa asserts that these Requirements are broadly-worded, open-ended 
and suggest that even a small addition of facilities would compel an 
entity to comply with all of the Reliability Standards, which might not 
otherwise apply.
    354. CenterPoint contends that coordination cannot be audited with 
an objective auditable measure and recommends that this standard be 
eliminated. CenterPoint notes tradeoffs involved in planning 
interconnections for generators can put transmission service providers 
at risk for either accusation by the ERO of failing to provide adequate 
facilities or accusation by state commissions of ``gold-plating,'' or 
not performing proper generation interconnection planning. CenterPoint 
adds that although staff has discussed planning for the most onerous 
conditions, real-life application of this is more complex because it 
needs to be based on the reasoned judgment of experts considering 
particular facts as opposed to rigid standards.
    355. MEAG asserts that including distribution providers in FAC-002-
0 is unnecessarily redundant and potentially overbroad because the 
Reliability Standard should not apply to distribution providers that do 
not own generation or transmission facilities. It explains that, if a 
distribution provider owns facilities that are integral to the 
transmission system, then the distribution provider is also a 
transmission owner, according to the ``NERC glossary of Terms Used in 
Reliability Standards.'' Likewise, if a distribution provider owns 
generating facilities, then the distribution provider is a generator 
owner. However, if each load-serving entity provides the transmission 
owner with its load characteristics and the distribution provider does 
not own integral generation or transmission facilities, then MEAG 
concludes that FAC-002-0 should not apply to such distribution 
providers.
iv. Commission Proposal
    356. The Commission agrees with NERC and others that the 
Reliability Standard should refer not only to TPL-001, but also to TPL-
002-0 and TPL-003-0, which relate to loss of one or more Bulk-Power 
System elements. This would improve the technical soundness of the 
Reliability Standard by appropriately broadening the scope of system 
performance assessments to include post-contingency conditions. In 
addition, such a modification would achieve greater consistency with 
Order No. 2003. Thus, we propose to direct that NERC modify FAC-002-0 
accordingly.
    357. Requirements R1.1 and R1.2 provide that an applicable entity 
seeking to integrate generation, transmission and end-user facilities 
must perform an assessment that includes: An evaluation of the 
reliability impact of the new facilities and their connections on the 
interconnected transmission systems (R1.1) and ``ensurance of 
compliance with NERC Reliability Standards'' and other applicable 
criteria (R1.2). While we agree with Alcoa that Requirements R1.1 and 
R1.2 lack corresponding metrics, we disagree that these Requirements 
are overly-broad or open-ended. Nor do we read Requirement R1.2 as 
suggesting that even a small addition of facilities would compel an 
entity to comply with all of the Reliability Standards, which might not 
otherwise apply. Rather, we believe that the Requirements and existing 
Measures set forth in FAC-002-0 are sufficiently clear and objective to 
provide guidance for compliance.
    358. The Commission disagrees with CenterPoint's comments that 
because

[[Page 64807]]

coordination is not readily auditable, the Reliability Standard should 
be eliminated. The Reliability Standard specifies the assessments that 
must be carried out to demonstrate that facility connections meet 
reliability performance requirements. Furthermore the Reliability 
Standard specifies that the assessment studies must be jointly 
evaluated by the entities involved and that evidence of such 
coordination shall be provided. Coordination provides assurance of a 
fair, equitable and comprehensive Interconnection process, which is the 
basis for open access and is required to avoid adverse impacts on 
reliability.
    359. The Commission disagrees with MEAG's comment that the 
inclusion of distribution providers is redundant and unnecessary. The 
NERC definition clearly identifies the role of the distribution 
provider as providing the ``wires'' connecting the transmission system 
to the end use customer. FAC-002-0 has a reliability goal of avoiding 
adverse impacts on Interconnections, including a number of types of 
end-user facilities. Because the distribution provider has 
responsibility at the interface between the transmission and 
distribution system, it is proper that FAC-002-0 include Requirements 
to address those responsibilities.
    360. The Commission agrees with the ISO/RTO Council that the 
Reliability Standard does not identify functional entities responsible 
for specific tasks. The Commission understands that the roles and 
responsibilities of the transmission planner and planning authority in 
carrying out the tasks are in accordance with the definitions in the 
NERC glossary. Since the Commission has previously approved the 
division of responsibilities in various tariffs, the exact delegation 
of individual tasks is better placed in the procedures manuals than in 
the Reliability Standard.
    361. While the Commission has identified concerns with regard to 
FAC-002-0, we believe that the proposal serves an important purpose in 
ensuring that generator owners, transmission owners and end-users meet 
facility connection and performance requirements. We note that the 
Reliability Standards contains Measures and Levels of Non-Compliance. 
Further, the proposed Requirements set forth in this Reliability 
Standard are sufficiently clear and objective to provide guidance for 
compliance.
    362. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes 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.
d. Transmission Vegetation Management Program (FAC-003-1)
i. NERC Proposal
    363. NERC stated that proposed Reliability Standard 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 establish a system for uniform 
reporting of vegetation-related transmission outages. FAC-003-1 applies 
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). The Reliability 
Standard requires 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.
    364. 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 
Institute of Electrical and Electronics Engineers (IEEE) Standard 516-
2003 (IEEE Guide for Maintenance Methods on Energized Power Lines).'' 
\162\
---------------------------------------------------------------------------

    \162\ Standard FAC-003-1 (Requirement R1.2.2).
---------------------------------------------------------------------------

    365. Compliance with this standard is measured against four Levels 
of Non-Compliance. Levels 1 and 2 relate to documentation. Level 3 non-
compliance occurs if a transmission owner reports one incident of 
vegetation-related outage in a calendar year due to vegetation grow-ins 
from inside or outside the right of way. If the transmission owner 
reports more than one vegetation-related outage, then Level 4 non-
compliance has occurred.
ii. Staff Preliminary Assessment
    366. Staff expressed concern that the Reliability Standard does not 
designate maximum allowable inspection intervals but, instead, allows 
each transmission owner to define its inspection schedule and maintain 
its own program. Thus, a transmission owner cannot be faulted for the 
length of its inspection interval, provided that it has defined the 
schedule in its formal program.
    367. Staff also expressed concern with the Reliability Standard's 
development of a minimum clearance, i.e., the distance between a wire 
and the vegetation around it, based on IEEE standard 516-2003 that was 
developed with the primary purpose of enabling the performance of safe, 
energized line maintenance.\163\ IEEE 516-2003 specifies a 2.45-foot 
clearance from a live conductor for the 120 kV voltage class.\164\ 
Staff noted that this clearance is lower than that specified by 
relevant U.S. safety codes such as the ANSI Z-133 standard, which 
specifies 12-feet, 4-inches as the approach distance for the 115 kV 
voltage class.\165\
---------------------------------------------------------------------------

    \163\ Institute of Electrical and Electronics Engineers, Inc. 
Standard 516-2003, IEEE Guide for Maintenance Methods on Energized 
Power Lines at 1 (July 29, 2003) (IEEE 516-2003).
    \164\ Id. at 20.
    \165\ ANSI Z133, American National Standards Institute Standard 
for Tree Care Operations--Pruning, Trimming, Repairing, Maintaining 
and Removing Trees, and Cutting Brush--Safety Requirements.
---------------------------------------------------------------------------

    368. Staff expressed concern that use of the IEEE clearance 
provision as a basis for minimum clearance may not be appropriate, and 
adopting it for use with regular maintenance practices in vegetation 
management may be a ``lowest common denominator'' approach. In 
addition, use of IEEE Standard 516-2003 could create the unintended 
consequence that some transmission owners that currently maintain more 
stringent vegetation management programs based on standards such as the 
ANSI Z-133 may relax their practices to meet the less-stringent minimum 
requirement set forth in the NERC vegetation management standard FAC-
003-1. Staff questioned whether the Reliability Standard sufficiently 
addresses Recommendation No. 16 of the Blackout Report to establish 
``enforceable standards for maintenance of electrical clearances in 
right-of-way areas.'' \166\
---------------------------------------------------------------------------

    \166\ Blackout Report at 154.

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

[[Page 64808]]

iii. Comments
    369. NERC contends that FAC-003-1 is an excellent standard that 
sets appropriate requirements for managing vegetation in transmission 
rights-of-way. NERC and other commenters address four key issues: (1) 
Adequacy of minimum clearances; (2) the need to specify maximum 
inspection intervals; (3) no vegetation-related outage can occur 
without also violating the proposed Reliability Standard; and (4) cost 
impact of expanding the minimum clearances.
    370. Adequacy of minimum clearances: NERC explains the adoption of 
minimum clearance distances based on the standard IEEE 516-2003 is 
appropriate because, even though the standard was originally developed 
for live line workers, ``its engineering basis applies electric 
flashover physics that apply to flashover conditions between an 
energized conductor and a grounded object, such as a tree.'' \167\ NERC 
adds that the minimum clearances identified in the standard are the 
``second'' clearance requirement.\168\ In the first instance, a 
transmission owner must develop wider clearances when accounting for 
vegetation growth, line dynamics and other conditions between the times 
of tree pruning.
---------------------------------------------------------------------------

    \167\ NERC Comments at 31.
    \168\ ``Clearance 1'' is the clearance distance between 
vegetation and a transmission line to be achieved at the time of 
vegetation management work, and ``clearance 2'' is the minimum 
clearance distance between vegetation and a transmission line to be 
achieved at all times. FAC-003-1 defines ``clearance 2'' in 
Requirement R1.2.2 as ``The Transmission Owner shall determine and 
document specific radial clearances to be maintained between 
vegetation and conductors under all rated electrical operating 
conditions. These minimum clearance distances are necessary to 
prevent flashover between vegetation and conductors and will vary 
due to such factors as altitude and operating voltages. These 
Transmission Owner-specific minimum clearance distances shall be no 
less than those set forth in the [IEEE] Standard 516-2003 * * * and 
as specified in its Section 4.2.2.3, Minimum Air Insulation 
Distances without Tolls in the Air Gap.''
---------------------------------------------------------------------------

    371. Similar to NERC's view on the adequacy of minimum clearances, 
several commenters argue that the IEEE 516-2003 standard is an 
appropriate standard for use in FAC-003-1.\169\ Southern indicates that 
full compliance with this standard would help to ensure line 
reliability consistent with the purposes of this standard and therefore 
believes the use of the IEEE standard is appropriate for use as a 
minimum acceptable clearance in this context. CenterPoint states that 
``clearance 2,'' i.e., the minimum distance in FAC-003-1, must be 
maintained under all rated electrical operating conditions and must 
consider additional clearance for the dynamic movement of the 
transmission conductors to avoid vegetation related outages. According 
to CenterPoint, the derived values from the IEEE table serve only as a 
theoretical minimum for static situations.
---------------------------------------------------------------------------

    \169\ E.g., EEI, Mid-American, National Grid, NRECA, PG&E, and 
Southern.
---------------------------------------------------------------------------

    372. Conversely, ReliabilityFirst submits that it agrees with 
staff's evaluation of standard FAC-003-1 regarding the appropriateness 
of using the IEEE standard. SCE believes that the adoption of IEEE 516-
2003 in FAC-003-1 to establish ``specific radial clearances to be 
maintained between vegetation and conductors under all rated electrical 
operating conditions'' is wholly inappropriate when determining minimum 
tree-to-line clearances. SCE states that no scientific evidence was 
ever presented or cited during the NERC standard development process 
that demonstrated vegetation represented a greater or equal flash-over 
hazard in comparison to the human body (i.e., a qualified electrical 
worker) when placed in proximity to transmission lines. SCE recommends 
that NERC establish a new minimum clearance for transmission lines 
operated at 200 kV and above and that studies be conducted so that 
these new minimum clearances be based on real-world knowledge and line 
clearing expertise, as opposed to simply appropriating standards that 
were designed for other situations.
    373. Inspection Cycle: With regard to a maximum allowable 
inspection cycle, NERC believes FAC-003-1 appropriately provides 
discretion to transmission owners to develop vegetation inspection 
cycles appropriate for their respective systems. Several commenters 
argue that staff's concern that FAC-003-1 does not designate maximum 
allowable inspection intervals fails to recognize varying types of 
vegetation, growth rates and climates throughout North America.\170\ 
Some commenters consider staff's comment on maximum allowable 
inspection intervals as a ``one size fits all'' approach to vegetation 
management and advise that such an approach to inspection intervals 
could result in the lowest common denominator among all regions 
throughout the country or unfairly punish or financially burden certain 
regions. Allegheny proposes as an alternative that maximum inspection 
intervals could vary between Regional Entities and notes that there 
might need to be variations of the maximum interval within a Regional 
Entity that is geographically diverse.
---------------------------------------------------------------------------

    \170\ E.g., Allegheny, CenterPoint, EEI, MRO, National Grid, 
NRECA, NYSPUC, SCE, and Southern.
---------------------------------------------------------------------------

    374. Performance measure: NERC states that no vegetation-related 
transmission line outage can occur without also being a violation of 
the standard. NERC expresses the view that, if such outages do occur, 
the transmission owner has violated the standard, and the solution is 
to engage in compliance enforcement actions rather than developing a 
wider margin of clearance. Several commenters concur with NERC on this 
point and assert that staff's concerns with regard to maximum 
inspection intervals and minimum clearances would not be an issue if a 
vegetation management standard measured and used performance as a 
metric.\171\ Southern points out that FAC-003-1 utilizes outage 
reporting to measure the effectiveness of an entity's vegetation 
management program and suggests that the performance metric will expose 
the standard's shortcomings which can then be addressed through a 
revision of the standard.
---------------------------------------------------------------------------

    \171\ E.g., CenterPoint, National Grid, ISO/RTO Council and 
Southern.
---------------------------------------------------------------------------

    375. Cost of compliance: Finally, NERC and others express concern 
that expanding the minimum clearances could increase workload and costs 
yet not provide any added reliability benefit. Regarding the issue on 
increased costs to maintain greater minimum clearances versus 
reliability benefits, EEI points out that ``flexibility written into 
the standard recognizes that fixed clearance distances will not provide 
stronger protection of the grid, and are certain to cause significant 
additional costs,'' yet recognizes the need to prevent cost-based 
incentives which might drive the Reliability Standard toward a lowest 
common denominator.\172\
---------------------------------------------------------------------------

    \172\ EEI Comments at 8.
---------------------------------------------------------------------------

    376. USDA Forest Service expresses concern with regard to the 
manner in which the requirements of EPAct 2005 are being applied. In 
particular, utilities are submitting vegetation management standards to 
the Commission for use on National Forest System lands that were not 
first approved by the USDA Forest Service. It adds that it objects to 
any process that allows a utility to set its own new vegetation 
management standards independently and to any interpretation of EPAct 
2005 that would diminish the USDA Forest Service's authority to approve 
new vegetation management standards on Forest Service lands.

[[Page 64809]]

iv. Commission Proposal
    377. Giving due weight to the technical expertise of the ERO and 
with the expectation that the Reliability Standard will accomplish the 
purpose represented to the Commission by the ERO and that it will 
improve the reliability of the nation's Bulk-Power System, the 
Commission proposes to approve Reliability Standard FAC-003-1. In 
addition, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of 
our regulations, the Commission proposes to modify the Reliability 
Standard, as discussed below.
(a) Adequacy of Minimum Clearances
    378. NERC and others support the proposed minimum ``clearance 2'' 
distances based on IEEE 516-2003 as appropriate for use in vegetation 
management. The Commission believes that clearance distances need to 
exceed IEEE 516-2003's requirements in many circumstances, but should 
never be less than these requirements. The Commission is concerned that 
the application of the IEEE requirement without consideration of 
specific circumstances may result in flashovers, and this possibility 
appears to be addressed in IEEE 516-2003 and the vegetation management 
standard. Specifically, FAC-003-1 provides that a transmission owner 
must ``identify and document clearances between vegetation and 
[conductors] taking into consideration transmission line voltage, the 
effects of ambient temperature on conductor sag under maximum design 
loading, and the effects of wind velocities on conductor sway.'' \173\ 
In addition, the Reliability Standard provides:
---------------------------------------------------------------------------

    \173\ FAC-003-1, Requirement R1.2.

    The Transmission Owner shall determine and document specific 
radial clearances to be maintained between vegetation and conductors 
under all rated electrical operating conditions. These minimum 
clearance distances are necessary to prevent flashover between 
vegetation and conductors and will vary due to such factors as 
altitude and operating voltages.'' \174\
---------------------------------------------------------------------------

    \174\ FAC-003-1, Requirement R1.2.2 (emphasis added).

    379. Consistent with the notion that the minimum clearance may vary 
due to various factors, NERC states that the transmission owners must 
develop wider clearances when accounting for vegetation growth, line 
dynamics and other conditions between the times of tree pruning.\175\ 
In addition, IEEE 516-2003 makes clear that the stated minimum 
clearances are based on ``standard'' atmospheric conditions and ``if 
standard atmospheric conditions do not exist, extra care must be 
taken.'' \176\
---------------------------------------------------------------------------

    \175\ NERC Comments at 32.
    \176\ IEEE 516-2003 at 20. Further, IEEE 516-2003 defines 
``standard atmospheric conditions'' as temperatures above freezing, 
wind less than 24 kilometer per hour, unsaturated air, normal 
barometer, uncontaminated air, and clean and dry insulators.''
---------------------------------------------------------------------------

    380. NERC's comments, IEEE 516-2003, and the vegetation management 
standard itself all make clear that the minimum ``clearance 2'' 
distances based on IEEE 516-2003 are adequate in some, but not all, 
circumstances. The minimum clearances that a transmission owner must 
identify and document depend on a variety of conditions including, but 
not limited to, transmission line voltage, temperature, wind 
velocities, altitude. 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.\177\
---------------------------------------------------------------------------

    \177\ Nothing in this Reliability Standard should be interpreted 
as preempting the authority and responsibility of the states to set 
and enforce minimum clearances, such as those delineated in the 
National Electric Safety Code, to protect the safety of the public.
---------------------------------------------------------------------------

    381. In response to the USDA Forest Service's comments, we believe 
that any potential issues regarding minimum clearances on National 
Forest Service lands should be dealt with on a case-by-case basis. The 
Commission seeks comments whether another approach would be more 
appropriate.
(b) Inspection Intervals
    382. NERC and other commenters believe FAC-003-1 appropriately 
provides discretion to transmission owners to develop vegetation 
inspection cycles appropriate for their respective systems. While the 
Commission recognizes that some variation in inspection cycles would be 
appropriate based on climate and other factors, we are concerned that 
the complete discretion left to the transmission owners in determining 
inspection cycles limits the effectiveness of the Reliability Standard.
    383. While the Commission will not dictate a specific minimum 
vegetation inspection cycle, based on data provided by transmission 
owners to the Commission in 2004 as part of the Commission's vegetation 
management survey, it appears that a one-year vegetation inspection 
cycle is reasonable.\178\ According to the Vegetation Management 
Report, 76 of 161 entities surveyed conduct ground inspections once a 
year.\179\ This indicates that a one-year vegetation inspection cycle 
is the ``norm'' for the industry, but not a lowest common denominator 
that sets a standard less stringent than the industry practice. While 
the Commission will not dictate a minimum vegetation inspection cycle, 
we do believe that it is important that the ERO develop a minimum 
requirement as a ``backstop'' to assure that transmission owners 
conduct inspections at a reasonable interval. Accordingly, we propose 
to direct that the ERO modify the Reliability Standard to establish a 
minimum vegetation inspection cycle.
---------------------------------------------------------------------------

    \178\ The data provided in the survey was used to prepare a 
report to Congress, Federal Energy Regulatory Commission, Utility 
Vegetation Management and Bulk Electric Reliability Report, 
(September 7, 2004) (Vegetation Management Report).
    \179\ Id. at 11. The Vegetation Management Report indicates that 
29 entities conduct ground inspections semi-annually or more 
frequently, 37 entities inspect less frequently than annually, 12 
inspect on an ``as needed'' basis, and seven entities did not report 
on their inspection cycle.
---------------------------------------------------------------------------

    384. Further, as mentioned above, the Commission believes that some 
variation to a continent-wide, one year minimum cycle should be allowed 
due to physical differences such as climate and species of vegetation. 
Appropriate variations may be determined on a regional basis, with FAC-
003-1 providing a continent-wide ``backstop.'' Alternatively, the 
continent-wide standard could specify a one-year minimum inspection 
cycle, and provide that exemptions would be granted by the ERO for 
legitimate physical differences. The most appropriate approach could be 
determined in the ERO Reliability Standard development process.
    385. The applicability of FAC-003-1 currently states that it 
applies 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 reliability. 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, we are concerned that this approach will not 
result in the inclusion of all transmission lines that could impact 
Bulk Power System reliability. Accordingly, the Commission proposes to 
direct NERC to change the applicability of FAC-003-1 so that it applies 
to Bulk-Power System transmission lines that have an impact of 
reliability as determined by the ERO.
    386. While we have expressed some concerns regarding FAC-003-1, we

[[Page 64810]]

believe that it serves an important goal of improving the reliability 
of the Bulk-Power System by preventing outages from vegetation. 
Further, with our interpretation above regarding minimum clearances, 
the Commission believes that the proposed Requirements set forth in 
FAC-003-1 are sufficiently clear and objective to provide guidance for 
compliance.
    387. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard FAC-003-1. 
Further, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of 
our regulations, we propose to direct that NERC submit a modification 
to FAC-003-1 that: (1) The ERO develop a minimum vegetation inspection 
cycle that allows variation for physical differences, as discussed 
above; and (2) removes the 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 of reliability as 
determined by the ERO.
e. Methodologies for Determining Electrical Facilities (FAC-004-0) and 
Electrical Facility Ratings for System Modeling (FAC-005-0)
    388. NERC's August 28, 2006 Supplemental Filing states that 
Reliability Standards FAC-004-0 and FAC-005-0 were filed for approval 
on April 4, 2006, but have been superseded by FAC-008-1 and FAC-009-1, 
respectively. NERC has withdrawn its request for approval of FAC-004-0 
and FAC-005-0. Thus, the Commission will not address them in this 
notice of proposed rulemaking.
f. Facility Ratings Methodology (FAC-008-1)
i. NERC Proposal
    389. The stated purpose of FAC-008-1 is to ensure that facility 
ratings used in the reliable planning and operation of the bulk 
electric system are determined based on an established methodology. It 
requires that each transmission owner and generation owner develop a 
facility rating methodology for their facilities, which should consider 
manufacturing data; design criteria (such as IEEE, ANSI and other 
industry standards); 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.
ii. Staff Preliminary Assessment
    390. Staff noted that this Reliability Standard does not establish 
or require a uniform or consistent set of methodologies, which has 
resulted in different ratings for the same equipment under the same 
conditions in the same region. Rather, it only requires an equipment 
owner to document the methodology it chooses to use. Thus, staff was 
concerned that FAC-008-1 does not appear to address Recommendation No. 
27 of the Blackout Report that NERC develop ``clear, unambiguous 
requirements for the calculation of transmission line ratings.'' \180\
---------------------------------------------------------------------------

    \180\ Blackout Report at 162.
---------------------------------------------------------------------------

iii. Comments
    391. NERC comments that strengthening the consistency of the 
underlying assumptions and methods used to determine the ratings of 
facilities could improve the standard; however, NERC cautions that a 
single, uniform method for ratings calculations will not be practical 
or effective. This concern is echoed by ReliabilityFirst. NERC explains 
that the rating of facilities is very complex, beginning with the fact 
that each physical device has its own unique design criteria and 
limitations, which are incorporated into the device's warranty. The 
facility owner risks voiding the warranty or damaging the physical 
device if it is operated outside of the manufacturer ratings. The 
second consideration is the configuration of the equipment within the 
power system. A facility owner examines the equipments' limitations and 
uses engineering judgment to apply a variety of assumptions and 
practices in creating the design criteria for operational facilities. 
NERC agrees that it is at this step where practices could be more 
consistent. However, it adds that differences in assumptions and 
practices arise from site-specific characteristics such as climate 
conditions, local equipment safety codes, or life expectancy of the 
equipment, and that when the standards were developed, participants 
strongly agreed that uniform methods were not appropriate or feasible.
    392. NERC points out that there are trade-offs to uniform ratings 
methods. Currently, a facility owner assumes a business risk associated 
with the assumptions used in the rating of facilities because the 
facility owner has invested in the equipment and is responsible for 
maintaining the warranty, the equipment's performance, and ultimately 
replacement costs. If ratings are uniform and outside a facility 
owner's control, NERC questions who would be responsible for equipment 
failures. Uniform rating methods might also lead to a reduction in 
limits on facilities and, consequently, reduced capacity of the 
transmission network. Several commenters, including NERC, agree with 
staff that regardless of how ratings are developed, jointly-owned 
facilities must use the same ratings.
    393. Allegheny disagrees with staff's evaluation of standard FAC-
008. It comments that the industry does not consider the absence of a 
standard methodology for determining facility ratings a threat to the 
reliability of the transmission grid and that the establishment of a 
uniform standard will be a massive and costly undertaking. Allegheny 
explains that, historically, generator owners and transmission owners 
rely on manufacturer-provided equipment ratings, in conjunction with 
their respective business practices, to ensure consistent documentation 
and application of ratings to ensure reliability. Further, monitoring 
by regional organizations has also ensured that generator and 
transmission owners' practices address reliability concerns. In light 
of this, Allegheny advocates that staff's recommendations not be 
adopted without further demonstration that the benefits justify the 
cost.
    394. PG&E asserts that FAC-008-1 appropriately balances the need 
for consistent facility ratings with the realities of the transmission 
system and that a single line rating methodology for all of North 
America is neither practical nor advisable. It explains that the 
Reliability Standard properly places the responsibility of determining 
facility ratings with the facility owners. PG&E believes the 
Reliability Standard's disclosure requirement safeguards against 
manipulation of facility ratings.
    395. Mid-American and MRO agree that a consistent methodology 
should be established for equipment rating. Mid-American believes that 
the standard should encourage a consistent methodology for calculating 
equipment ratings, ensure transmission customers of nondiscriminatory 
treatment without being overly burdensome to the facility owner, and 
must address all factors that affect equipment ratings. However, Mid-
American does not support an overly-prescriptive standard. It suggests 
that staff's concerns should be directed at

[[Page 64811]]

ensuring consistent methodologies for rating development, however, 
points out that a consistent methodology may still result in differing 
numerical ratings due to differing ambient temperatures, sag 
conditions, etc., that may exist in differing regions. While supporting 
staff's recommendation for a consistent methodology, MRO disagrees with 
staff's approach. Transmission owners should be able to set facility 
ratings as they see fit, provided the rating is communicated to others 
and the transmission owners operate with the same rating.
    396. National Grid comments that it supports some measure of 
standardization of equipment rating methodologies. It explains that, 
``if left entirely to the asset owners, the lack of uniform equipment 
rating methodologies leaves open the possibility in some circumstances 
that the determination of facility ratings can be used by an asset 
owner to gain a market edge over other market participants that do not 
own assets.'' \181\ National Grid encourages the standardization of 
facility ratings only at a conceptual level, though not necessarily the 
standardization of specific parameters, recognizing regional climatic 
and topological conditions.
---------------------------------------------------------------------------

    \181\ National Grid Comments at 19.
---------------------------------------------------------------------------

    397. CenterPoint contends that Reliability Standards FAC-004-0, 
FAC-005-0, FAC-008-1 and FAC-009-1 are not necessary and should be 
rejected. It explains that Blackout Report Recommendation No. 27 does 
not require a uniform set of methodologies for rating facilities, but 
instead only recommends that there be clear, unambiguous requirements 
to rate transmission lines. According to CenterPoint, most if not all 
utilities follow a standard IEEE method for rating transmission lines.
    398. The Valley Group proposes that the fastest and most efficient 
way to fulfill Blackout Report Recommendation No. 27 would be the 
adoption of the principles of the International Council on Large 
Electric Systems (CIGRE)/IEEE Guide and the necessary procedures for 
enforcement. The Valley Group cites survey data indicating that a large 
percentage of utilities have increased their facility ratings by 
changing certain ratings assumptions, most commonly by increasing the 
assumed wind speed. It views this as a dangerous trend because system 
loads have generally increased during the same period. It also sees the 
regional adoption of assumptions being based on utilities with the 
least conservative practices, leading to a ``lowest common 
denominator'' result. To correct this problem, the Valley Group 
encourages adoption of IEEE/CIGRE guidelines for selection of weather 
parameters.\182\
---------------------------------------------------------------------------

    \182\ The Valley Group cites a CIGRE Technical Brochure entitled 
Guide for Selection of Weather Parameters for Overhead Bare 
Conductor Ratings published in August 2006 and a CIGRE/IEEE 
Tutorial, which was presented in June 2006.
---------------------------------------------------------------------------

    399. Alcoa agrees with staff's evaluation of the facility 
Reliability Standards. It adds that, without a clear set of 
straightforward methodologies for facility ratings, the proposed 
documentation requirements are unduly burdensome. Alcoa suggests that 
the ERO propose methodologies that consider the relative importance to 
the reliability of the Bulk-Power System, as well as the ability of the 
owner of the facilities to pass on the costs incurred to enhance 
reliability to those receiving the benefit.
iv. Commission Proposal
    400. The Commission proposes to approve FAC-008-1 as mandatory and 
enforceable. In addition, we propose directing that NERC develop 
modifications to the Reliability Standard, as discussed below.
    401. The Commission agrees with NERC and others that the 
assumptions used in the methodologies can not be standardized. The 
assumptions are essentially input variables into rating methodologies 
used to convert the input into the normal and emergency ratings of the 
facilities. Owners will use the actual topology and substation 
arrangement of the facilities in configuring equipment for facility 
ratings. There should be different input variables such as the ambient 
temperatures in Texas as compared to Maine. Thus, we are not proposing 
to require a ``uniform method of ratings calculation,'' which would 
standardize the input assumptions in the formula for calculating 
ratings.
    402. On the other hand, the Commission disagrees with MRO that 
transmission owners ``should set the rating as they see fit, provided 
that everyone knows what the rating is and that rating is used for all 
purposes including the Transmission Owner's use of the facilities.'' 
\183\ As explained by National Grid, allowing facility owners to set 
ratings ``as they see fit'' could result in the use of a facility 
rating determination to gain a competitive advantage over other market 
participants that do not own assets. This could harm the reliability of 
the transmission grid and can also impact competition as described by 
National Grid. Likewise, the Valley Group raises legitimate concerns 
about manipulation of the assumptions, in particular wind speed, 
demonstrating the need not only for uniformity, but for oversight as 
well.
---------------------------------------------------------------------------

    \183\ MRO Comments at 8.
---------------------------------------------------------------------------

    403. The Commission believes that, to address the concerns of 
National Grid, Valley Group and others, the Reliability Standard could 
be improved in two ways. First, we propose that the different 
assumptions that are the basis for the input variables should be 
documented and made available for review by other users, owners and 
operators of the Bulk-Power System. Currently, only a subset of 
functional entities responsible for the facilities in a specific area 
are able to view this information. The added transparency that we 
propose would allow customers, regulators and other affected users, 
owners and operators of the Bulk-Power System to understand how a 
facility owner sets its facility ratings.
    404. Second, asset owners use various methods for calculating 
ratings that are widely accepted throughout the industry, such as IEEE 
and CIGRE, to calculate transmission line conductor ratings. 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.
    405. Further, consistent with NERC's comments,\184\ the Commission 
proposes that the limiting component(s) be identified and that the 
increase in rating based on the next limiting component(s) be defined 
for all critical facilities, including facilities that limit TTC, limit 
delivery of generation to load, or bottle generation. This would 
provide additional transparency and sufficient information so that the 
most cost effective solutions to increase facility ratings can be 
identified. For example, if a specific transmission line is limited by 
the relay settings or protective relay system, ordinarily the line 
could be ``up rated'' for a relatively modest cost. As a second 
example, if a line is limited by the sag of one particular span, 
modifying the tension in that span, even if it requires reinforcing a 
few towers, may result in significant increases in capability at 
relatively low cost. Such information would be useful to users of the 
Bulk-Power System and to the Commission.
---------------------------------------------------------------------------

    \184\ See NERC Comments at 61.
---------------------------------------------------------------------------

    406. CenterPoint has not provided a compelling reason for us to 
reject this Reliability Standard. Assuming CenterPoint is correct that 
most, if not all, utilities follow a standard method for rating 
transmission lines, that fact

[[Page 64812]]

does not obviate the need for mandatory and enforceable Reliability 
Standards that require clear, ambiguous requirements to rate 
transmission lines. Moreover, industry use of a standard line rating 
method may be a result of the Reliability Standard, which requires 
facility owners to consider industry rating practices such as IEEE. 
Moreover, the Reliability Standards include ratings for all facilities, 
not just transmission lines.
    407. FAC-008-1 makes considerable progress in addressing Blackout 
Report Recommendation No. 27, which as noted above recommends that NERC 
develop clear and unambiguous requirements for the calculation of 
transmission line ratings. While the Commission has identified ways to 
improve and strengthen this Reliability Standard, we believe that the 
proposal serves an important purpose in ensuring that facility ratings 
are determined based on an established methodology. Further, the 
Commission believes that the proposed Requirements set forth in FAC-
008-1 are sufficiently clear and objective to provide guidance for 
compliance.
    408. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC submit a modification to FAC-008-1 that 
requires transmission and generation facility owners to: (1) Document 
underlying assumptions and methods used to determine normal and 
emergency facility ratings; and (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 for all 
critical facilities the increase in rating based on the next limiting 
component(s).
g. Establish and Communicate Facility Ratings (FAC-009-1)
i. NERC Proposal
    409. The stated Purpose of FAC-009-1 is to ensure that facility 
ratings are determined based on an established methodology. It requires 
each transmission owner and generation owner to establish facility 
ratings consistent with their associated facility ratings methodology 
and provide those ratings to their reliability coordinator, 
transmission operator, transmission planner, and planning authority.
ii. Staff Preliminary Assessment
    410. The Staff Preliminary Assessment did not identify any issues 
related to this Reliability Standard.
iii. Comments
    411. ReliabilityFirst agrees with staff's evaluation that FAC-009-1 
does not contain any substantive issues.
iv. Commission Proposal
    412. 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 proposes to approve Reliability 
Standard FAC-009-1 (Establish and Communicate Facility Ratings) as 
just, reasonable, not unduly discriminatory or preferential, and in the 
public interest.
h. Transfer Capability Methodology (FAC-012-1)
i. NERC Proposal
    413. Proposed Reliability Standard FAC-012-1 requires each 
reliability coordinator and planning authority to document their 
methodology used to develop 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.
ii. Staff Preliminary Assessment
    414. Staff noted that a move toward standardization of the inter-
regional and intra-regional transfer capability may be desirable to 
ensure an adequate level of reliability and minimize undue negative 
impact on competition.
iii. Comments
    415. Responding to staff's suggested move toward standardization, 
MRO comments that the Reliability Standards should recognize the 
differences in geographical diversity, as well as relative population 
size, to maintain reliability. A single approach is desirable, but it 
should provide the flexibility to adjust for technical realities within 
a given part of the Eastern Interconnection. It explains that the 
assumptions underlying methodologies for determining inter-regional and 
intra-regional transfer capabilities may vary for different regions of 
the Eastern Interconnection due to geography, system design, weather, 
or state-specific requirements. Transparency in the approach and 
assumptions is essential.
    416. PG&E comments that the inherent differences in the development 
of the transmission infrastructure between the Eastern Interconnection 
and the Western Interconnection weigh against the imposition of a 
single methodology. Because transmission lines tend to be located in 
common corridors in the Western Interconnection, efficiency and 
reliability are maximized by transfer capabilities calculated with 
consideration of selected multiple contingencies to account for the 
multiplicity of potential credible events.
    417. CenterPoint proposes that FAC-012-1 be consolidated with FAC-
013-1. Further, it advocates that, because the ERCOT region operates as 
a single control area and thus does not have transfers between control 
areas, the NERC transfer capability methodology is not used, nor should 
it be.
iv. Commission Proposal
    418. As 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.'' Accordingly, the 
Commission will not propose to accept or remand this Reliability 
Standard, until the regional procedures are submitted. In the interim, 
compliance with FAC-012-1 should continue on its current basis, and the 
Commission considers compliance with the Reliability Standard to be a 
matter of good utility practice.
    419. Although we do not propose any action with regard to FAC-012-1 
at this time, we address comments and our additional concerns regarding 
this Reliability Standard below.
    420. We agree with MRO and PG&E that different regions or 
Interconnections may have different geography, population size, or 
transmission structure that necessitate different approaches to 
transfer capability, and we have noted that the Requirement R1.3 
addresses issues such as transmission system topology and current and 
projected use of transmission system for reliability margin but not for 
transfer capability calculation. FAC-012-1 only requires

[[Page 64813]]

that the regional reliability organization provide documentation on 
transfer capability methodology and provide this documentation to 
entities such as 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.\185\ We believe that this Reliability Standard should, 
as a minimum, provide a framework for the transfer capability 
calculation methodology including data inputs, and modeling 
assumptions. We seek comments on the most efficient way to make the 
above information transparent for all participants.
---------------------------------------------------------------------------

    \185\ Path rating process in WECC and various regional transfer 
capability methodologies in the Eastern interconnection.
---------------------------------------------------------------------------

    421. With regard to CenterPoint's comment, while FAC-012, which 
pertains to the documentation of transfer capability methodologies, and 
FAC-013, which pertains to the establishment of transfer capabilities 
consistent with the methodology, are related, we leave it to NERC's 
discretion whether they should be consolidated. As we have mentioned 
elsewhere, CenterPoint's suggestion that the Reliability Standard not 
apply to the ERCOT region must be submitted by NERC as a regional 
difference.
i. Establish and Communicate Transfer Capability (FAC-013-1)
i. NERC Proposal
    422. Proposed Reliability Standard FAC-013-1 requires each 
reliability coordinator and planning authority to calculate transfer 
capabilities consistent with its transfer capability methodology and 
provide those capabilities to its transmission operators, transmission 
service providers, and planning authorities.
ii. Staff Preliminary Assessment
    423. The Staff Preliminary Assessment did not identify any issues 
related to this Reliability Standard.
iii. Comments
    424. ReliabilityFirst agrees with staff's evaluation that FAC-013-1 
does not contain any substantive issues.
iv. Commission Proposal
    425. The Commission's concern about this Reliability Standard is 
related to the applicability. The Reliability Standard currently states 
that it is applicable to a reliability coordinator (as required by its 
regional reliability organization), and a planning authority (as 
required by its regional reliability organization). The Commission 
believes that the Reliability Standard should be applicable to all 
Reliability Coordinators. A planning authority may also have a role in 
determining transfer capabilities, however, the regional reliability 
organization should not be the entity that makes this determination.
    426. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC submit 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.
6. INT: Interchange Scheduling and Coordination
a. Overview
    427. The Interchange Scheduling and Coordination (INT) group of 
Reliability Standards addresses the process of Interchange 
Transactions, which occur when electricity is purchased and transmitted 
from a seller to a buyer across the power grid.\186\ Specific 
information regarding each transaction must be identified in an 
electronic label, known as a ``Tag,'' which is used by an affected 
reliability coordinator, transmission service provider or balancing 
authority to assess the transaction for reliability impacts. In 
addition, communication, submission, assessment and approval of a Tag 
must be completed for reliability consideration before implementation 
of the transaction.
---------------------------------------------------------------------------

    \186\ NERC glossary at 8 defines ``Transaction'' as ``[a]n 
agreement to transfer energy from a seller to a buyer that crosses 
one or more Balancing Authority Area boundaries.''
---------------------------------------------------------------------------

    428. In its April 4, 2006 Petition, NERC submitted four Version 0 
interchange Reliability Standards, INT-001-0 through INT-004-0. In its 
August 28, 2006 Supplemental Filing, NERC submitted nine Version 1 
proposed Reliability Standards in the INT group.\187\ Reliability 
Standards INT-001-1, INT-003-1 and INT-004-1 replace the corresponding 
Version 0 standards although, as discussed later on, the language of 
some Requirements have been modified and other Requirements have been 
transferred elsewhere. NERC states that Reliability Standard INT-002-0 
is being retired, effective January 1, 2007 and asked that it be 
withdrawn for Commission review. Reliability Standards INT-005-1 
through INT-010-1 are new to the Version 1 Reliability Standards.
---------------------------------------------------------------------------

    \187\ INT-001-1, INT-003-1, INT-004-1, INT-005-1, INT-006-1, 
INT-007-1, INT-008-1, INT-009-1, INT-010-1.
---------------------------------------------------------------------------

i. General Comments
    429. CenterPoint comments that the INT group of proposed 
Reliability Standards should be rejected because Reliability Standards 
that attempt to create auditable requirements to measure 
``coordination'' cannot realistically be implemented and are 
unnecessary appendages to Reliability Standards addressing the actual 
goal of ensuring reliable operation. CenterPoint also contends that, if 
the Commission approves the INT group of Reliability Standards, ERCOT 
should be explicitly exempted from them because interchange tagging is 
not used in ERCOT.
    430. ReliabilityFirst comments generally on the INT group of 
Reliability Standards. It states that the development of missing 
compliance elements by NERC's drafting team must be expedited and that 
it may be necessary to supplement the team with additional experts if 
it is necessary to expand and/or detail requirements in these 
Reliability Standards.
ii. Commission Proposal
    431. Order No. 672 explains that a Reliability Standard must be 
designed to achieve a specified reliability goal.\188\ The goal of the 
INT group of Reliability Standards is not simply to measure 
coordination as CenterPoint contends. Rather, these Reliability 
Standards are intended to ensure that uses of the Bulk-Power System are 
known to operating entities and reliability coordinators sufficiently 
in advance to permit them to evaluate reliability impacts and curtail 
transactions in the event system parameters approach their operating 
limits.\189\ In our view, the INT group of Reliability Standards is 
designed to achieve a specified goal that is important to maintaining 
Bulk-Power System reliability. Accordingly, the Commission disagrees 
with CenterPoint

[[Page 64814]]

that the INT group of Reliability Standards should be rejected.
---------------------------------------------------------------------------

    \188\ Order No. 672 at P 324.
    \189\ NERC Petition at 40-41.
---------------------------------------------------------------------------

    432. With regard to CenterPoint's suggestion that ERCOT be 
explicitly exempted from the INT group of Reliability Standards, we 
note that NERC has not proposed such an exemption as a regional 
difference. Order No. 672 makes clear that a proposed Reliability 
Standard, including a modification or regional difference to a 
Reliability Standard, must be submitted by the ERO to the Commission 
for our consideration.\190\ Accordingly, we will not consider such an 
exemption unless submitted by NERC for our review.
---------------------------------------------------------------------------

    \190\ Order No. 672 at P 249.
---------------------------------------------------------------------------

    433. With regard to ReliabilityFirst's comment, we agree that the 
development of missing compliance elements is an important priority and 
note that NERC has stated that it plans to submit a filing in November 
2006 that will include many such missing compliance elements. NERC 
staffing of the team assigned to develop missing compliance elements is 
a matter beyond the scope of this proceeding.
b. Interchange Information (INT-001-1)
i. NERC Proposal
    434. NERC states that the purpose of INT-001-1 is to ensure that 
interchange information is submitted to the reliability analysis 
service identified by NERC.\191\ Proposed Reliability Standard INT-001-
1 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.\192\ The Requirements 
apply to all dynamic schedules, delivery from a jointly owned generator 
and bilateral inadvertent interchange payback.
---------------------------------------------------------------------------

    \191\ Currently, the reliability analysis service used by NERC 
is the Interchange Distribution Calculator.
    \192\ NERC's Glossary of Terms adopted by NERC's Board of 
Trustees on August 2, 2006 defines Interchange as ``Energy transfers 
that cross Balancing Authority boundaries.''
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    435. Staff noted that INT-001-0 has only one Measure and no Levels 
of Non-Compliance. The Version 1 standard, INT-001-1, would delete the 
one Measure and, thus, would contain no Measures or Levels of Non-
Compliance.
iii. Comments
    436. ISO/RTO Council generally agrees with staff that INT-001-0 
lacks sufficient compliance measures. Allegheny, in contrast, comments 
that tagging deadlines within the Reliability Standard provide an 
adequate measure of compliance.
iv. Commission Proposal
    437. The Commission proposes to approve INT-001-1 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    438. Requirement R1.2 in INT-001-0 (the Version 0 standard) 
requires data submission on all point-to-point transfers entirely 
within a balancing authority area, including ``all grandfathered and 
'non-Order 888' Point-to-Point Transmission Service.'' This Requirement 
to submit data for grandfathered and non-Order 888 point-to-point 
transmission service is not included in INT-001-1 or any other Version 
1 Reliability Standard in the INT group. These transactions, if not 
reported, will create a gap in reliability assessment and transaction 
curtailment provisions and may result in adverse impact on reliable 
operation of the Interconnection. Therefore, the Commission proposes to 
direct that NERC retain this important Requirement.
    439. Requirements R1.1, R3, R4 and R5 of INT-001-0, which relate to 
the timing and content of e-tags, have been deleted in the Version 1 
Reliability Standard. NERC indicates that these Requirements are 
actually business practices and that they will be included in the next 
version of NAESB Business Practices.\193\ Without prejudging any future 
proceeding regarding NAESB business practices, we find acceptable 
NERC's explanation that the deleted Requirements are business 
practices, and we propose to approve INT-001-1 with the deletion of 
Requirements R1.1, R3, R4 and R5. However, the Commission notes that 
NAESB has not at this time filed these e-tagging requirements as part 
of its business practices. If, at the time of the final rule, no such 
business practice has been submitted, the Commission may reinstate 
these Requirements as part of the final rule. In the future, to ensure 
that there is not a gap in Reliability Standards or business practices, 
the Commission expects filings from NERC and NAESB be coordinated to 
allow for the seamless transfer of Requirements from Reliability 
Standards to Business Practices.
---------------------------------------------------------------------------

    \193\ See NERC Implementation Plan for Coordinate Interchange 
Standards INT-005 through INT-010 (December 15, 2005) at 2-3.
---------------------------------------------------------------------------

    440. With regard to Allegheny's comments, we believe that all 
Reliability Standards will benefit from Measures and Levels of Non-
Compliance. Further, as mentioned above, the tagging deadlines which 
Allegheny believes provides an adequate measure of compliance have been 
deleted and will be incorporated by NAESB as business practices.
    441. While the Commission has identified concerns with regard to 
INT-001-1, it serves an important purpose in ensuring that responsible 
entities have the information they need to assess the reliability 
impact of an interchange transaction. While NERC should provide 
Measures and Levels of Non-Compliance, the Requirements set forth in 
INT-001-1 are sufficiently clear and objective as to provide guidance 
for compliance.
    442. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 our regulations, we propose directing 
that NERC 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.
c. Regional Difference to INT-001-1 and INT-004-1: WECC Tagging Dynamic 
Schedules and Inadvertent Payback
i. NERC Proposal
    443. NERC states that WECC has a regional variance that exempts 
tagging dynamic schedules and inadvertent payback. The waiver request 
included with the proposed Reliability Standards explains that tagging 
requirements simply do not apply to operations in the Western 
Interconnection. Also, a tagging requirement for dynamic schedules 
would create a burden for scheduling entities and not provide a 
substantial benefit. NERC explains that control areas and transmission 
providers have real-time scheduling information on dynamic schedules 
and that unilateral

[[Page 64815]]

inadvertent payback is not allowed in the WECC.\194\
---------------------------------------------------------------------------

    \194\ Waiver Request--Tagging Dynamic Schedules and Inadvertent 
Payback, Approved November 21, 2002. NERC Petition, Exhibit A.
---------------------------------------------------------------------------

ii. Commission Proposal
    444. As discussed earlier, in Order No. 672, the Commission 
stressed that uniformity of Reliability Standards should be the goal 
and practice, ``the rule rather than the exception.'' \195\ The absence 
of a tagging requirement for dynamic schedules in WECC is, therefore, a 
matter of concern to us. However, the Commission understands that WECC 
currently is developing a tagging requirement for dynamic 
schedules.\196\ The Commission seeks 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 the current waiver will be obviated when the tagging 
requirements become effective. The Commission will not approve or 
remand the waiver until NERC submits this information. The Commission 
will consider any regional differences contained in proposed WECC 
tagging requirement for dynamic schedules when it is submitted by NERC 
for Commission review.
---------------------------------------------------------------------------

    \195\ Order No. 672 at P 290.
    \196\ Information on this development can be found at: http://www.wecc.
[fxsp0]biz/

index.php?[fxsp0]module=pn[fxsp0]Forum&func=view[fxsp0]topic&topic=39
4.
---------------------------------------------------------------------------

d. Regional Difference to INT-001-1 and INT-003-1: MISO Energy Flow 
Information
i. NERC Proposal
    445. NERC states that a regional difference is necessary to allow 
MISO to provide market flow information in lieu of tagging intra-market 
flows among its member balancing authorities. The waiver request 
included with the proposed Reliability Standards seeks specific 
provisions to accommodate a multi-control area energy market. According 
to the waiver request, 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 impacted.\197\ The waiver text includes a condition 
specifying that the ``Midwest ISO must provide equivalent information 
to Reliability Authorities as would be extracted from a transaction 
tag.''
---------------------------------------------------------------------------

    \197\ Waiver Request--Energy Flow Information, Approved July 16, 
2003. (Attached to NERC's proposed Reliability Standards).
---------------------------------------------------------------------------

ii. Commission Proposal
    446. Order No. 672 explains that ``uniformity of Reliability 
Standards should be the goal and the practice, the rule rather than the 
exception.'' \198\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.\199\ 
Regional differences must still be just, reasonable, not unduly 
discriminatory or preferential and in the public interest.\200\
---------------------------------------------------------------------------

    \198\ Order No. 672 at P 290.
    \199\ Id. at 291.
    \200\ Id.
---------------------------------------------------------------------------

    447. Based on the information provided by NERC, the proposed 
regional difference for the INT Reliability Standards is necessary to 
accommodate MISO's Commission-approved, multi-control area energy 
market.\201\ Thus, we believe that the regional difference is 
appropriate as it is more stringent than the continent-wide Reliability 
Standard and otherwise satisfies the statutory standard for approval of 
a Reliability Standard.
---------------------------------------------------------------------------

    \201\ See Midwest Independent Transmission System Operator, 
Inc., 102 FERC ] 61,196 at P 38 (2003).
---------------------------------------------------------------------------

    448. Accordingly, the Commission proposes to approve the regional 
difference.
e. Interchange Transaction Implementation (INT-003-1)
i. NERC Proposal
    449. NERC states that the purpose of the INT-003-1 is to ensure 
that balancing authorities confirm interchange schedules with adjacent 
balancing authorities prior to implementing the schedules in their area 
control error equations. The proposed Reliability Standard applies to 
balancing authorities. INT-003-1 contains one Requirement that focuses 
on ensuring that a sending balancing authority confirms interchange 
schedules with the receiving balancing authority prior to 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.
    450. NERC indicates that it will modify this proposed Reliability 
Standard to address the lack of Measures and Levels of Non-Compliance 
and resubmit the proposal for Commission approval in November 2006.
ii. Staff Preliminary Assessment
    451. Staff noted in its Staff Preliminary Assessment that INT-003-0 
contains no Measures or Levels of Non-Compliance. This comment applies 
equally to INT-003-1.
iii. Commission Proposal
    452. The Commission notes that Requirement R1.1.3 addressing ramp 
starting time and duration in INT-003-0 is removed from INT-003-1, and 
will be included as a NAESB business practice, whereas Requirement R1.3 
addressing interchange schedules crossing an interconnection boundary 
is now included in the new INT-009-1. In addition, Requirements R2, R3 
and R4 in INT-003-0 addressing implementation requirements and 
responsibilities on the balancing authorities are transferred to INT-
009-1. Requirement R5 stipulating that balancing authorities in 
implementing interchange schedule do not knowingly cause other system 
to violate operating criteria is now retired. Requirement R6 on the 
maximum limit on the net interchange schedule is replaced with R1.2 in 
the new INT-006-1.
    453. As noted above, INT-003-1 lacks Measures and Levels of Non-
Compliance. While it is important to develop Measures and Levels of 
Non-Compliance, the Commission believes that INT-003-1 serves an 
important purpose in requiring receiving and sending balancing 
authorities to confirm and agree on the interchange schedules. Further, 
we believe that the Requirements set forth in INT-003-1 are 
sufficiently clear and objective to provide appropriate guidance for 
compliance.
    454. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard INT-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, we propose directing 
NERC to submit a modified Reliability

[[Page 64816]]

Standard that includes Measures and Levels of Non-Compliance.
f. Regional Differences to INT-003-1: MISO/SPP Scheduling Agent and 
MISO Enhanced Scheduling Agent
i. NERC Proposal
    455. The MISO/SPP Scheduling Agent Waiver dated November 21, 2002 
creates variances from this proposed Reliability Standard for MISO/SPP 
that permits a market participant to utilize a scheduling agent to 
prepare a transaction Tag on its behalf.\202\ The scheduling agent is a 
single point of contact for all external, non-participating control 
areas or other scheduling agents with respect to scheduling interchange 
into, out of, or through the RTO to which the variance applies. The 
variance document explains that the variance is needed to implement a 
proposed RTO scheduling process to meet the RTO obligations under Order 
No. 2000, simplify transaction information requirements for market 
participants, reduce the number of parties with which control area 
operators must communicate, and provide a common means to tag 
transactions within and between RTOs. It also specifies that the 
specific scheduling processes implemented between participating control 
areas are internalized and transparent to the market, but that it has 
no reliability implications and will not violate any reliability 
criteria.\203\ The Commission has issued orders authorizing use of 
these practices by MISO.\204\
---------------------------------------------------------------------------

    \202\ NERC has proposed three regional differences for INT-003-1 
that would apply to MISO. One regional difference was addressed 
above as it also related to Reliability Standard INT-001-1. The 
remaining two are discussed here.
    \203\ Waiver Request--Scheduling Agent, Approved November 21, 
2002. NERC Petition, Exhibit A.
    \204\ Midwest Independent Transmission System Operator, Inc., et 
al., 108 FERC ] 61,163 at P 100 (2004).
---------------------------------------------------------------------------

    456. The MISO Enhanced Scheduling Agent Waiver dated July 16, 2003 
creates a variance from INT-003-1 for MISO that permits an enhanced 
single point of contact scheduling agent. Again, the variance document 
explains that the variance is needed to implement a proposed RTO 
scheduling process to meet the RTO obligations under Order No. 2000, 
simplify transaction information requirements for market participants, 
reduce the number of parties with which control area operators must 
communicate, and provide a common means to tag transactions within and 
between RTOs.\205\
---------------------------------------------------------------------------

    \205\ Waiver Request--Enhanced Scheduling Agent, Approved 
November 16, 2003. ERC Petition, Exhibit A.
---------------------------------------------------------------------------

ii. Commission Proposal
    457. The Commission ruled in Order No. 672 that, as a general 
matter, the following types of regional differences in Reliability 
Standards would be acceptable: (1) a regional difference that is more 
stringent than the continent-wide Reliability Standard, including a 
regional difference that addresses matters that the continent-wide 
Reliability Standard does not; and (2) a regional Reliability Standard 
that is necessitated by a physical difference in the Bulk-Power 
System.\206\
---------------------------------------------------------------------------

    \206\ Order No. 672 at P 291.
---------------------------------------------------------------------------

    458. Based on the information provided by NERC, the proposed 
regional differences for the INT Reliability Standard will provide 
administrative efficiency, and equal or greater amounts of information 
to the appropriate entities as required in MISO's Commission-approved 
multi-control area energy market.\207\ Thus, we believe that the 
proposed regional differences meet the legal standard for approval as 
well as the first criteria discussed above for a regional difference.
---------------------------------------------------------------------------

    \207\ See Midwest Independent Transmission System Operator, 
Inc., 102 FERC ] 61,196 at P 38 (2003).
---------------------------------------------------------------------------

    459. Accordingly, for the reasons set forth above, the Commission 
proposes to approve these two additional regional differences.
g. Dynamic Interchange Transaction Modifications (INT-004-1)
i. NERC Proposal
    460. NERC states that the purpose of INT-004-1 is 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 a Tag for dynamic schedules, i.e., 
transactions that vary from within an hour. INT-004-1 does not identify 
Levels of Non-Compliance.
ii. Staff Preliminary Assessment
    461. No concerns were raised in the Staff Preliminary Assessment.
iii. Comments
    462. INT-004-1 was included in NERC's August 28, 2006 Supplemental 
Filing, and no comments were submitted regarding it.
iv. Commission Proposal
    463. The Commission notes that Requirement R1 in INT-004-1 
providing procedures to modify interchange schedules to address 
reliability events are replaced with Requirements R1, R2 and R3 in the 
new INT-010-1. Requirement R2 which applies to generator operators or 
load serving entities for requesting to modify an interchange 
transaction due to loss of generation or load is replaced with 
Requirements in INT-005-1 through INT-010-1.
    464. The Commission believes that Levels of Non-Compliance should 
be included.
    465. INT-004-1 contains a regional variance from WECC that exempts 
tagging dynamic schedules and inadvertent payback. This is discussed 
above in more detail. The Commission proposes to leave pending the WECC 
regional difference until NERC files a new regional difference.
    466. 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 for reliability assessment. 
Further, the Requirements set forth in INT-004-1 are sufficiently clear 
and objective to provide guidance for compliance.
    467. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard INT-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, we propose directing 
NERC to submit a modification to INT-004-1 that includes Levels of Non-
Compliance.
h. Interchange Authority Distributes Arranged Interchange (INT-005-1)
i. NERC Proposal
    468. INT-005-1, submitted with NERC's August 28, 2006 Supplemental 
Filing, ensures the implementation of interchange between source and 
sink balancing authorities and the interchange information is 
distributed by an interchange authority to the relevant entities for 
reliability

[[Page 64817]]

assessments. INT-005-1 is applicable to the ``interchange authority.'' 
\208\
---------------------------------------------------------------------------

    \208\ NERC's glossary defines ``interchange authority'' as 
``[t]he 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.''
---------------------------------------------------------------------------

ii. Commission Proposal
    469. The Commission is satisfied that the Requirements of the 
Reliability Standard are appropriate to ensure that interchange 
information is distributed and available for reliability assessment 
prior to its implementation. However, we are concerned regarding the 
applicability of INT-005-1 to the interchange authority. It is not 
clear from NERC's definition whether an interchange authority is a 
user, owner or operator of the Bulk-Power System, or what types of 
entities would be eligible to perform such a function. Therefore, the 
Commission requests 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.
    470. Reliability Standard INT-005-1 does not include Levels of Non-
Compliance.
    471. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard INT-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, we propose to direct 
that NERC submit a modification to INT-005-1 that includes Levels of 
Non-Compliance. Further, the Commission requests 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.
i. Response to Interchange Authority (INT-006-1)
i. NERC Proposal
    472. INT-006-1, submitted with NERC's August 28, 2006 Supplemental 
Filing to replace INT-002-0, ensures that each arranged interchange is 
checked for reliability before it is implemented. It is applicable to 
balancing authorities and transmission service providers and requires 
these entities to evaluate the energy profile and the ramp rate of the 
generation to support the transactions in response to the request from 
the interchange authority to change the status of an interchange from 
an arranged interchange to a confirmed interchange.
ii. Staff Preliminary Assessment
    473. INT-006-1 is a new Reliability Standard that mostly contains 
Requirements from retired INT-002-0. Staff noted in its Staff 
Preliminary Assessment that INT-002-0 does not explicitly apply to 
reliability coordinators and transmission operators for reliability 
assessments of transactions before they are implemented. Staff 
indicated that it is important that the Reliability Standard apply to 
these entities explicitly because power flows for interchange 
transactions cross multiple balancing authority areas and affect 
multiple transmission paths in an Interconnection.
iii. Comments
    474. As discussed below, INT-006-1 raises a number of issues that 
are similarly raised by the Reliability Standard it replaces, INT-002-
0. Therefore, relevant comments regarding INT-002-0 are discussed here.
    475. NERC maintains that staff's concerns regarding the 
applicability of INT-002-0 to reliability coordinators and transmission 
operators are addressed by proposed Reliability Standard INT-004-0, 
which addresses reliability events such as potential or actual SOL or 
IROL violations.
    476. Similarly, Southern submits that the Reliability Standard 
currently applies to reliability coordinators and transmission 
operators in their role in the reliability assessment of individual 
interchange transactions. Southern explains that an individual Tag is 
first assessed by the balancing authority based on information on 
system limits provided by the reliability coordinator and/or the 
transmission operator. The composite set of Tags and associated 
schedules are then forwarded to the reliability analysis services that 
reliability coordinators and transmission operators use for their wide-
area review. Southern contends that it would not be appropriate for 
reliability coordinators and transmission owners to approve or deny 
individual schedules during tagging, and states that they should be 
involved in reviewing tags in a composite manner.
iv. Commission Proposal
    477. The Commission proposes to approve INT-006-1 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    478. We agree with NERC and Southern that it would be duplicative 
for a reliability coordinator or transmission owner to approve or deny 
an individual schedule during tagging. However, consistent with 
Southern's comment, we believe that reliability coordinators and 
transmission operators should review composite energy interchange 
transaction information (composite Tags) for wide-area reliability 
impact. 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 prior to implementation. Accordingly, we propose to 
require the ERO to modify the proposed Reliability Standard to ensure 
that reliability coordinators and transmission operators validate 
composite Tags (now called composite arranged interchanges) for 
reliability.
    479. The Commission notes that INT-006-1 has included Measures and 
Levels of Non-Compliance with Requirements on balancing authorities and 
transmission service providers to check each arranged interchange for 
reliability. We believe that INT-006-1 serves an important purpose in 
assessing each interchange transaction from a reliability perspective.
    480. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard INT-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, we propose to direct 
that NERC 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 prior to implementation.

[[Page 64818]]

j. Interchange Confirmation (INT-007-1)
i. NERC Proposal
    481. INT-007-1, submitted with NERC's August 28, 2006 Supplemental 
Filing, ensures that each arranged interchange is checked for 
reliability before it is implemented. INT-007-1 requires the 
interchange authority to verify that the submitted arranged 
interchanges are valid and complete with relevant information and 
approvals from the balancing authorities and transmission service 
providers before changing their status to confirmed interchanges.
ii. Commission Proposal
    482. We are concerned regarding the applicability of INT-007-1 to 
the interchange authority. As discussed previously, it is not clear 
from NERC's definition whether an interchange authority is a user, 
owner or operator of the Bulk-Power System, or what types of entities 
would be eligible to perform such a function, and in our discussion of 
INT-005-1 we request that NERC provide additional information regarding 
the role of the interchange authority.
    483. However, the Commission is satisfied that the Requirements of 
the Reliability Standard are appropriate to ensure that interchange 
information is verified prior to its implementation. Accordingly, the 
Commission therefore proposes to approve INT-007-1 as mandatory and 
enforceable. We believe that the proposed Reliability Standard is just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest.
k. Interchange Authority Distributes Status (INT-008-1)
i. NERC Proposal
    484. INT-008-1, submitted with NERC's August 28, 2006 Supplemental 
Filing, ensures that the implementation of interchanges between source 
and sink balancing authorities is coordinated by an interchange 
authority. The Reliability Standard applies to the interchange 
authority. 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.
ii. Commission Proposal
    485. Again, we are concerned regarding the applicability of INT-
008-1 to the interchange authority. As explained above, the Commission 
requests additional information because it is not clear from NERC's 
definition whether an interchange authority is a user, owner or 
operator of the Bulk-Power System, or what types of entities would be 
eligible to perform such a function.
    486. However, the Commission is satisfied that the Requirements of 
the Reliability Standard are appropriate to ensure that interchange 
information is coordinated between the source and sink balancing 
authorities prior to its implementation. Accordingly, the Commission 
therefore proposes to approve INT-008-1 as mandatory and enforceable. 
We believe that the proposed Reliability Standard is just, reasonable, 
not unduly discriminatory or preferential, and in the public interest.
l. Implementation of Interchange (INT-009-1)
i. NERC Proposal
    487. INT-009-1, submitted with NERC's August 28, 2006 Supplemental 
Filing, ensures that the implementation of an interchange between 
source and sink balancing authorities is coordinated by an interchange 
authority.
ii. Commission Proposal
    488. The Commission is satisfied that the proposed Reliability 
Standard performs a necessary reliability function by coordination of 
interchanges and incorporating them into the ACE calculation of the 
respective balancing authorities. Further, INT-009-1 includes clear and 
appropriate Requirements, Measurements and Levels of Non-Compliance to 
ensure proper implementation of interchange transactions that have 
received reliability assessments. The Commission therefore proposes to 
approve INT-009-1 as mandatory and enforceable. We believe that the 
proposed Reliability Standard is just, reasonable, not unduly 
discriminatory or preferential, and in the public interest.
m. Interchange Coordination Exemptions (INT-010-1)
i. NERC Proposal
    489. INT-010-1, submitted with NERC's August 28, 2006 Supplemental 
Filing, allows certain types of interchange schedules to be initiated 
or modified by reliability entities under abnormal operating 
conditions, and to be exempt from compliance with other Reliability 
Standards in the INT group. The Reliability Standard is applicable to 
the balancing authority and reliability coordinator.
    490. The proposed Reliability Standard, INT-010-1 has three 
Requirements, which allows modifications to interchange schedules under 
abnormal system conditions: (1) The balancing authority that 
experiences a loss of resources covered by an energy sharing agreement 
shall ensure that a request for an arranged interchange is submitted 
within required time; (2) for a modification to an existing interchange 
schedule that is directed by a reliability coordinator for a current or 
imminent reliability-related reasons, the reliability coordinator 
directs a balancing authority to submit the modified arranged 
interchange reflecting that modification within a specified time; and 
(3) for a new interchange schedule that is directed by a reliability 
coordinator for current or imminent reliability-related reasons, the 
reliability coordinator directs a balancing authority to submit an 
arranged interchange reflecting that interchange schedule within 
required time.
ii. Staff Preliminary Assessment
    491. INT-010-1 includes three Requirements that replace Requirement 
R1 from INT-004-0. Staff raised concerns in the Staff Preliminary 
Assessment on INT-004-0 with respect to the use of transaction 
modifications to address reliability events such as actual IROL 
violations.
    492. Specifically, staff noted that INT-004-0 (now INT-010-1) 
allows modification of an interchange transaction to address an actual 
SOL or IROL violation.\209\ Staff stated that, in light of the 
procedures involved, including submission, assessment and approval, the 
total time necessary to implement an interchange transaction 
modification is expected to exceed significantly the 30 minute time-
frame established in other Reliability Standards, i.e., the requirement 
that the system be returned from a SOL/IROL violation to a secure 
operating state as soon as possible, but no more than 30 minutes after 
the violation.\210\ INT-004-0 (now INT-010-1) does not contain a clear 
reference to this potential

[[Continued on page 64819]]

From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 64819-64868]] Mandatory Reliability Standards for the Bulk-Power System

[[Continued from page 64818]]

[[Page 64819]]

limitation, and staff observed that it could lead to the inappropriate 
use of transaction modification by reliability entities to deal with 
actual SOL/IROL violations. Staff expressed concern that such actions 
could lead to the loss of valuable time that would be needed to 
readjust the system effectively using other operational corrective 
actions.
---------------------------------------------------------------------------

    \209\ NERC defines IROL as ``[t]he value (such as MW, MVar, 
Amperes, Frequency or Volts) derived from, or a subset of the System 
Operating Limits, which if exceeded, could expose a widespread area 
of the Bulk Electric System to instability, uncontrolled 
separation(s) or cascading outages.'' NERC glossary at 8.
    \210\ Reliability Standard IRO-005-0, Requirement R3, states in 
part ``[i]f a potential or actual IROL violation cannot be avoided 
through proactive intervention, the Reliability Coordinator shall 
initiate control actions or emergency procedures to relieve the 
violation without delay, and no longer than 30 minutes.''
---------------------------------------------------------------------------

iii. Comments
    493. There were no comments submitted regarding the use of 
transaction modification to address actual IROL violations in INT-010-
1.
iv. Commission Proposal
    494. The Commission believes that it is generally ineffective to 
use transaction modifications to mitigate an actual IROL violation or 
other system condition that calls for expeditious return to a secure 
system state. Transaction modifications are even less effective than 
the use of transmission load relief (TLR) procedures to mitigate an 
actual IROL violation. We note that the Blackout Report specified that 
NERC should ``clarify that the [TLR] process should not be used in 
situations involving an actual violation of an Operating Security 
Limit.'' The Blackout Report stated that ``the TLR procedure is often 
too slow for use in situations in which an affected system is already 
in violation of an Operating Security Limit.'' \211\ We believe these 
same concerns articulated in the Blackout Report apply all the more so 
to a transaction modification to address an actual IROL violation.
---------------------------------------------------------------------------

    \211\ Blackout Report at 163.
---------------------------------------------------------------------------

    495. 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. We interpret 
that these current or imminent reliability-related reasons do not 
include actual IROL violations as 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--a period that is 
much shorter than the time that is expected to require for new or 
modified transactions to be implemented.
    496. Accordingly, with the above interpretation, the Commission 
therefore proposes to approve INT-010-1 as mandatory and enforceable. 
We believe that the proposed Reliability Standard is just, reasonable, 
not unduly discriminatory or preferential, and in the public interest.
7. IRO: Interconnection Reliability Operations and Coordination
a. Overview
    497. The Interconnection Reliability Operations and Coordination 
(IRO) group of Reliability Standards detail the responsibilities and 
authorities of a reliability coordinator.\212\ The proposed 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.
---------------------------------------------------------------------------

    \212\ According to the NERC glossary, at 13, 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 * * *''
---------------------------------------------------------------------------

b. General Comments
    498. CenterPoint believes that the IRO series of Reliability 
Standards are largely unnecessary as they are process-oriented. It 
proposes the consolidation of the IRO series of Reliability Standards 
to replace the process based Requirements with performance metrics. If, 
after some time, these do not achieve their reliability goal, they 
should be rejected.
    499. The Commission believes that performance metrics will 
generally complement and improve the proposed Reliability Standards. 
However, we do not believe that a Reliability Standard based solely on 
performance metrics can replace the proposed IRO Reliability Standards. 
This is because performance metrics, in general, are lagging 
indicators, and therefore, could only serve as reactive tools in 
improving the Reliability Standards. Additionally, we do not agree with 
CenterPoint's statement that the IRO series of Reliability Standards 
are largely unnecessary and can be replaced with performance standards. 
On the contrary, we believe that the proposed IRO series of Reliability 
Standards establish requirements for data, tools, and wide area view 
and other real-time operating activities that must be performed by a 
reliability coordinator to ensure the reliable operation of the 
interconnected grid.
c. Reliability Coordination--Responsibilities and Authorities (IRO-001-
0)
i. NERC Proposal
    500. IRO-001-0 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. This Reliability 
Standard would apply to reliability coordinators and regional 
reliability organizations.
ii. Staff Preliminary Assessment
    501. The Staff Preliminary Assessment noted that IRO-001-0 does not 
explicitly assign responsibilities to reliability coordinators in its 
Purpose or Requirements. Responsibilities can only be inferred from the 
definition of reliability coordinator in the NERC glossary.
iii. Comments
    502. NERC comments that virtually every Requirement in IRO-001-0 
applies to reliability coordinators, so it does not understand the 
Staff Preliminary Assessment's concern regarding the assignment of a 
reliability coordinator's responsibilities. It also states that the 
compliance registry will include reliability coordinators.
    503. MRO and ReliabilityFirst agree with the Staff Preliminary 
Assessment. MRO believes that a clarification of the ``Purpose'' 
section of IRO-001-0 is warranted to better identify a reliability 
coordinator's responsibilities.
    504. The ISO/RTO Council does not share the Staff Preliminary 
Assessment's concern because each reliability coordinator's 
``reliability plan'' is approved by the NERC Operating Committee. It 
states that this process is intended to ensure that a reliability 
coordinator's peers validate that there is an appropriate entity 
authorized to carry out a reliability coordinator's plans.
iv. Commission Proposal
    505. The stated Purpose of IRO-001-0 is ``[r]eliability 
[c]oordinators must have the authority, plans and agreements in place 
to immediately direct reliability entities within their Reliability 
Coordinator Areas to re-dispatch generation, reconfigure transmission, 
or reduce load to mitigate critical conditions to return the system to 
a reliable state.'' As noted by NERC, IRO-001-0 includes eight 
Requirements that set forth reliability coordinator responsibilities. 
However, these Requirements do not comprehensively match the 
responsibilities described in the Purpose statement of this Reliability 
Standard. Nonetheless, the Commission observes that the IRO group of 
Reliability Standards, taken as a whole, together with the NERC 
glossary definition of reliability coordinator, provides an adequate 
understanding of

[[Page 64820]]

the role and responsibilities of a reliability coordinator. Thus, while 
IRO-001-0 could be improved by comprehensively defining the overall 
responsibility of a reliability coordinator, as suggested in the title 
of the Reliability Standard (Reliability Coordination--Responsibilities 
and Authorities), we will not propose to direct NERC to do so.
    506. Requirement R1 of IRO-001-0 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. Sections 502 and 503 of NERC's Rules of Procedure indicate 
that the ERO and Regional Entities are responsible for registering, 
certifying and verifying entities pursuant to NERC's compliance 
registry, including reliability coordinators. The Commission proposes 
that NERC modify Requirement R1 to reflect the process set forth in the 
NERC Rules of Procedures, including the substitution of Regional Entity 
for regional reliability organization.
    507. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard IRO-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 
proposes to direct that NERC 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.
d. Reliability Coordination--Facilities (IRO-002-0)
i. NERC Proposal
    508. The proposed Reliability Standard, IRO-002-0, 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, act in addressing real-
time emergency conditions and control analysis tools. NERC indicates 
that it plans to modify IRO-002-0 to address the lack of Measures and 
Levels of Non-Compliance and resubmit it for Commission approval in 
November 2006.
ii. Staff Preliminary Assessment
    509. The Staff Preliminary Assessment did not identify any 
substantive issues other than noting the absence of Measures and Levels 
of Non-Compliance.
iii. Comments
    510. MISO contends that the proposed Reliability Standard does not 
clearly require all reliability coordinators to demonstrate a 
functioning state estimation, real-time contingency analysis or a 
defined ``wide area view'' that includes visibility into neighboring 
regions. According to MISO, the requirement that a reliability 
coordinator have ``adequate analysis tools'' is a ``loophole that 
belies the term `standard.' ''\213\ ReliabilityFirst asserts that NERC 
should expedite the development of missing compliance elements within 
IRO-002-0.
---------------------------------------------------------------------------

    \213\ MISO Comments at 13, n.13, quoting IRO-002-0, Requirement 
R7, which states, ``[e]ach Reliability Coordinator shall have 
adequate analysis tools such as state estimation, pre- and post-
contingency analysis capabilities (thermal, stability, and voltage), 
and wide-area overview displays.''
---------------------------------------------------------------------------

iv. Commission Proposal
    511. Requirement R7 currently does not specifically require the 
reliability coordinators to have specific tools because it includes the 
phrase ``such as.'' Requirement R7 should be modified to explicitly 
require a minimum set of tools that should be made available to the 
reliability coordinator. We share ReliabilityFirst's concern that IRO-
002-0 lacks Measures and Levels of Non-Compliance and direct NERC to 
add these compliance elements in its modification of the proposed 
Reliability Standard. While the Commission has identified concerns with 
regard to IRO-002-0, we believe that the proposal serves an important 
purpose in ensuring that reliability coordinators have the information, 
tools and capabilities to perform their functions. NERC should provide 
Measures and Levels of Non-Compliance for this proposed Reliability 
Standard. Nonetheless, the proposed Requirements set forth in this 
Reliability Standard are sufficiently clear and objective to provide 
guidance for compliance.
    512. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard IRO-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 
proposes to direct that NERC submit, a modification to IRO-002-0 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.
e. Reliability Coordination--Wide Area View (IRO-003-1)
i. NERC Proposal
    513. The stated purpose of the proposed Reliability Standard is 
that a reliability coordinator must 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. 
NERC indicates that it plans to modify IRO-003-1 to address the absence 
of Measures and Levels of Non-Compliance and will resubmit it for 
Commission approval in November 2006.
ii. Staff Preliminary Assessment
    514. The Staff Preliminary Assessment indicated that IRO-003-1 does 
not specify the criteria for defining critical facilities in adjacent 
systems whose status and loading could affect the reliability of 
neighboring systems.
iii. Comments
    515. NERC responds that IRO-003-1 provides that ``critical 
facilities'' are those that, if they fail, would result in an SOL or 
IROL violation. According to NERC, this means that critical facilities 
can only be determined by contingency analysis and change through time, 
and therefore, ``may or may not exist.'' Because an SOL or IRO 
violation is an operating state that can only be determined by running 
a series of ``what if'' analyses, IRO-003-1 defines a ``critical 
facility'' as the facility that, if it fails, places the transmission 
system in a state ``such that the failure of some other element will 
result in facility overloads, instability, or uncontrolled cascading 
outages.'' \214\ NERC states that the Commission should approve the 
Reliability Standard and adds that it will consider revising it to 
clarify the definition of ``critical facility.''
---------------------------------------------------------------------------

    \214\ NERC Comments at 126.
---------------------------------------------------------------------------

    516. MRO agrees with the Staff Preliminary Assessment that this 
Reliability Standard should be revised to specify the criteria for 
defining ``critical facilities'' in adjacent systems. MISO contends 
that the proposed Reliability Standard does not clearly

[[Page 64821]]

define the term ``wide area view'' that includes visibility into 
neighboring regions.
iv. Commission Proposal
    517. The Blackout Report emphasized that a principal cause of the 
August 2003 blackout was a lack of situational awareness, which was in 
turn the result of inadequate reliability tools and backup 
capabilities.\215\ It pointed out that the need for improved 
visualization capabilities over a wide geographic area has been a 
recurrent theme in blackout investigations. The Blackout Report also 
explained that the Task Force investigation of the August 2003 blackout 
revealed that ``there has been no consistent means across the Eastern 
Interconnection to provide an understanding of the status of the power 
grid outside of a control area,'' and improved visibility of grid 
status would aid an operator in making adjustments in operations to 
mitigate potential problems.\216\ The Commission believes that this 
issue is applicable to the entire country and not just the Eastern 
Interconnection. IRO-003-1 addresses these important concerns of the 
Blackout Report by requiring that a reliability coordinator monitor its 
own and adjacent areas to have a wide area view that is ``necessary to 
ensure that, at any time, regardless of prior planned or unplanned 
events, the Reliability Coordinator is able to determine any potential 
System Operating Limit and Interconnection Reliability Operating Limit 
violations within its Reliability Coordination Area.'' \217\
---------------------------------------------------------------------------

    \215\ Blackout Report at 159.
    \216\ Id.
    \217\ IRO-003-1, Requirement R1.
---------------------------------------------------------------------------

    518. The Commission notes that Requirement R2 of the Reliability 
Standard requires that each reliability coordinator know the current 
status of all ``critical facilities'' whose ``failure, degradation or 
disconnection'' could result in an SOL or IROL violation. However, IRO-
003-1 does not specify the criteria for defining critical facilities. 
NERC explains that specifying such criteria is very difficult because 
critical facilities can only be determined by contingency analysis and 
change through time. While NERC acknowledges the absence of such 
criteria, it requests that the Reliability Standard be approved. In 
addition, NERC indicates that it will consider a modification to 
clarify the definition of ``critical facility.''
    519. IRO-003-1 serves an important reliability goal of requiring 
reliability coordinators to have a wide area view and maintain 
situational awareness. The Commission proposes to direct NERC to 
provide Measures and Compliance elements for the proposed Reliability 
Standard, and include criteria to define ``critical facilities'' in a 
reliability coordinator's area and its adjacent systems. Nonetheless, 
the Requirements set forth in IRO-003-1 are sufficiently clear and 
objective to provide guidance for compliance and a basis for 
enforcement.
    520. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard IRO-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 
proposes to direct that NERC submit a modification to IRO-003-1 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.
f. Reliability Coordination--Operations Planning (IRO-004-1)
i. NERC Proposal
    521. The stated purpose of IRO-004-1 is to require that each 
reliability coordinator 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.
ii. Staff Preliminary Assessment
    522. The Staff Preliminary Assessment noted that, while IRO-004-1 
requires Reliability Coordinators to conduct next-day reliability 
analyses to ensure reliable operations in anticipated normal and 
contingency event conditions, it ``does not require that the system be 
assessed in the next-day planning analysis to identify the control 
actions needed to bring the system back to a stable state, with an 
effective implementation time of within 30 minutes, so that the system 
will be able to withstand the next contingency without cascading.'' 
\218\
---------------------------------------------------------------------------

    \218\ Staff Preliminary Assessment at 71.
---------------------------------------------------------------------------

iii. Comments
    523. NERC asserts that Requirement R1 of IRO-004-1 does require 
next-day operations planning studies and does not require 
modification.\219\ Similarly, ISO-RTO Council comments that the 
proposed Reliability Standard contains the appropriate requirements for 
ensuring reliable operations because there are other tools available to 
meet the needs identified with a next-day analysis. These alternative 
tools are adequate for conducting next-day analysis.
---------------------------------------------------------------------------

    \219\ Requirement R1 requires that ``Each Reliability 
Coordinator shall conduct next-day reliability analyses for its 
reliability coordinator area to ensure that the Bulk Electric System 
can be operated reliably in anticipated normal and contingency event 
conditions. The reliability coordinator shall conduct contingency 
analysis studies to identify potential interface and other SOL and 
IROL violations, including overloaded transmission lines and 
transformers, voltage and stability limits, etc.''
---------------------------------------------------------------------------

    524. MRO suggests that the next-day reliability analyses do not 
need to include the control actions that would be implemented to bring 
the system back to a stable state. MRO argues that, in most cases, the 
actual dispatch and condition of the system during real-time is not 
representative of the dispatch used in the model for performing the 
next-day analyses and, thus, mitigation action needed during real-time 
will differ.
    525. ReliabilityFirst agrees in general with the Staff Preliminary 
Assessment's comments, but cautions that the proposal to identify and 
study all possibilities for alleviating SOL and IROL may be impractical 
and unachievable.
iv. Commission Proposal
    526. The Commission agrees with NERC that the proposed Reliability 
Standard requires next day operations planning. While the Staff 
Preliminary Assessment mentions the next-day planning analysis and the 
need to study events that would result in cascading for the first 
contingency, this was not the intended focus of staff's observations. 
Rather, the thrust of staff's concern was that the control actions 
necessary to return the system to a stable state after the first 
contingency must do so effectively within the specified implementation 
time of less than 30 minutes.\220\ To assure that an operator has 
either sufficient generation resources, transmission modifications, or 
load shedding capability to avoid a cascading outage after the first 
contingency, the control actions should be identified in the next-day 
analyses to better prepare system operators to deal

[[Page 64822]]

with system contingencies or emergencies in real-time operations.
---------------------------------------------------------------------------

    \220\ IRO-005-1, Requirement R3 states, in relevant part, ``* * 
* the [r]eliability [c]oordinator shall initiate control actions or 
emergency procedures to relieve the violations without delay, and no 
longer than 30 minutes.''
---------------------------------------------------------------------------

    527. The Commission believes that identification of potential 
control actions will aid system operators in performance of their 
duties. While MRO is correct that control actions identified in a next-
day analysis may not always be useful in a real-time scenario, 
nonetheless, the control actions identified in the next-day analysis 
may quite often be relevant and having the system operators aware of 
options earlier on would be helpful.
    528. The Commission agrees with NERC regarding the applicability of 
this Reliability Standard. While most Requirements pertain to 
reliability coordinators, they also require each balancing authority, 
transmission operator, transmission owner, generator operator, and 
load-serving entity to provide information to its reliability 
coordinator for system studies. It also requires that each transmission 
operator, balancing authority and transmission service provider to 
comply with the directive of its reliability coordinator based on next-
day assessments.
    529. While the Commission has identified one concern with regard to 
IRO-004-1, the proposed Reliability Standard serves an important 
purpose by requiring that each reliability coordinator conduct next-day 
operations reliability analyses to ensure that the system can be 
operated reliably in anticipated normal and contingency system 
conditions. Further, the Requirements set forth in IRO-004-1 are 
sufficiently clear and objective to provide guidance for compliance and 
a basis for enforcement.
    530. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC 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.
g. Reliability Coordination--Current Day Operations (IRO-005-1)
    531. IRO-005-1 ensures energy balance and transmission reliability 
for the current day by identifying tasks that reliability coordinators 
must perform throughout the day. The stated purposed of the proposed 
Reliability Standard is that a reliability coordinator must be 
continuously aware of conditions within its area and include this 
information in its reliability assessments. Additionally, a reliability 
coordinator must monitor the parameters of the system that may have a 
significant impact upon its area and neighboring reliability 
coordinator areas. NERC indicates that it plans to modify IRO-005-0 to 
address the lack of Measures and Levels of Non-Compliance and resubmit 
it for Commission approval in November 2006.
i. Staff Preliminary Assessment
    532. Requirement R3 of IRO-005-1 provides that: ``[i]f a potential 
or actual IROL violation cannot be avoided through proactive 
intervention, the Reliability Coordinator shall initiate control 
actions or emergency procedures to relieve the violation without delay, 
and no longer than 30 minutes. The Reliability Coordinator shall ensure 
all resources, including load shedding, are available to address a 
potential or actual IROL violation.'' The Staff Preliminary Assessment 
pointed out that this Requirement may be interpreted in either of two 
ways: (1) a less conservative interpretation in which an IROL is 
allowed to be exceeded during normal operations, i.e., prior to a 
contingency, provided that corrective actions are taken within 30 
minutes; and (2) a more conservative interpretation that an IROL should 
only be exceeded after a contingency and the system must subsequently 
be returned to a secure condition as soon as possible, but no longer 
than 30 minutes. Therefore, IRO-005-1 creates the situation in which 
the system may be one contingency away from potential cascading failure 
if operated under the less conservative interpretation or two 
contingencies away from potential cascading failure if the more 
conservative interpretation is adopted.
ii. Comments
    533. NERC acknowledges that the SOLs and IROLs are among the most 
important operating measures contained in the proposed Reliability 
Standards and that it continues to refine the definitions of both these 
terms. NERC explains that SOL and IROL violations do not necessarily 
result from an event or ``contingency.'' It asserts that the 
transmission system may ``drift'' into an SOL or IROL violation without 
any triggering event and with every element of the transmission system 
operation within its own safe limit.\221\ NERC states that the point of 
these limits is not whether a particular transmission facility is 
operating within its normal limits, but to determine what happens if 
the transmission element fails regardless of how much power is flowing 
through it.
---------------------------------------------------------------------------

    \221\ See NERC Comments at 43-48.
---------------------------------------------------------------------------

    534. NERC states that it will consider clarifying those Reliability 
Standards that indicate a contingency is not required and, as a 
corollary, that a Reliability Standard should not allow a system 
operator to ``drift'' in and out of an SOL or IROL violation. Further, 
NERC will continue to refine its definition of SOL and IROL violations. 
The Operating Committee has commissioned an Operating Limits Definition 
Task Force to work on this matter, and the Task Force will bring its 
final suggestions to the Operating Committee by the end of 2006. NERC 
indicates that it will review proposed Reliability Standards IRO-003-0 
and IRO-005-1 and address SOL and IROL violation mitigation.
    535. According to NERC, the 30-minute limit for mitigating IROL 
violations is one of many reliability standards gleaned from decades of 
interconnected systems operation experience, and represents a tradeoff 
between: (1) sufficient time to allow the transmission operator or 
reliability coordinator to mitigate the violation without having to 
shed load or disconnect transmission system components; and (2) the 
risk that some event will occur before the mitigating action is taken. 
NERC explains that action is required ``as soon as possible'' or 
``without delay,'' however, exceeding an SOL or IROL for no more than 
30 minutes is not a violation. It contends that this approach is 
reasonable because it allows the system operator to decide on what 
course of action to take. Operating options that are less severe than 
shedding load are often available, but it explains that these actions 
may require more time for implementation. NERC asserts that its 
committees and subcommittees have debated the phrase, ``as soon as 
possible'' for years and have not found a better way to articulate a 
requirement that allows the system operator the leeway to decide the 
best course of action.
    536. MRO and NYSRC agree with the Staff Preliminary Assessment that 
IRO-005-1 allows varying interpretations with respect to IROL limits 
under normal and contingency conditions and should be revised to 
clarify how IROL events are addressed. ReliabilityFirst believes that a 
methodology to address

[[Page 64823]]

SOLs and IROLs must be developed. It argues that this will aid in 
clarifying that exceeding limits is not acceptable operating practice. 
According to ReliabilityFirst, proposed Reliability Standards are being 
developed that will provide more definition and detail in this area. It 
urges the acceleration of this development.
    537. MidAmerican believes that staff's ``more conservative'' 
interpretation may be overly conservative and should not be adopted. It 
contends that, in an interconnected transmission network, it is 
difficult to operate prior to a contingency so that potential IROL 
violations are avoided at all times. It believes that to adopt the more 
conservative interpretation could require an operator to scale back the 
operation of its system pre-contingency by an inordinate amount to 
provide a safety margin so as not to risk a potential IROL violation 
even for only very short periods of time. MidAmerican maintains that 
such an operation would result in slightly more reliable operation at 
an unjustifiably high price.
iii. Commission Proposal
    538. The Commission proposes to approve IRO-005-1 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard and perform a survey of 
present operating practices and actual operating experience concerning 
drifting in and out of IROL violations.
    539. The Commission believes that one of the fundamental principles 
in operating the Bulk-Power System reliably is that the system must be 
capable of supplying firm demand and supporting firm transactions while 
retaining the capability to withstand a critical contingency without 
resulting in instability, uncontrolled separation or cascading 
failures. This is affirmed by the term, Reliable Operation, as set 
forth in section 215(a)(4) of the FPA \222\ and the technical 
requirement as stated in Table 1 of Reliability Standard TPL-002-
0.\223\ Therefore, in order to achieve the reliability goal stated in 
the definition of Reliable Operation, the Bulk-Power System must be 
operated to respect all applicable IROLs during normal conditions, i.e. 
prior to a contingency, so that the system is capable of withstanding a 
critical contingency without resulting in instability, uncontrolled 
separation or cascading outages.
---------------------------------------------------------------------------

    \222\ Reliable operation: 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.
    \223\ TPL-002-0 System Performance Following Loss of a Single 
Bulk Electric System Element, Table 1: For Category B events 
resulting in loss of a single element, the system remains stable and 
both thermal and voltage limits are within applicable ratings with 
no loss of demand or curtailment of firm transfers and no cascading 
outages.
---------------------------------------------------------------------------

    540. IRO-005-1 allows a system operation 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.
    541. The Commission notes that the proposed Reliability Standards 
(e.g. TOP-007-0) do not consider operation exceeding IROL for less than 
30 minutes as a compliance violation. This, in addition to the less 
conservative interpretation that IROL violation is permissible during 
normal operations, opens up a significant reliability gap that allows 
operations with IROL violations for less than 30 minutes at a time. 
Under the mandatory reliability construct, there would be no 
enforcement provision to sanction against such actions even they 
resulted in cascading outages.
    542. The Commission believes a proactive standard, that clearly 
defines that reliable operations means operating the system within 
IROLs and requires such operating practice be reinforced by periodic 
reporting of the frequency, duration and causes of IROL violations, is 
needed to prevent or mitigate the risk of blackouts. This is because, 
by definition, when the system is operating in violation of IROLs and 
if a critical contingency occurs, cascading outages will result.
    543. Operating the system during normal system conditions with IROL 
violations is also known in the industry as ``drifting in and out'' of 
an IROL violation. This is the first and less conservative 
interpretation of the proposed Reliability Standard as stated above and 
one contingency away from cascading failure. We particularly note that 
the NERC Operating Committee recommended that the proposed Reliability 
Standards should not allow a system operator to ``drift'' in and out of 
an SOL or IROL violation.
    544. The Commission agrees with ReliabilityFirst's comments that 
exceeding any limit is not acceptable operating practice. The system 
should strive to operate in a secure state that respects all IROLs 
under normal conditions at all times, except for infrequent and 
unanticipated changing conditions that are beyond the control of 
reliability coordinators and operating entities under their 
jurisdiction. Furthermore, these unanticipated factors should be 
limited and should not include load pick-up and drop-off as changes in 
load demand or coordinated generation dispatches and transactions, all 
of which would have obtained prior assessments and approvals.
    545. In contrast to MidAmerican's comments, the Commission does not 
believe that respecting IROL under normal system conditions requires an 
inordinate amount of operating margin which may result in an 
unjustifiably high price. However, 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 all reliability coordinators to report any 
violations of IROLs, their causes, the date and time of the violation, 
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.
    546. The Commission also finds that well-designed Levels of Non-
Compliance should duly recognize the magnitude, frequency and duration 
of IROL violations under normal system conditions and differentiate 
those caused by system contingencies. The former, if not severe, 
frequent, of extended duration or willfully deployed, should not incur 
heavy penalties. Nevertheless, these occurrences and causes should be 
recorded and reported. We understand that most reliability coordinators 
and transmission operators already keep records of power flows on 
transmission interfaces, transmission paths or flowgates versus their 
respective IROLs as a part of their operating and management tools. We 
believe that the practice of separately recording and reporting IROL 
violations and durations occurring under normal and contingency system 
conditions serves several purposes, including: (1) Reinforcing the 
sound principles of reliable system operations; (2) serving as a 
performance metric to gauge the effectiveness of Reliability Standards, 
coordinated Interconnection operations,

[[Page 64824]]

and the health of the Bulk-Power System; and (3) proactively improving 
system reliability over time.
    547. It is important to keep in mind that, while the Commission has 
concerns regarding Requirement R3, the proposed Reliability Standard 
contains 17 Requirements relating to current day operations. With this 
perspective, while the Commission has identified a number of concerns 
with regard to IRO-005-1, we believe that the proposed Reliability 
Standard adequately addresses the important reliability goal of 
requiring a reliability coordinator to be continuously aware of 
conditions within its reliability coordinator area and include this 
information in its reliability assessments. Further, NERC should 
provide Measures and Levels of Non-Compliance elements for this 
proposed Reliability Standard. Nonetheless, the proposed Requirements 
set forth in this Reliability Standard are sufficiently clear and 
objective to provide guidance for compliance.
    548. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC submit a modification to IRO-005-1 that 
includes Measures and Levels of Non-Compliance. We propose 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, as discussed above, we propose that 
the ERO conduct a survey on IROL practices and experiences. The 
Commission may propose further modifications to IRO-005-1 based on the 
survey results.
h. Reliability Coordination--Transmission Loading Relief (IRO-006-3)
i. NERC Proposal
    549. 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.\224\ 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.\225\ It also references the equivalent Interconnection-wide 
congestion management methods used in the WECC and ERCOT regions.
---------------------------------------------------------------------------

    \224\ 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.
    \225\ The NERC glossary defines Interchange Distribution 
Calculator as ``The 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 6.
---------------------------------------------------------------------------

    550. On August 28, NERC submitted IRO-006-3 for approval, which 
replaces IRO-006-1. The new proposal would extend the PJM/MISO regional 
difference to SPP and contains some additional changes to the 
Attachment to the Reliability Standard. The comments submitted in 
response to the Preliminary Staff Assessment on IRO-006-1 apply equally 
to IRO-006-3.\226\
---------------------------------------------------------------------------

    \226\ We note that on September 29, 2006, NERC submitted Version 
2 of the same Reliability Standard (ERO-006-2) in Docket No. ER06-
1545-000, seeking approval of its TLR procedure pursuant to section 
205 of the FPA.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    551. The Staff Preliminary Assessment noted that IRO-006-1 does not 
address concerns expressed in the Blackout Report that call for 
``clarify[ing] that the transmission loading relief (TLR) process 
should not be used in situations involving an actual violation of an 
Operating Security Limit [SOL].'' \227\ It also noted that Requirement 
R2, which provides that a reliability coordinator experiencing a 
potential or actual SOL or IROL violation shall select from either a 
local or Interconnection-wide transmission loading relief procedure, 
could lead a reliability system operator to ``inappropriately use 
transmission loading relief procedures to mitigate actual IROL 
violations'' and, ``in doing so, valuable time that could be utilized 
to re-adjust the system by other, more effective, operating measures 
would be lost.'' \228\
---------------------------------------------------------------------------

    \227\ Blackout Report, Recommendation No. 31 at 163.
    \228\ Staff Preliminary Assessment at 69.
---------------------------------------------------------------------------

iii. Comments
    552. NERC explains that the TLR procedure is a method of addressing 
the impacts of bilateral transactions causing parallel flows. The 
procedure curtails bilateral transactions, which causes generation to 
be re-dispatched, which in turn changes the flow patterns on the 
transmission system. The curtailments are based on a power flow model 
of the Eastern Interconnection, and have the effect of reducing the 
loading on those lines over which the transactions are actually 
flowing.
    553. 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.\229\ It states that, while TLR procedures can be effective 
as a preventive tool to adjust and manage bilateral transactions so 
that limit violations do not occur, other options such as local or 
market area re-dispatch and transmission reconfiguration are more 
precise for a system operator to stay within SOLs and IROLs.
---------------------------------------------------------------------------

    \229\ NERC Comments at 49.
---------------------------------------------------------------------------

    554. NERC believes that transmission operators and reliability 
coordinators understand that the TLR procedure is not the only method 
for mitigating an SOL or IROL violation and that the proposed 
Reliability Standard--as one tool among many--is adequate and necessary 
to protect Bulk-Power System reliability. NERC states that ``it does 
not believe the recommendation of the Blackout Report that ``the [TLR] 
process should not be used in situations involving an actual violation 
of an Operating Security Limit [SOL]'' needs further discussion to 
determine possible changes to standard.'' \230\
---------------------------------------------------------------------------

    \230\ Id. at 50.
---------------------------------------------------------------------------

    555. ISO/RTO Council states that, although TLR should not be 
considered an emergency procedure,\231\ Requirement R1 of IRO-006-3 
does not require use of TLR procedures and permits the implementation 
of existing policies and procedures to correct transmission 
loading.\232\ It further states that Requirement R1 appropriately 
identifies a reliability coordinator as being responsible for actions 
related to transmission loading. As a result,

[[Page 64825]]

because Requirement R1 clearly does not specify the use of TLR, and 
instead explicitly calls for the use of appropriate tools available to 
the reliability coordinator, the ISO/RTO Council believes that IRO-006-
3 allows entities sufficient flexibility to ensure reliability.
---------------------------------------------------------------------------

    \231\ In its comments on EOP-002-0 regarding Capacity and Energy 
Emergencies, ISO/RTO Council elaborates that it ``agrees with FERC 
Staff's concerns that TLRs are not appropriate for addressing actual 
transmission emergencies, because TLRs are not a method that can be 
used quickly or predictably enough in situations where an operating 
security limit is close to, or actually being violated.''
    \232\ IRO-006-1, Requirement R1 states, ``[a] [r]eliability 
[c]oordinator shall take appropriate actions in accordance with 
established policies, procedures, authority, and expectations to 
relieve transmission loading.''
---------------------------------------------------------------------------

    556. However, ISO/RTO Council explains the limitations of TLR in 
EOP-002-0 that most ISOs and RTOs use re-dispatch to correct SOL and 
IROL violations instead of TLR procedures because re-dispatch is 
superior to TLR procedures for the purposes of ensuring system 
reliability. It further states that as a result, the applicability to 
an ISO or RTO region of any Reliability Standard that provides for the 
use of TLR procedures is not clear, and if applied, could actually be 
detrimental to reliability.
    557. ReliabilityFirst agrees in general with the Staff Preliminary 
Assessment. NYSRC comments that the concerns articulated by staff are 
not significant enough to prevent approval of the proposed Reliability 
Standard. MRO believes that IRO-006-3 should be modified to clarify the 
use of TLR as proposed by the Staff Preliminary Assessment due to the 
identified interpretation issue.
    558. CenterPoint contends that the ERCOT region should be 
explicitly exempted from these [IRO] Reliability Standards since ERCOT 
does not use TLR procedures. Instead, it manages congestion using 
procedures relevant to ERCOT market rules.
iv. Commission Proposal
    559. The Commission proposes to approve IRO-006-3 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard as discussed below.
    560. The Commission notes that NERC agrees that the TLR procedure 
is usually not effective by itself as a control measure to mitigate an 
IROL violation, the procedure is not intended to be effective in this 
manner and that it be combined with other effective methods such as 
reconfiguration, re-dispatch or load shedding until relief requested by 
the TLR process is achieved.\233\ The Commission is concerned, however, 
that the Requirements in IRO-006-3 do not sufficiently convey the 
availability of alternatives, nor highlight the inefficiency of TLR 
procedure which requires a lead time for implementation much longer 
than the allowable 30 minutes to return the system from IROL violation 
to a secure state. This could potentially mislead a transmission 
operator or reliability coordinator that is attempting to mitigate an 
IROL violation to first deploy the TLR procedure only to find out later 
that other more effective operating measures should have been used. In 
addition, we duly note ISO/RTO Council's comment that the applicability 
to an ISO or RTO region of any Reliability Standard that provides for 
the use of TLR procedures is not clear, and if applied, could actually 
be detrimental to reliability. Since the system is subject to cascading 
outages when it is in IROL violation, we have particular concern 
regarding the use of TLR to mitigate IROL violations and less so on its 
use on SOLs since the latter would not result in cascading outages.
---------------------------------------------------------------------------

    \233\ NERC Comments at 49.
---------------------------------------------------------------------------

    561. While NERC suggests that transmission operators and 
reliability coordinators understand that the TLR procedure is not the 
sole method for mitigating an SOL or IROL violation, the Commission 
notes that the Blackout Report suggests otherwise with regard to the 
causes of the August 2003 cascading blackout since the operator was 
first attempting to use TLR to mitigate an IROL violation only to find 
out it was ineffective.\234\ This led the Blackout Task Force to 
recommend that NERC ``clarify that the [TLR] process should not be used 
in situations involving an actual violation of an Operating Security 
Limit.'' \235\
---------------------------------------------------------------------------

    \234\ See Blackout Report at 63.
    \235\ Id. at 163.
---------------------------------------------------------------------------

    562. We propose that the Reliability Standard should also clearly 
provide the flexibility for ISOs and RTOs to rely on re-dispatch, as 
suggested by ISO/RTO Council. Accordingly, we propose to direct that 
NERC modify IRO-006-3 to (1) include a clear warning that TLR procedure 
is an inappropriate and ineffective tool to mitigate IROL violation and 
(2) to identify effective alternatives to use of the TLR procedure in 
situations involving an IROL violation.
    563. With regard to CenterPoint suggestion that the ERCOT region be 
explicitly exempted from compliance with IRO-006-3, we note that our 
regulations require that any such proposal must be developed through an 
open, stakeholder process and submitted to the Commission by the ERO.
    564. The Commission notes that Requirement R2.2 identifies the 
``WSCC Unscheduled Flow Mitigation Plan'' \236\ as an equivalent load 
relief procedure for use in the Western Interconnection. The referenced 
document contains governance, compensation, charges for use of the 
procedure and limitations on applicable facilities which are unusual in 
a Reliability Standard. The Commission believes that these issues are 
part of the transition to mandatory Reliability Standards and are 
mainly administrative in nature. The Commission believes that the WECC 
approach is superior to the national standard because it uses phase 
angle regulators, series capacitors and back-to-back DC lines to 
mitigate contingencies without curtailing transactions. The Commission 
proposes to approve its use.
---------------------------------------------------------------------------

    \236\ WSCC is an old reference to WECC.
---------------------------------------------------------------------------

    565. The Commission notes that Requirement R2.3 identifies section 
7 of the ERCOT Protocols as an equivalent load relief procedure for use 
in the Texas Interconnection. The Protocol contains significant details 
about the ERCOT market that are unusual in a Reliability Standard. The 
Commission believes that these issues are part of the transition to 
mandatory Reliability Standards and are mainly administrative in 
nature. The Commission believes that the ERCOT zonal LMP approach is 
superior to the national standard in that it uses generation re-
dispatch and pricing to mitigate congestion without curtailing 
transactions. The Commission proposes to approve its use.
    566. While the Commission has identified concerns with regard to 
IRO-006-3, we believe that the proposal serves an important purpose in 
ensuring reliability coordinators have a coordinated method for 
alleviating loadings on the transmission system when it becomes too 
congested to avoid potential SOL and IROL violations. It also includes 
a regional difference for reporting market flow information to the 
Interchange Distribution Calculator. The Commission believes that it is 
important for NERC to clarify that the TLR process is not the only, and 
perhaps not even the preferred, method to mitigate an SOL and 
especially IROL violation. The proposed Requirements set forth in IRO-
006-3 are sufficiently clear and objective to provide guidance for 
compliance.
    567. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC submit a modification

[[Page 64826]]

to IRO-006-3 that: (1) Includes a clear warning that 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.
i. Regional Difference to IRO-006-3: PJM/MISO/SPP Enhanced Congestion 
Management (Curtailment/Reload/Reallocation)
i. NERC Proposal
    568. IRO-006-003 provides for a regional difference for MISO, PJM 
and SPP. NERC explains that this 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.
ii. Staff Preliminary Assessment
    569. This regional difference was not addressed in the Staff 
Preliminary Assessment.
iii. Comments
    570. MISO and PJM, in a joint filing, contend that there is unduly 
discriminatory treatment of the market flows of MISO and PJM versus the 
generation-to-load impacts of non-market entities in the application of 
the TLR standard. They argue that NERC should modify IRO-006-3 and the 
MISO/PJM regional difference to require: (1) Netting of generation-to-
load impacts; (2) reporting to the Interchange Distribution Calculator 
all net generation-to-load impacts for both market and non-market 
transmission providers; and (3) modifying the curtailment threshold to 
a standard percentage for all impacts thus reported to the Interchange 
Distribution Calculator to a level that is technically feasible to 
implement and on a non-discriminatory basis. MISO and PJM also note 
that they, as well as SPP, have been working through various groups to 
achieve a consensus on these changes. According to MISO and PJM, these 
efforts were fruitful, but they were unable to complete the changes 
prior to NERC's April 6, 2006 submission of its Version 0 reliability 
standards for Commission approval. The Commission believes that SPP 
could experience the same problems identified by MISO and PJM.
iv. Commission Proposal
    571. The Commission believes that the comments and information 
presented by MISO and PJM are persuasive. However, before acting on 
this regional difference, the Commission invites comments to assure 
that we have a full and complete record on which to base our decision.
    572. The Commission notes that MISO and PJM indicate that their 
competition concerns are being addressed in discussions with NERC and 
other relevant entities. The Commission prefers that PJM, MISO and 
others continue to pursue a negotiated resolution rather than having 
the Commission impose a solution on market participants. Accordingly, 
the Commission will not propose to approve or remand this regional 
difference.
j. Procedures, Processes, or Plans to Support Coordination Between 
Reliability Coordinators (IRO-014-1)
i. NERC Proposal
    573. The stated purpose of IRO-014-1 is to ensure that each 
reliability coordinator's operations are coordinated such 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 (1) exchange of 
operating information and (2) coordination of operating plans.
ii. Staff Preliminary Assessment
    574. No substantive issues were identified for IRO-014-1.
iii. Comments
    575. No comments were submitted regarding IRO-014-1.
iv. Commission Proposal
    576. The Commission believes that IRO-014-1 contains sufficient 
details in the specification of the required procedures, processes or 
plans for a reliability coordinator to support coordination among it 
neighbors, and agreements that all reliability coordinators, as the 
only applicable entity, must take the indicated actions to ensure 
coordinated and reliable operations.
    577. For the reasons discussed above, the Commission proposes to 
approve Reliability Standard IRO-014-1 as just, reasonable, not unduly 
discriminatory or preferential, and in the public interest.
k. Notifications and Information Exchange Between Reliability 
Coordinators (IRO-015-1)
i. NERC Proposal
    578. Proposed Reliability Standard 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. This exchange of reliability-related 
information among reliability coordinators facilitates situation 
awareness.
ii. Staff Preliminary Assessment
    579. No substantive issues were identified for IRO-015-1.
iii. Comments
    580. No comments were submitted regarding IRO-015-1.
iv. Commission Proposal
    581. The Commission believes that IRO-015-1 contains sufficient 
Requirements to ensure that reliability coordinators inform and 
exchange information with other reliability coordinators, as the only 
applicable entity, to ensure coordinated operations.
    582. For the reasons discussed above, the Commission proposes to 
approve Reliability Standard IRO-015-1 as just, reasonable, not unduly 
discriminatory or preferential, and in the public interest.
l. Coordination of Real-Time Activities Between Reliability 
Coordinators (IRO-016-1)
i. NERC Proposal
    583. 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. Where a disagreement 
arises, IRO-016-1 requires that reliability coordinators work with one 
another until a system problem is resolved or implement the more 
conservative solution.
ii. Staff Preliminary Assessment
    584. No substantive issues were identified for IRO-016-1.
iii. Comments
    585. No comments were submitted regarding IRO-016-1.
iv. Commission Proposal
    586. The Commission believes that IRO-016-1 contains sufficient

[[Page 64827]]

requirements for a reliability coordinator to inform, discuss and 
identify a solution with other reliability coordinators to prevent or 
resolve a problem that requires joint actions from all affected 
reliability coordinators as the only applicable entity. It also clearly 
articulates binding and conservative corrective actions to be taken in 
the event that an agreement cannot be reached among them.
    587. For the reasons discussed above, the Commission proposes to 
approve Reliability Standard IRO-016-1 as just, reasonable, not unduly 
discriminatory or preferential, and in the public interest.
8. MOD: Modeling, Data, and Analysis
a. Overview
    588. The Modeling, Data, and Analysis group of Reliability 
Standards are intended to standardize methodologies and system data 
needed for traditional transmission system operation and expansion 
planning, reliability assessment, and the calculation of available 
transmission capacity (ATC) in an open access environment. The 23 
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.\237\ The second category covers steady-state and dynamics 
data and models.\238\ The third category covers actual and forecast 
demand data.\239\ The fourth category covers the verification of 
generator real and reactive power capability.\240\
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    \237\ MOD-001-0 through MOD-009-0.
    \238\ MOD-010-0 through MOD-015-0.
    \239\ MOD-016-0 through MOD-021-0.
    \240\ MOD-024-1 through MOD-025-1.
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OATT Reform NOPR and the MOD Standards
    589. The Commission has been considering ATC, TTC, CBM and TRM 
calculation issues in Docket Nos. RM05-17-000 and RM05-25-000, and is 
addressing them in the OATT Reform NOPR.\241\ Among other things, the 
OATT Reform NOPR discusses the need for consistency and transparency of 
ATC, TTC, CBM, and TRM. It proposes that public utilities, working 
through NERC/NAESB, would use the guidelines in the OATT Reform NOPR to 
revise the relevant standards and business practices, and asks for 
comments on certain proposals. It also recognizes that there are still 
many unspecified elements in the calculation processes and development 
of modeling assumptions, and deficiencies in data exchange that may 
have a negative impact on both transmission system reliability and 
competition.\242\
---------------------------------------------------------------------------

    \241\ OATT Reform NOPR, 71 FR 32636 at 32658.
    \242\ Id., 71 FR at 32654 and 32667.
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    590. The industry 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 
\243\ (AFC)/ATC Task Force to review NERC's standards on ATC, which 
issued a final report in 2005.\244\ Based on the recommendations in the 
NERC Report, NERC has begun two Standards Authorization Request (SAR) 
proceedings to revise the standards on ATC.\245\ NAESB has also begun a 
proceeding to develop business practice standards to enhance the 
processing of transmission service requests, which affects the ATC 
calculation.
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    \243\ AFC is a methodology that first calculates available 
capacity on a flowgate-AFC, and transfers that value into ATC by 
dividing AFC with the associated flowgate distribution factor. After 
ATC is determined, TTC is calculated from ATC for posting on OASIS. 
This method is different from NERC's original ATC calculation, where 
TTC is calculated in a first step and then used to determine ATC by 
reducing TTC with capacity needed for existing commitments and 
reserve margins.
    \244\ 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: ftp://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf
.

    \245\ 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.
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Staff Preliminary Assessment
    591. Staff expressed concerned that fourteen of the twenty-three 
Reliability Standards in this group apply to regional reliability 
organization, which is not a user, owner, or operator of the Bulk-Power 
System.
General Comments
    592. NERC comments that it has a team in place to address the 
regional reliability organization applicability issue and will submit 
an action plan and schedule in November 2006 for completing the fill-
in-the-blank standards. NERC expects that it will take approximately 
three years to complete the process, and will prioritize standards that 
require the most immediate revision.
    593. CenterPoint advocates eliminating many of the MOD Reliability 
Standards or consolidating them into planning or operating standards. 
CenterPoint reasons that, to the extent the process-oriented 
Reliability Standards are necessary, the ``fill-in-the-blank'' 
standards are necessary; however, it is impractical to require that 
each region use identical practices in building and validating its 
models. CenterPoint adds that, should the Reliability Standards be 
approved by the Commission, ERCOT should be exempt from those that 
address transfer capability because ERCOT does not have any inter-
control area transfers and does not use the NERC methodologies.
Commission Proposal
    594. As we discussed in the Common Issues section above describing 
fill-in-the-blank Reliability Standards, we propose to seek additional 
information before acting on the Reliability Standards that require the 
regional reliability organization to provide criteria on procedures.
    595. While we agree with CenterPoint that some of the MOD 
Reliability Standards could be grouped into planning or operating 
standards, we will not propose any such modification, but rather, leave 
it to the discretion of the ERO. Regarding CenterPoint's suggestion 
that ERCOT should be exempt from Reliability Standards that address 
available transfer capability, the Commission will consider any 
regional difference at the time it is submitted by NERC for Commission 
review. Therefore, if ERCOT wishes to request a regional difference it 
must do so through the ERO process.
b. Documentation of Total Transfer Capability and Available Transfer 
Capability Calculation Methodologies (MOD-001-0)
i. NERC Proposal
    596. NERC states that 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 the 
regional reliability organizations to develop their respective methods 
for determining TTC and ATC and to make those methodologies available 
to others for review. The Reliability Standard contains two 
Requirements directing each regional reliability organization to: (1) 
Develop and document a regional TTC and ATC methodology in conjunction 
with its members; and (2)

[[Page 64828]]

post the most recent version of its TTC and ATC methodology at a Web 
site accessible by NERC, the regional reliability organizations, and 
transmission users.
    597. The first Requirement specifies nine items that the regional 
reliability organization must include in its methodology for 
determining its TTC and ATC values. Most of these items call for 
descriptions on how TTC and ATC values are determined and what 
assumptions are used. Two items require the regional reliability 
organization to take into account the reservations and schedules for 
transactions occurring inside and outside the transmission provider's 
system. One item specifies a time and frequency for calculating and 
posting TTC and ATC values.
ii. Staff Preliminary Assessment
    598. Staff identified MOD-001-0 as a ``fill-in-the-blank'' standard 
that applies to the regional reliability organization. Staff expressed 
concern that industry historically used inconsistent calculation 
methodologies and stated that this inconsistency could have an undue 
negative impact on competition.
iii. Comments
    599. Although NERC acknowledges that proposed Reliability Standard 
MOD-001-0 needs improvement, it urges that the Commission approve it. 
NERC explains that the final version of the ATC/TTC/AFC Revision SAR 
proposes a method for calculating ATC and requires that specific 
reliability practices be incorporated into the ATC calculation and 
coordination methodologies. Further, NERC advises that a requirement 
will be added to enhance documentation of the calculation.
    600. MRO acknowledges that, because TTC and ATC values must satisfy 
certain principles, which balance both technical and commercial issues 
from each of the regions, there may be differences in the calculation 
of these values from the different regions. However, MRO adds that the 
parties in the Eastern Interconnection must agree to the values, 
calculations, and methodologies which flow across the borders of 
various regions and system operators. MRO states that these should be 
transparent and agreements should be based on rational, technical 
requirements.
    601. ReliabilityFirst submits that it generally agrees with staff's 
evaluation that, to ensure consistency, procedures developed by the 
individual regions need to be combined. Similarly, TAPS advises that 
there are significant flaws and undue competitive impacts in the way 
the Reliability Standard is currently proposed. TAPS urges the 
Commission to make the calculations related to this Reliability 
Standard transparent, consistent, and regionally-based.
iv. Commission Proposal
    602. MOD-001-0 is a ``fill-in-the-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. Because the regional procedures have 
not been submitted to the Commission, it is not possible to determine 
at this time whether MOD-001-0 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 will not propose to accept or remand this 
Reliability Standard until the ERO submits additional information. In 
the interim, compliance with MOD-001-0 should continue on its current 
basis, and the Commission considers compliance with the Reliability 
Standard to be a matter of good utility practice. Although we do not 
propose any action with regard to MOD-001-0 at this time, we address 
our concerns regarding this Reliability Standard below. The concerns we 
discuss below are consistent with the OATT Reform NOPR.\246\
---------------------------------------------------------------------------

    \246\ OATT Reform NOPR at ] 155-70.
---------------------------------------------------------------------------

    603. The Reliability Standard only requires that the regional 
reliability organization document its ATC and TTC methodology and post 
that documentation. The Reliability Standard does not contain clear 
Requirements on how ATC and TTC should be calculated, which has 
resulted in diverse interpretations of ATC, TTC, and the development of 
various calculation methodologies, modeling assumptions, and data 
exchange protocols by various entities.\247\ This creates potential 
reliability issues and an opportunity to unduly discriminate against 
competitors.
---------------------------------------------------------------------------

    \247\ For example, there are two primary ATC calculation 
methodologies: the contract path approach and the flowgate approach. 
However, the ATC values that result from application of either 
method should largely be the same if consistent data inputs and 
modeling assumptions are used. See OATT Reform NOPR, 71 FR 32653.
---------------------------------------------------------------------------

    604. Further, the different approaches in calculation of ATC/
AFC,\248\ TTC, and lack of clear requirements for calculation of 
existing transmission commitments (ETC) \249\ could also create an 
undue negative impact on competition. For example, NERC has not 
proposed either a definition or Reliability Standard on how ETC should 
be determined. This could allow transmission providers to set aside 
more capacity for native load than is needed, and ultimately block 
capacity that would otherwise be available to unaffiliated transmission 
customers. This also gives broad discretion to a transmission provider 
to determine how to model power transfers and associated loop flows 
that impact the neighboring systems reliability. We believe that this 
Reliability Standard should, at a minimum, provide a framework for the 
ATC, TTC, and ETC calculation.
---------------------------------------------------------------------------

    \248\ Available Flowgate Capability is a method widely used in 
the Eastern Interconnection but there is no NERC definition for that 
term.
    \249\ ETC includes transmission capacity set aside for both 
native load and transmission reservations.
---------------------------------------------------------------------------

    605. MOD-001-0 requires that the regional reliability organization 
develop and post its methodology on TTC and ATC, but only requires a 
narrative description of a few elements of the TTC and ATC calculation. 
We believe that this Reliability Standard should include a requirement 
that applicable entities make available a comprehensive list of 
assumptions and contingencies underlying ATC and TTC calculations. We 
believe that such documentation should include mathematical algorithms, 
process flow diagrams, data inputs, identification of flowgates, and 
modeling assumptions used to perform the TTC and ATC calculations, 
consistent with those proposed in the OATT Reform NOPR.
    606. We are further concerned that the Reliability Standard does 
not clearly define the data to be shared among transmission service 
providers. We believe that MOD-001-0 could be improved by identifying a 
detailed list of information to be shared. This is consistent with the 
OATT Reform NOPR, which proposes that, at a minimum, the following data 
should 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 calculation frequency; and (7) source/sink 
modeling identification.
    607. In addition, the Commission notes that MOD-001-0 
inappropriately combines the requirements for TTC and ATC methodology 
into one Reliability Standard. TTC and ATC serve two different purposes 
and are calculated through different calculation processes. We believe 
that MOD-001-0 should

[[Page 64829]]

address only the ATC and AFC requirements while the TTC requirements 
should be addressed in a separate Reliability Standard such as FAC-012-
1, as discussed below.
    608. The NERC glossary does not substantially differentiate between 
the definition of TTC (as used in MOD-001-0) \250\ and transfer 
capability (as used in FAC-012-1).\251\ Thus, there are two Reliability 
Standards to measure essentially the same thing: One Reliability 
Standard calculates TTC using one set of data and modeling assumptions 
presumably for use in evaluating transmission service requests, and 
another Reliability Standard calculates transfer capability for in-
house use in planning and operations studies. This will not only cause 
confusion, but also opportunities for discrimination against 
transmission customers. We believe that the TTC calculation methodology 
should be addressed under FAC-012-1, which standardizes transfer 
capability methodology.
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    \250\ 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.'' NERC 
glossary at 14.
    \251\ Transfer Capability is defined in 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 15.
---------------------------------------------------------------------------

    609. We reiterate our concern expressed in the OATT Reform NOPR 
that modeling assumptions are a crucial element in the calculation of 
ATC.\252\ We believe that NERC should develop a set of consistent 
assumptions as a part of MOD-001-0 for use in ATC and AFC 
determinations. Consistent with the OATT Reform NOPR, we believe that 
the assumptions in the calculation of ATC and AFC should be used 
consistently among transmission providers to the maximum extent 
practicable. In general, the Commission believes that the assumptions 
used in the determination of ATC and AFC should be consistent with 
those used for planning the expansion or operation of the Bulk-Power 
System. Consequently, the models for short- and long-term ATC and AFC 
calculation should be developed using consistent assumptions regarding 
the load level, generation dispatch, transmission and generation 
facilities maintenance schedules, contingency outages and topology as 
those used for expansion planning and operations. Consistent with the 
OATT Reform NOPR, we believe that the long-term ATC and AFC models 
should rely to the maximum extent possible on the same assumptions 
regarding new transmission and generation facility additions and 
retirements as those used in the planning for expansion. Specifically, 
MOD-001-0 should contain a Requirement that long-term ATC (one year and 
longer) be based on the calculation that uses the same power flow 
models, assumptions regarding load, generation dispatch, special 
protection systems, post contingency switching, and transmission and 
generation facility additions and retirements as those used in the 
expansion planning for the same time frame.
---------------------------------------------------------------------------

    \252\ OATT Reform NOPR at P 166.
---------------------------------------------------------------------------

    610. Finally, the applicability section identifies that the 
Reliability Standard applies to regional reliability organizations. 
Consistent with our discussion above, we believe that NERC should 
identify the applicable entities in terms of users, owners, and 
operators of the Bulk-Power System.\253\
---------------------------------------------------------------------------

    \253\ We note that our observation here also applies to MOD-002, 
MOD-003, MOD-004, MOD-005, MOD-008, MOD-009, MOD-011, MOD-013, MOD-
014, MOD-015, MOD-016, MOD-024, and MOD-025.
---------------------------------------------------------------------------

c. Review of Transmission Service Provider Total Transfer Capability 
and Available Transfer Capability Calculations and Results (MOD-002-0)
i. NERC Proposal
    611. 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 of TTC and ATC; and (3) provide the results of 
its most current reviews to NERC on request within 30 calendar days.
ii. Staff Preliminary Assessment
    612. Staff identified no substantive issues other than the fact 
that MOD-002-0 is a ``fill-in-the-blank'' standard and that the 
standard applies to the regional reliability organization.
iii. Comments
    613. The Commission received no specific comments regarding MOD-
002-0.
iv. Commission Proposal
    614. MOD-002-0 is a ``fill-in-the-blank'' Reliability 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. 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 will not propose to 
approve or remand 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.
d. Regional Procedure for Input on Total Transfer Capability and 
Available Transfer Capability Methodologies and Values (MOD-003-0)
i. NERC Proposal
    615. MOD-003-0 defines how a transmission user can submit its 
concerns regarding ATC/TTC calculation methodologies and values. It 
requires each regional reliability organization to: (1) Develop and 
document a procedure on how a transmission user can input their 
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.
ii. Staff Preliminary Assessment
    616. The Staff Preliminary Assessment noted that MOD-003-0 is a 
``fill-in-the-blank'' standard. It also raised concern that MOD-003-0 
does not provide a consistent procedure for transmission users to input 
concerns or questions regarding the methodology for calculation of TTC 
and ATC and resulting TTC and ATC values, nor does it provide a 
consistent procedure for

[[Page 64830]]

how these questions or concerns will be addressed.
iii. Comments
    617. The Commission received no comments regarding MOD-003-0.
iv. Commission Proposal
    618. MOD-003-0 is a ``fill-in-the-blank'' standard that requires 
each regional reliability organization to develop and document a 
procedure to on how a transmission user can input its concerns 
regarding the TTC and ATC methodologies of a transmission service 
provider. 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 will not propose to accept or remand 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.
e. Documentation of Regional Reliability Organization Capacity Benefit 
Margin Methodologies (MOD-004-0)
i. NERC Proposal
    619. NERC states that the purpose of MOD-004-0 is to promote the 
consistent and uniform application of transmission transfer capability 
margin. MOD-004-0 addresses the development of a regional methodology 
for CBM.\254\ The Reliability Standard requires each regional 
reliability organization to: (1) Develop and document a regional CBM 
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.
---------------------------------------------------------------------------

    \254\ 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.
---------------------------------------------------------------------------

    620. The first Requirement specifies ten items that the regional 
reliability organization must include and explain in its CBM 
calculation method. In addition, the Reliability Standard requires that 
other regional reliability organization-specific items be explained 
along with their use in determining CBM values. These requirements 
specify that calculation of CBM be consistent with the generation 
planning criteria, and that generation outages simulated in a 
transmission provider's CBM calculation be restricted to those 
generators located within the transmission provider's system. It is 
also required that CBM should be preserved only for the load within the 
control area. The allocation process of the CBM should be identified. 
In addition, it requires that the sum of the CBM values allocated to 
all interfaces at one control area shall not exceed the portion of the 
generation reliability requirement that is to be provided from outside 
resources. The remaining items require a description of the rationale 
regarding the assumptions used for CBM calculation. Finally, it 
requires a description of the formal process and rational for the 
regional reliability organization to grant any variances to individual 
transmission providers from the regional reliability organization's CBM 
methodology.
ii. Staff Preliminary Assessment
    621. The Staff Preliminary Assessment noted that MOD-004-0 is a 
``fill-in-the-blank'' standard. Further, while MOD-004-0 requires each 
regional reliability organization to develop and document a regional 
CBM methodology, it does not specify how CBM is determined and 
allocated across transmission paths. Staff expressed concern that the 
Reliability Standard does not address the effect of associated 
transmission service requirements and curtailment provisions on 
transmission customers nor does it specify the criteria used in 
determining whether or not to include generation resources, reserves, 
and loads in its methodology as described in four of the Requirements 
(R1.5, R1.6, R1.9, and R1.10).
iii. Comments
    622. NERC points out that the CBM/TRM Revisions Standard 
Authorization Request (SAR) proposes requiring crisp and clear 
calculation documentation and making various components of the 
methodology mandatory to ensure consistency.
    623. TAPS agrees with staff's evaluation of MOD-004-0. TAPS states 
that the proposed Reliability Standard has significant flaws and will 
harm competition if accepted in its current form. For example, TAPS 
refers to the significant potential for abuse because transmission 
providers have flexibility in the calculation of CBM. Further, TAPS 
questions how CBM can be viewed as a Reliability Standard if it is 
optional to the transmission provider. TAPS urges the Commission to 
make the calculations related to this standard transparent, consistent, 
and regionally-based.
iv. Commission Proposal
    624. MOD-004-0 is a ``fill-in-the-blank'' Reliability Standard that 
requires each regional reliability organization to develop and document 
a regional CBM methodology. Because the regional CBM methodologies have 
not been submitted to the Commission, it is not possible for 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 will not propose to accept or remand 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.
    625. Although we do not propose any action with regard to MOD-004-0 
at this time, we address our concerns regarding the Reliability 
Standard below.
    626. We share TAPS' concern that MOD-004-0 may contain significant 
flaws and may unduly impact competition. The Commission expressed 
similar concerns with the CBM calculation in the OATT Reform NOPR. The 
lack of consistent criteria and clarity with regard to the entity on 
whose behalf CBM has been set aside has the potential to result in the 
transmission provider setting aside capacity that it might not 
otherwise need to, thus increasing costs for native load customers and 
blocking third party uses of the transmission system.\255 \
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    \255\ The Commission has explained that the pro forma OATT 
requires both transmission customers and transmission providers 
using the transmission system to serve network load (including 
bundled retail native load) to designate their resources and loads 
so that the transmission customers and transmission providers would 
have no incentive to designate network resources above their needs 
and, in so doing, tie up valuable transmission capacity. Aquila 
Power Corp. v. Entergy Services, Inc., 90 FERC ] 61,260, reh'g 
denied, 92 FERC ] 61,064 (2000), reh'g denied, 101 FERC] 61,328 
(2002), aff'd sub nom. Entergy Services, Inc. v. FERC, 375 F.3d 1204 
(D.C. Cir. 2004).
---------------------------------------------------------------------------

    627. We also share TAPS' concern that the calculations related to 
this Reliability Standard must be transparent and consistent. We are 
concerned with the latitude that transmission providers have when 
preserving a portion of transfer capability for CBM. There are

[[Page 64831]]

no consistent industry-wide standards for determining how much transfer 
capability should be set aside as CBM and how that amount should be 
allocated to interfaces. Therefore, we believe that MOD-004-0 could be 
improved by providing more specific Requirements on how CBM should be 
determined and allocated to interfaces.
    628. In response to TAPS's question about how CBM can be viewed as 
a Reliability Standard if it is optional to the Transmission Provider, 
our understanding is that transmission providers that opt not to use 
CBM could instead set aside transmission margin (needed to meet the 
generation Reliability Standard) either through ETC or TRM. Obviously, 
CBM is not the only way to preserve transmission margin. However, if 
the Reliability Standard is not clear regarding the method to calculate 
transmission margin, it may cause double-counting of transmission 
margins and reduction of ATC. Therefore, we believe that MOD-004-0 
could be improved by including a provision ensuring that CBM, TRM, and 
ETC cannot be used for the same purpose, such as the loss of the 
identical generation unit. Without a clear requirement against double-
counting of margins causing ATC decrease, there is a possibility that 
such double-counting may be used to prevent the non-affiliated third 
party's access to the transmission system.
f. Procedure for Verifying Capacity Benefit Margin Values (MOD-005-0)
i. NERC Proposal
    629. The Reliability Standard specifies the requirements regarding 
the periodic review of a transmission service provider's adherence to 
the regional reliability organization's CBM methodology. This 
Reliability Standard has three Requirements. The first Requirement 
calls for each regional reliability organization to develop and 
implement a procedure to review at least annually the CBM calculations 
and the resulting values determined by member transmission service 
providers. The second Requirement mandates that the regional 
reliability organization document its CBM review procedure and make it 
available to NERC on request within 30 calendar days. The third 
Requirement specifies that the regional reliability organization must 
make the results of the most current CBM review available to NERC on 
request, within 30 calendar days. There are several sub-requirements 
specifying the regional reliability organization's CBM review process, 
including an assurance that the transmission provider's CBM components 
are calculated consistently with its planning criteria, and a 
Requirement that CBM values are at least annually updated and made 
available to the regional reliability organization, NERC, and 
transmission users.
ii. Staff Preliminary Assessment
    630. Staff Preliminary Assessment noted that although MOD-005-0 
requires each regional reliability organization to review the CBM 
calculations and the resulting values, it does not require a consistent 
and uniform calculation of CBM.
iii. Comments
    631. The Commission received no comments regarding MOD-005-0.
iv. Commission Proposal
    632. MOD-005-0 is a ``fill-in-the-blank'' standard that requires 
the regional reliability organization to develop and implement a 
procedure to review the CBM calculations and the resulting values and 
to make the documentation of the results of the CBM review available to 
NERC and others. 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, reasonable, not unduly 
discriminatory or preferential, and in the public interest.'' 
Accordingly, the Commission will not propose to accept or remand this 
Reliability Standard until the ERO submits additional information. 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.
g. Procedure for the Use of Capacity Benefit Margin Values (MOD-006-0)
i. NERC Proposal
    633. NERC states that the purpose of MOD-006-0 is to promote the 
consistent and uniform use of transmission transfer capability margins 
calculations among transmission system users. MOD-006-0 requires a 
transmission service provider to document and post its procedures on 
the use of CBM. Specifically, the Reliability Standard requires that 
each transmission service provider document its procedure explaining 
scheduling of energy against CBM. It also requires the transmission 
service provider to make that procedure available on a Web site 
accessible by the regional reliability organization, NERC, and 
transmission users.
ii. Staff Preliminary Assessment
    634. Staff stated that it was concerned that proposed Reliability 
Standard MOD-006-0 does not require a consistent and uniform 
calculation of CBM.
iii. Comments
    635. The Commission received no comments regarding MOD-006-0.
iv. Commission Proposal
    636. The Commission proposes to approve MOD-006-0 as mandatory and 
enforceable. In addition, we propose to direct NERC to modify the 
Reliability Standard, as discussed below.
    637. As discussed above regarding MOD-004-0, we are concerned that 
there is an opportunity to double-count transmission margins CBM and 
TRM, which will result in lower ATC values. Without a clear requirement 
against double-counting margins, this may be used to prevent non-
affiliated third party access to the transmission system. Therefore, we 
propose to direct the ERO to modify this Reliability Standard to 
include a provision that will ensure that CBM and TRM cannot be used 
for the same purpose.
    638. Requirement R1.2 of MOD-006-0 calls for CBM to be used by a 
load-serving entity that experiences a generation deficiency only when 
its transmission provider simultaneously experiences ``transmission 
constraints relative to imports of energy on its transmission system.'' 
It is our understanding that a load-serving entity can experience a 
generation deficiency without the simultaneous transmission constraint 
on its transmission service provider's system. Therefore, we propose 
that the ERO modify Requirement R1.2 so that concurrent occurrence of 
transmission constraints is not a required condition for CBM usage.
    639. Moreover, the Reliability Standard does not specify how the 
generation deficiency is identified. We propose to direct that the ERO 
define ``generation deficiency'' based on a specific energy emergency 
alert level (specified in the EOP Reliability Standards) that triggers 
CBM usage.
    640. The Commission believes that CBM should be used only when the 
load-serving entity's local generation capacity is insufficient to meet 
balancing Reliability Standards. Moreover, a load-serving entity that 
has sufficient generation resources within its balancing authority to 
meet the balancing Reliability Standards should

[[Page 64832]]

not need to preserve capacity for CBM at all. In addition, we believe 
that CBM should have a zero value in the calculation of non-firm ATC. 
Based on this guidance, we propose 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.
    641. Requirement R1.2 of MOD-006-0 provides that CBM shall only be 
used if the load-serving entity calling for its use is experiencing a 
generation deficiency. The applicability section, however, applies to 
only transmission service providers and not load-serving entities. The 
Commission believes that the applicability section should be expanded 
to include the entities that actually use CBM, such as load serving 
entities.
    642. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-006-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose directing 
that NERC 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 load serving entities.
h. Documentation of the Use of Capacity Benefit Margin (MOD-007-0)
i. NERC Proposal
    643. NERC states that the purpose of MOD-007-0 is to promote the 
consistent use of transmission transfer capability margin calculations 
among transmission system users. MOD-007-0 requires transmission 
service providers that use CBM to report and post its use. This 
Reliability Standard has two Requirements. The first Requirement calls 
for each transmission provider that uses CBM, at the request of a load-
serving entity, to report that use to the regional reliability 
organization, NERC and the transmission users. The transmission service 
provider is not required to report the occasions when CBM is sold on a 
non-firm basis. The second Requirement is that, for any use of CBM 
concurrent with an energy emergency situation, the transmission service 
provider must disclose and post circumstances, duration, and the amount 
of CBM used on a Web site accessible by the regional reliability 
organization, NERC, and transmission users.
ii. Staff Preliminary Assessment
    644. Staff noted that MOD-007-0 does not specify how CBM should be 
preserved, which is important to allow both transmission providers and 
transmission customers to meet their respective generation reliability 
criteria.
iii. Comments
    645. The Commission received no comments regarding MOD-007-0.
iv. Commission Proposal
    646. The Commission proposes to approve MOD-007-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    647. Requirement R1 of MOD-007-0 provides that the use of CBM by 
the load-serving entity shall be documented. However, the applicability 
section of MOD-007-0 applies to only transmission service providers and 
not load-serving entities. The Commission believes that the 
applicability section should be expanded to include the entities that 
actually use CBM, such as load-serving entities.
    648. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-007-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose directing 
that NERC to submit a modification to MOD-007-0 that expands the 
applicability section to include the entities that actually use CBM, 
such as load-serving entities.
i. Documentation and Content of Each Regional Transmission Reliability 
Margin Methodology (MOD-008-0)
i. NERC Proposal
    649. NERC notes that the purpose of MOD-008-0 is to promote the 
consistent application of transmission transfer capability margin 
calculations among transmission service providers and transmission 
owners. MOD-008-0 requires the development and posting of a regional 
methodology for TRM, a transmission capacity that is preserved to 
provide reasonable assurance that the interconnected transmission 
network will remain secure under various system conditions. The 
Reliability Standard specifies two Requirements for the regional 
reliability organization to: (1) Develop and document a regional TRM 
methodology in conjunction with its members, and (2) post the most 
recent version of its TRM methodology on a Web site accessible by NERC, 
the regional reliability organizations, and transmission users.
    650. The first Requirement specifies five items that the regional 
reliability organization must include and explain in its TRM 
calculation method. In addition, the Reliability Standard allows other 
items specific to a regional reliability organization to be explained 
along with their use in determining TRM values, if such items exist. 
Some of these items require the regional reliability organization to 
specify TRM update frequency, describe how TRM values are accounted for 
in ATC calculations, and detail which uncertainties are accounted for 
in TRM. The regional reliability organization must also describe how 
transmission capacity preserved for TRM can be sold for non-firm 
services.
ii. Staff Preliminary Assessment
    651. Staff noted that although MOD-008-0 requires each regional 
reliability organization to develop and document a Regional TRM 
methodology, it does not specify how TRM is determined and allocated 
across transmission paths. Staff also stated that the Requirement R1.5 
does not specify the criteria for granting variances from the regional 
TRM methodology.
iii. Comments
    652. NERC points out that a Reliability Standard is under 
development that will make various components of the methodology 
mandatory to ensure consistency.
    653. MRO advocates that MOD-008-0 should specify the criteria for 
granting variances.
iv. Commission Proposal
    654. MOD-008-0 is a ``fill-in-the-blank'' Reliability Standard that 
requires each regional reliability organization to develop a 
methodology for determining TRM and to make the methodology available 
to others for review. Because the regional methodologies have not been 
submitted to the Commission, it is

[[Page 64833]]

not possible to determine at this time whether MOD-008-0 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 will not propose to 
accept or remand this Reliability Standard until the ERO submits 
additional information. In the interim, compliance with MOD-008-0 
should continue on its current basis, and the Commission considers 
compliance with the Reliability Standard to be a matter of good utility 
practice.
    655. Although we do not propose any action with regard to MOD-008-0 
at this time, we address our concerns regarding this Reliability 
Standard below.
    656. We are concerned about the lack of clear requirements on how 
TRM should be calculated and allocated across the paths. In addition, 
the lack of consistent criteria and clarity with regard to the entity 
on whose behalf TRM has been set aside may result in the transmission 
provider setting aside excess capacity, thus increasing costs for 
native load customers, and blocking third party uses of the 
transmission system. We seek comments on how TRM is currently 
calculated and allocated across the paths, and what would be a 
recommended approach for the future.
j. Procedure for Verifying Transmission Reliability Margin Values (MOD-
009-0)
i. NERC Proposal
    657. MOD-009-0 specifies the Requirements for establishing a 
procedure for periodic review of a transmission provider's adherence to 
the relevant regional reliability organization's TRM methodology. This 
Reliability Standard has three Requirements. The first Requirement 
calls for 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. The second Requirement is that the 
regional reliability organization documents its TRM review procedure 
and makes that available to NERC on request within 30 calendar days. 
The third Requirement specifies that the reliability regional 
organization must make the documentation of the results of the most 
current TRM review available to NERC on request, within 30 calendar 
days.
ii. Staff Preliminary Assessment
    658. Staff noted that MOD-009-0 does not provide a consistent 
procedure for review of TRM calculations and the resulting values.
iii. Comments
    659. The Commission received no specific comments regarding MOD-
009-0.
iv. Commission Proposal
    660. MOD-009-0 is a ``fill-in-the-blank'' Reliability Standard that 
requires each regional reliability organization to develop its 
procedure for review of TRM calculations and the resulting values. 
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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
MOD-009-0 should continue on its current basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice.
k. Steady-State Data for Modeling and Simulation of Interconnected 
Transmission System (MOD-010-0)
i. NERC Proposal
    661. The purpose of this Reliability Standard is to establish 
consistent data requirements, reporting procedures, and system models 
to be used in the 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 entities 
specified in Requirement R1 of MOD-011-0. Data is to be provided within 
the determined time schedule or upon request if no time schedule 
exists.
ii. Staff Preliminary Assessment
    662. Staff noted that MOD-010-0 does not include the planning 
authority as an applicable entity. The inclusion of the planning 
authority is necessary in the applicability section of the 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.
iii. Comments
    663. MRO and ReliabilityFirst state that they generally agree with 
staff's evaluation of MOD-010-0. However, in response to the staff 
comment regarding inappropriate exclusion of the planning authority 
from the Reliability Standard's applicability, ReliabilityFirst points 
out that the information required by the Reliability Standard 
originates with the transmission planner and resource planner who, 
ultimately, provide such information to the planning authority. 
Similarly, PG&E states that a planning authority does not develop, and 
cannot provide such information and is rightly not included in the 
applicability section of the standard. PG&E explains that MOD-010-0 
requires transmission owners, transmission planners, generator owners, 
and resource planners to provide appropriate equipment characteristics, 
system data, and existing and future interchange schedules in 
compliance with Interconnection regional steady-state or dynamic 
modeling and simulation data requirements and reporting procedures.
iv. Commission Proposal
    664. The Commission proposes to approve MOD-010-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    665. We propose that MOD-010-0 should add a new requirement to have 
the transmission owners also provide the list of the contingencies they 
use in performing system operation and planning studies. We believe 
that access to such information will enable neighboring systems to 
accurately study their effects on their own systems.
    666. In addition, we propose that the Reliability Standard should 
be modified to apply to the planning authority. The planning authority 
is the entity responsible for 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 commenters that the planning authority should be omitted 
from the applicability section because it merely gets the data from the 
others. We believe that the planning authority plays a significant role 
in integration of the data.
    667. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the

[[Page 64834]]

purpose represented to the Commission by the ERO and that it will 
improve the reliability of the nation's Bulk-Power System, the 
Commission proposes to approve Reliability Standard MOD-010-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose to direct 
that 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.
l. Maintenance and Distribution of Steady-State Data Requirements and 
Reporting Procedures (MOD-011-0)
i. NERC Proposal
    668. The purpose of MOD-011-0 is to establish consistent data 
requirements, reporting procedures, and system models to be used in the 
reliability analysis. MOD-011-0 requires the regional reliability 
organization within an Interconnection to develop comprehensive steady-
state data requirements and reporting procedures needed to model and 
analyze the steady-state conditions for each of the three NERC 
Interconnections. The regional reliability organizations within an 
Interconnection are required to:
    (1) Document their Interconnection's data requirements and 
reporting procedures;
    (2) Review the data requirements and reporting procedures at least 
every five years; and
    (3) Make the data requirements and reporting procedures available 
on request to the regional reliability organizations, NERC, and all 
users of the interconnected transmission system.
ii. Staff Preliminary Assessment
    669. Staff noted that MOD-011-0, identified as a ``fill-in-the-
blank'' standard, does not include the planning authority in the 
Requirements section. The planning authority is the entity responsible 
for 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.
iii. Comments
    670. PG&E comments that MOD-011-0 does not need to be modified 
because the appropriate planning authority will be a part of the 
regional reliability organization.
iv. Commission Proposal
    671. As mentioned above, MOD-011-0 is a ``fill-in-the-blank'' 
standard that requires the regional reliability organizations within an 
Interconnection to develop comprehensive steady-state data requirements 
and reporting procedures needed to model and analyze the steady-state 
conditions for each of the three NERC Interconnections. Because the 
regional methodologies 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.'' Accordingly, the Commission will not propose to 
accept or remand this Reliability Standard until the ERO submits 
additional information. In the interim, compliance with MOD-011-0 
should continue on its current basis, and the Commission considers 
compliance with the Reliability Standard to be a matter of good utility 
practice.
    672. As we noted in the discussion of MOD-010-0, we believe that 
the planning authority plays a significant role in integration of data 
and should also be included in the applicability section of MOD-011-0.
m. Dynamics Data for Modeling and Simulation of the Interconnected 
Transmission System (MOD-012-0)
i. NERC Proposal
    673. The purpose of MOD-012-0 is to establish consistent data 
requirements, reporting procedures, and system models to be used in the 
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 entities specified in MOD-013-0, Requirement 
R1, within a pre-determined time schedule or upon request if no time 
schedule exists.
ii. Staff Preliminary Assessment
    674. Staff stated that proposed Reliability Standard MOD-012-0 does 
not apply to the planning authority. However, 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.
iii. Comments
    675. MRO agrees with staff that the planning authority should be 
included in MOD-012-0. In contrast, PG&E comments that MOD-012-0 does 
not need to be modified, as found by staff's evaluation. Since the 
appropriate planning authority is already a part of the regional 
reliability organization, specific inclusion of the planning authority 
within the Reliability Standard is unnecessary. PG&E explains that, 
because MOD-012-0 requires the regional reliability organization within 
an Interconnection to develop data requirements and reporting 
procedures needed to model and analyze the conditions for each 
Interconnection, it already provides for appropriate participation by 
the planning authority.
iv. Commission Proposal
    676. We propose that MOD-012-0 add a new requirement for 
transmission owners to provide the list of faults or disturbances they 
use in performing dynamic stability analysis. We believe that access to 
such information will enable neighboring systems to accurately study 
their effects on their own systems. As we noted in the discussions of 
MOD-010-0 and MOD-11-0, we believe that the planning authority plays a 
significant role in integration of data and should also be included in 
the applicability section of MOD-012-0.
    677. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-012-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose directing 
that NERC 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 dynamic stability analysis; and (2) 
expands the applicability section to include the planning authority.
n. Maintenance and Distribution of Dynamics Data Requirements and 
Reporting Procedures (MOD-013-1)
i. NERC Proposal
    678. The purpose of MOD-013-1 is to establish consistent data 
requirements, reporting procedures, and system models to be used in 
reliability analysis. MOD-013-1 requires the regional

[[Page 64835]]

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 
of the three NERC Interconnections. 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 on request to the 
regional reliability organizations, NERC, and all users of the 
interconnected transmission system on request.
    679. The proposed Reliability Standard specifies the types of 
dynamic data that should be included. For example, it specifies that 
dynamics data pertaining to generating units, synchronous condensers, 
other devices that dynamically respond during disturbances, and 
dynamics data representing load characteristics should be provided. In 
addition, the Reliability Standard requires that dynamics data be 
consistent with the steady state data supplied according to MOD-010-0, 
Requirement R1.
    680. NERC's August 28, 2006 Supplemental Filing includes a revised 
version of MOD-013, designated MOD-013-1. MOD-013-1 has an additional 
Requirement to provide design data for the new or refurbished 
excitation systems.
ii. Staff Preliminary Assessment
    681. Staff stated that proposed Reliability Standard does not 
include the planning authority in the applicability section. The 
inclusion of the planning authority is necessary in the applicability 
section of the Reliability Standard because the planning authority is 
the entity responsible for coordinating and integrating transmission 
facilities and resource plans, as well as one of the entities 
responsible for the integrity and consistency of the data.\256\
---------------------------------------------------------------------------

    \256\ Although the Staff Preliminary Assessment addresses 
concerns regarding the MOD-013-0, many of the same concerns apply to 
MOD-013-1 as well.
---------------------------------------------------------------------------

iii. Comments
    682. NERC acknowledges that planning authorities also have 
responsibilities under the Reliability Standard and the applicability 
section should be revised to reflect that. PG&E, on the other hand, 
asserts that the proposed Reliability Standard does not need to be 
modified, because the appropriate planning authority is a part of the 
regional reliability organization, specific inclusion of the planning 
authority within the Reliability Standard is unnecessary.
    683. PG&E adds that Requirement R1.1.1, which 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, is arbitrary 
in imposing the 1990 cut-off. PG&E asserts that difficulty in obtaining 
unit specific data is not limited to the age of the unit but also unit 
configuration. As a result, PG&E recommends that the 1990 cut-off be 
removed from the proposed Reliability Standard and that the Reliability 
Standard be revised to allow the use of estimated or typical 
manufacturer data where unit specific data is impractical to obtain.
iv. Commission Proposal
    684. MOD-013-1 is a ``fill-in-the-blank'' Reliability Standard that 
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 
or response for each of the three NERC Interconnections. Because the 
regional methodologies have not been submitted to the Commission, it is 
not possible to determine at this time whether the proposed Reliability 
Standard satisfies the statutory requirement that it be ``just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest.'' Accordingly, the Commission will not propose to 
accept or remand this Reliability Standard until the ERO submits 
additional information. In the interim, compliance with the proposed 
Reliability Standard should continue, and the Commission considers 
compliance with the Reliability Standard to be a matter of good utility 
practice. Although we do not propose any action with regard to MOD-013-
1 at this time, we address our concerns regarding this Reliability 
Standard below.
    685. We share PG&E's concern regarding the 1990 cut off date 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 seeks comment whether it is reasonable to permit 
entities to estimate dynamics data if they are unable to obtain unit 
specific data for any reason.
    686. We agree with NERC that the Reliability Standard should apply 
to the planning authority.
o. Development of Steady-State System Models (MOD-014-0)
i. NERC Proposal
    687. The purpose of MOD-014-0 is to establish consistent data 
requirements, reporting procedures, and steady-state system models to 
be used in reliability analysis. The Reliability Standard 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 yearly models represent 
various seasonal conditions, usually for on- and off-peak load. The 
models are to be updated annually. The regional reliability 
organizations are required to submit the most recent models to NERC in 
accordance with a set schedule.
ii. Staff Preliminary Assessment
    688. Staff pointed out that while the Reliability Standard requires 
the development of steady-state models, it does not require periodic 
verification or appropriate modification of models against field data 
in accordance with Recommendation No. 24 of the Blackout Report.\257\
---------------------------------------------------------------------------

    \257\ Blackout Report at 160.
---------------------------------------------------------------------------

iii. Comments
    689. NERC comments that the NERC Multiregional Modeling Working 
Group (MMWG) is following recommendations from the Blackout Report that 
involve verifying powerflow models and databases, which include 
benchmarking to actual load levels and the periodic testing of MW, 
MVAR, and dynamic controls of generators.
    690. MRO, National Grid and ISO/RTO Council agree with staff's 
evaluation of MOD-014-0. ReliabilityFirst submits that it generally 
agrees with staff's evaluation of MOD-014-0 that, to ensure 
consistency, procedures developed by the individual regions need to be 
merged. In contrast, CenterPoint maintains that it is impractical to 
require each region to use identical practices in building and 
validating its models.
iv. Commission Proposal
    691. MOD-014-0 is a ``fill-in-the-blank'' Reliability Standard that 
requires

[[Page 64836]]

the regional reliability organizations within an Interconnection to 
develop, coordinate and maintain a library of solved Interconnection-
specific steady-state models. 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.'' 
Accordingly, the Commission will not propose to accept or remand this 
Reliability Standard until the ERO submits additional information. In 
the interim, compliance with MOD-014-0 should continue, and the 
Commission considers compliance with the Reliability Standard to be a 
matter of good utility practice.
    692. Although we do not propose any action with regard to MOD-014-0 
at this time, we address our concerns regarding this Reliability 
Standard below.
    693. The Reliability Standard does not require periodic 
verification or appropriate modification of models against field data 
in accordance with Recommendation No. 24 of the Blackout Report.\258\ 
We understand that the NERC MMWG that is incorporating recommendations 
from the Blackout Report is developing models only for the Eastern 
Interconnection. We believe that a Requirement to verify that steady 
state models are accurate should be a part of this Reliability Standard 
so that it applies to all three Interconnections.
---------------------------------------------------------------------------

    \258\ Blackout Report at 160.
---------------------------------------------------------------------------

    694. In addition, we are concerned 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. We believe that this 
Reliability Standard should contain a Requirement specifying the time 
period and the planning years to be identical to those found in FERC 
Form 715.\259\ We also seek comments on any incompatibility between our 
requirements under FERC Form 715 and MOD-014-0.
---------------------------------------------------------------------------

    \259\ FERC Form 715 is available at http://www.ferc.gov/docs-filing/eforms.asp#715.
 FERC Form 715 specific instructions on Part 

2, power flow base cases:
    ``The input data to the solved power flow base cases must be 
forward-looking. For example, the power flow base cases submitted 
and made available might include: 1. One, two, five and ten-year 
forecasts under summer and winter peak conditions and 2. A one-year 
forecast under light load/heavy transfers condition. This example is 
similar to a schedule of base cases proposed by NERC's Multiregional 
Modeling Working Group for development at the time this form was 
created.''
---------------------------------------------------------------------------

p. Development of Dynamics System Models (MOD-015-0)
i. NERC Proposal
    695. The purpose of MOD-015-0 is to establish consistent data 
requirements, reporting procedures, and system models to be used in the 
reliability analysis. The Reliability Standard 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 dynamic system models. These 
models represent near-term years and the years chosen from the longer-
term planning horizon. The models are to be updated annually. The 
regional reliability organizations are required to submit the most 
recent models to NERC in accordance with a set schedule.
ii. Staff Preliminary Assessment
    696. Staff noted that, while the Reliability Standard requires the 
development of dynamic models, it does not require periodic 
verification or appropriate modification of models against field data 
in accordance with Recommendation No. 24 of the Blackout Report.\260\
---------------------------------------------------------------------------

    \260\ Blackout Report at 160.
---------------------------------------------------------------------------

iii. Comments
    697. NERC comments that testing should be done to periodically 
verify that system dynamics models are accurate.
    698. ISO/RTO Council and MRO agree with staff's evaluation of 
Reliability Standard MOD-015-0. MRO suggests that, should a Regional 
Entity be required to perform this responsibility, it should be 
required in the Regional Entity's delegation agreement.
iv. Commission Proposal
    699. MOD-015-0 is a ``fill-in-the-blank'' Reliability Standard that 
requires the regional reliability organizations within an 
Interconnection to develop, coordinate and maintain a library of 
initialized Interconnection-specific dynamics system models. Because 
the applicable 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.'' Accordingly, the Commission 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. 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.
    700. Although we do not propose any action with regard to MOD-015-0 
at this time, we address our concerns regarding this Reliability 
Standard below.
    701. We agree with NERC and believe that a Requirement to verify 
accuracy of system dynamics models should be a part of this Reliability 
Standard.\261\
---------------------------------------------------------------------------

    \261\ See ERCOT report ``August 19, 2004 Forney Plant Trip Event 
Simulation'' prepared by the ERCOT Reliability and Operations 
Subcommittee by ERCOT Dynamics Working Group.
---------------------------------------------------------------------------

q. Documentation of Data Reporting Requirements for Actual and Forecast 
Demands, Net Energy for Load, Controllable Demand--Side Management 
(MOD-016-1)
i. NERC Proposal
    702. The purpose of MOD-016-1 is to ensure that past and forecasted 
demand data are 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 Demand-Side Management (DSM) data to be reported for 
system modeling and reliability analysis. These requirements are to 
ensure that consistent data is supplied for various TPL and MOD 
Reliability Standards that address system models and simulations.\262\
---------------------------------------------------------------------------

    \262\ On August 28, 2006, NERC submitted MOD-016-1 for approval, 
which replaces MOD-016-0. MOD-016-1 contains an additional 
Requirement that each load-serving entity must count its customer 
demand values only once. MOD-016-1 has also an improved set of 
Measures and Levels of Non-compliance.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    703. Staff noted that the proposed Reliability Standard does not 
include the transmission planner in the applicability section. The 
transmission planner is one of the entities involved in assuring the 
integrity and consistency of the load, energy, and DSM data.
iii. Comments
    704. The Commission received no specific comments regarding this 
Reliability Standard.
iv. Commission Proposal
    705. We propose that the Reliability Standard be modified to 
include

[[Page 64837]]

transmission planner in the applicability section because the 
transmission planner is one of the entities involved in assuring the 
integrity and consistency of the load, energy, and DSM data.\263\
---------------------------------------------------------------------------

    \263\ DSM may include control of electric supply to individual 
appliances or equipment on customer premises, interruptible/
curtailable load, demand bidding/buy-back programs, emergency demand 
response programs, capacity market programs, ancillary service 
market programs, and distributed generation (including solar PV, 
Combined Heat and Power facilities, and micro turbines). See Demand 
Response Report, Executive Summary at viii.
---------------------------------------------------------------------------

    706. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-016-1 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose directing 
that NERC submit a modification to MOD-016-1 that expands the 
applicability section to include the transmission planner.
r. Aggregated Actual and Forecast Demands and Net Energy for Load (MOD-
017-0)
i. NERC Proposal
    707. The purpose of MOD-017-0 is to ensure that past and forecasted 
demand data are available for validation of past events and future 
system assessment. The Reliability Standard requires the load-serving 
entities, 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 forecast and net load 
energy for the next two years; and (4) annual peak demand forecast 
(summer and winter) and annual net load energy for at least five and up 
to ten years into the future.
ii. Staff Preliminary Assessment
    708. Staff stated that MOD-017-0 does not require a consistent 
methodology in validating and forecasting demand. Specifically, there 
are no Requirements to report the accuracy, error, and bias of load 
forecasts.
iii. Comments
    709. ReliabilityFirst submits that it generally agrees with staff's 
evaluation of MOD-017-0. It also points out that some of the data 
related to the Reliability Standard are already addressed in U.S. 
Energy Information Administration (EIA) reporting requirements.
iv. Commission Proposal
    710. The Commission proposes to approve MOD-017-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    711. The Commission notes that load forecasts for most of the 
nation are driven by hot and humid weather. Most forecasts are 
``normalized'' to a standard temperature and humidity condition to 
avoid the variations caused by real weather conditions. It is important 
to know these conditions when viewing the actual peak loads and in 
predicting what peak loads will be in the future. The Commission 
proposes to add a Requirement to provide temperature and humidity 
information that is associated with peak load data.
    712. MOD-017-0 does not require a consistent methodology in 
validating and forecasting demand, specifically in reporting the 
accuracy, error, and bias of load forecasts by load serving entity, 
planning authority, and resource planner. This can lead to 
inconsistencies in modeling the load data for transmission planning and 
ATC analysis. We believe that underestimated load data (modeled in 
steady-state cases for future years) may not adequately indicate a need 
for operating procedures, or system reinforcements, and can potentially 
jeopardize system reliability.
    713. We propose that the Reliability Standard have additional 
requirements for reporting the accuracy, error, and bias of load 
forecasts compared to actual loads with due regard to temperature and 
humidity variations.\264\
---------------------------------------------------------------------------

    \264\ The Commission expects that the data provided in response 
to MOD-017-0 will be consistent with data reported in MOD-019-0, 
MOD-020-0 and MOD-021-0.
---------------------------------------------------------------------------

    714. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-017-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose to direct 
that NERC submit a modification to MOD-017-0 that includes new 
Requirements for: (1) reporting of temperature and humidity along with 
the peak load; and (2) reporting of the accuracy, error, and bias of 
load forecasts compared to actual loads with due regard to temperature 
and humidity variations.
s. Treatment of Nonmember Demand Data and How Uncertainties Are 
Addressed in the Forecasts of Demand and Energy for Load (MOD-018-0)
i. NERC Proposal
    715. The purpose of MOD-018-0 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 the load-
serving entities, planning authorities, transmission planners, and 
resource planners each submit a load data report which: (1) Indicates 
whether the demand data includes the regional reliability organization 
non-members' demand, and (2) addresses how assumptions, methods, and 
uncertainties are treated. The Reliability Standard also requires that 
each of the load-serving entities, planning authorities, transmission 
planners, and resource planners report the above information to NERC, 
the regional reliability organization, and the load-serving entities, 
planning authorities, transmission planners, and resource planners on 
request.
ii. Staff Preliminary Assessment
    716. Staff raised no specific concerns regarding MOD-018-0.
iii. Comments
    717. The Commission received no specific comments regarding MOD-
018-0.
iv. Commission Proposal
    718. The Commission proposes to approve MOD-018-0 as mandatory and 
enforceable. The Requirements set forth in MOD-018-0 are sufficiently 
clear and objective as to provide guidance for compliance.
t. Reporting of Interruptible Demands and Direct Control Load 
Management (MOD-019-0)
i. NERC Proposal
    719. The purpose of MOD-019-0 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 the load-
serving entities, planning authorities, transmission planners, and 
resource planners annually provide their forecasts of interruptible 
demands and direct control load management to NERC, the regional 
reliability

[[Page 64838]]

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.
ii. Staff Preliminary Assessment
    720. Staff stated that proposed Reliability Standard MOD-019-0 does 
not require a consistent methodology to validate and forecast 
interruptible demand. Specifically, there are no Requirements to report 
the accuracy, error and bias of load forecasts.
iii. Comments
    721. The Commission received no specific comments regarding MOD-
019-0.
iv. Commission Proposal
    722. MOD-019-0 does not require reporting of the accuracy, error 
and bias of controllable load \265\ forecast. Therefore, we propose 
that NERC develop a Requirement for a consistent approach to 
controllable load forecast and verification as well as reporting of the 
associated accuracy, error and bias of controllable load forecast.
---------------------------------------------------------------------------

    \265\ Whereas MOD-019-0 and MOD-020-0 use two separate terms 
interruptible load and Direct Control Load Management, NOPR uses 
``controllable load'' to refer to both of them.
---------------------------------------------------------------------------

    723. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-019-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose to direct 
that NERC submit a modification to MOD-019-0 that includes new 
Requirements for reporting of the accuracy, error and bias of 
controllable load forecast.
u. Providing Interruptible Demands and Direct Control Load Management 
Data to System Operators and Reliability Coordinators (MOD-020-0)
i. NERC Proposal
    724. 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 load-
serving entity, planning authority, transmission planner, and resource 
planner identifies its amount of: (1) Interruptible demand and (2) 
direct control load management (DCLM) to the transmission operators, 
balancing authorities, and reliability coordinators on request.
ii. Staff Preliminary Assessment
    725. Staff found that proposed Reliability Standard MOD-020-0 does 
not require a consistent methodology in validating and forecasting 
interruptible demand. Specifically, there are no Requirements to report 
the accuracy, error and bias of load forecasts.
iii. Comments
    726. The Commission received no specific comments regarding MOD-
020-0.
iv. Commission Proposal
    727. The Commission proposes to approve MOD-020-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    728. For the same reasons as discussed in MOD-017, the Commission 
proposes to direct NERC to add requirements concerning the reporting of 
the accuracy, error, and bias of controllable load forecasts.
    729. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-019-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose directing 
that NERC 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.
v. Documentation of the Accounting Methodology for the Effects of 
Controllable Demand-Side Management in Demand and Energy Forecasts 
(MOD-021-0)
i. NERC Proposal
    730. The purpose of MOD-021-0 is to ensure that past and forecasted 
demand data are available for validation of past events and future 
system assessment. The Reliability Standard requires the load-serving 
entities, transmission planners, and resource planners to clearly 
document how each addresses the demand and energy effects of DSM 
programs . The Reliability Standard also requires the load-serving 
entities, transmission planners, and resource planners to each include 
information detailing how Demand-Side Management 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. Lastly, 
MOD-021-0 requires load-serving entities, transmission planners, and 
resource planners to each document the treatment of its DSM programs, 
which is to be made available to NERC on request.
ii. Staff Preliminary Assessment
    731. Staff stated that proposed Reliability Standard MOD-021-0 does 
not require a consistent methodology in validating and forecasting 
demand. Specifically, there are no Requirements to report the accuracy, 
error and bias of load forecasts.
iii. Comments
    732. The Commission received no specific comments regarding MOD-
021-0.
iv. Commission Proposal
    733. The Commission proposes to approve MOD-021-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    734. MOD-021-0 does not require a consistent methodology in 
validating and forecasting demand, specifically in reporting 
information detailing how DSM measures are addressed in the forecasts. 
We propose that NERC modify MOD-021-0 to contain Requirements 
standardizing principles on reporting and validation of DSM program 
information. While the title of this Reliability Standard includes 
``controllable demand side management,'' the Requirements only relate 
to demand side management in general. We have a similar concern with 
the purpose statement of this Reliability Standard. Thus, we propose 
that the ERO modify the title and purpose statement consistent with the 
Requirements.
    735. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard MOD-019-0 as 
mandatory and enforceable. In addition, pursuant to section 215(d)(5) 
of the FPA and Sec.  39.5(f) of our regulations, we propose directing 
that NERC submit a modification to MOD-021-0 that: (1) Includes a 
Requirement standardizing principles on reporting

[[Page 64839]]

and validation of DSM program information; and (2) modifies the title 
and purpose statement to remove the word ``controllable,'' consistent 
with the Requirements.
w. Verification of Generator Gross and Net Real Power Capability (MOD-
024-1)
i. NERC Proposal
    736. NERC states that the purpose of MOD-024-1 is to ensure that 
accurate information on generation gross and net real power capability 
is used for reliability assessment. The Reliability Standard requires 
the regional reliability organization to establish and maintain 
procedures to address verification of generator gross and net real 
power capability. The Reliability Standard also requires the regional 
reliability organization to provide its generator gross and net real 
power capability verification and reporting procedures, and any changes 
to those procedures, to the generation owners, generation operators, 
transmission operators, planning authorities, and transmission planners 
affected by those procedures. Finally, MOD-024-1 requires the generator 
owners to follow their regional reliability organization's procedure 
for verifying and reporting gross and net real power generating 
capability.
ii. Staff Preliminary Assessment
    737. Staff noted that while the Reliability Standard requires the 
regional reliability organization to establish and maintain procedures 
to address verification of generator gross and net real power 
capability, the Reliability Standard 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.
iii. Comments
    738. NERC points out that Requirement R1.3 of MOD-024-1 includes 
data verification of any applicable conditions under which the data 
should be verified. MRO and ReliabilityFirst note that MOD-024-1 is 
currently undergoing field-testing.
iv. Commission Proposal
    739. MOD-024-1 is a ``fill-in-the-blank'' Reliability Standard that 
requires the regional reliability organizations to establish and 
maintain procedures to address verification of generator gross and net 
real power capability. Because the applicable regional procedures have 
not been submitted to the Commission, it is not possible to determine 
at this time whether MOD-024-1 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 will not propose to accept or remand this 
Reliability Standard until the ERO submits additional information. In 
the interim, compliance with MOD-24-1 should continue on its current 
basis, and the Commission considers compliance with the Reliability 
Standard to be a matter of good utility practice.
    740. Although we do not propose any action with regard to MOD-024-1 
at this time, we address our concerns regarding this Reliability 
Standard below.
    741. We believe that the Reliability Standard is not sufficiently 
clear because it does not define the test conditions and methodologies 
for calculating de-rating factors. Such specificity would provide 
consistency in reporting of generator gross and net real power 
capability. In addition, we note that the Requirement R2 states that 
the ``Regional Reliability Organization shall provide generator gross 
and net real power capability verification within 30 calendar days of 
approval.'' It is not clear what approval is required and it is also 
not clear when the 30 days period starts. Taking into account that the 
Reliability Standard is currently undergoing field-testing, we believe 
that more information will be available at the time the NOPR comments 
are due.
x. Verification of Generator Gross and Net Reactive Power Capability 
(MOD-025-1)
i. NERC Proposal
    742. NERC states that the purpose of MOD-025-1 is to ensure that 
accurate information on generation gross and net reactive power 
capability is used for reliability assessment. The Reliability Standard 
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. Lastly, MOD-025-1 requires the generator owner to follow 
its regional reliability organization's procedures for verifying and 
reporting its gross and net reactive power generating capability.
ii. Staff Preliminary Assessment
    743. Staff identified MOD-025-1 as a ``fill-in-the-blank'' standard 
that applies to the regional reliability organization.
iii. Comments
    744. CenterPoint suggests that MOD-025-1 does not adequately 
address the verification of generator reactive capability. It explains 
that the Reliability Standard requires a generator to provide certain 
reactive power capability at the unit's full MW loading. However, it 
points out that most units rarely operate at full MW loading, making it 
unclear what reactive capability is required over a unit's real power 
(MW) operating range. CenterPoint suggests that MOD-025-1 would be 
clearer if it requires a minimum reactive (MVAR) capability throughout 
a unit's real power operating range.
    745. MRO and ReliabilityFirst note that MOD-025-1 is currently 
undergoing field-testing.
iv. Commission Proposal
    746. The MOD-025-1 is a ``fill-in-the-blank'' Reliability Standard 
that requires the regional reliability organizations to establish and 
maintain procedures to address verification of generator gross and net 
reactive power capability. Because the applicable regional procedures 
have not been submitted to the Commission, it is not possible to 
determine at this time whether MOD-025-1 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 will not propose to accept or 
remand this Reliability Standard until the ERO submits additional 
information. In the interim, compliance with MOD-25-1 should continue 
on its current basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice.
    747. Although we do not propose any action with regard to MOD-025-1 
at this time, we address our concerns regarding this Reliability 
Standard below.
    748. We agree with CenterPoint that MOD-025-1 could be clearer. 
This could be accomplished by requiring a minimum reactive power (MVAR) 
capability throughout a unit's real power operating range. In addition, 
we note that the Requirement R2 states that the ``Regional Reliability 
Organization

[[Page 64840]]

shall provide generator gross and net real power capability 
verification within 30 calendar days of approval.'' It is not clear 
what approval is required and it is also not clear when the 30 days 
period starts. Taking into account that the Reliability Standard is 
currently undergoing field-testing, we believe that more information 
will be available at the time the NOPR comments are due.
9. PER: Personnel Performance, Training and Qualifications
a. Overview
    749. 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 proposed PER 
Reliability Standards address: (1) Operating personnel responsibility 
and authority; (2) operating personnel training; (3) operating 
personnel credentials; and (4) reliability coordination staffing.
b. Operating Personnel Responsibility and Authority (PER-001-0)
i. NERC Proposal
    750. PER-001-0 ensures the energy balance and transmission 
reliability of the Interconnected grid by requiring that transmission 
operator and balancing authority personnel have the responsibility and 
authority to direct actions in real-time. In practical terms, NERC 
asserts that the proposed Reliability Standard requires operating 
personnel who are responsible for operating the Bulk-Power System to 
have the authority to take action when they believe it is 
necessary.\266\ Additionally, PER-001-0 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.
---------------------------------------------------------------------------

    \266\ Reliability Standard EOP-003-0 addresses the need to 
provide safeguards to shield operators from retaliation when they 
declare an emergency or shed load in accordance with previously 
approved guidelines.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    751. No substantive issues were identified concerning PER-001-0.
iii. Comments
    752. Several commenters recommend that the Commission accept the 
proposed Reliability Standard.\267\
---------------------------------------------------------------------------

    \267\ See, e.g., NYSRC, WECC/OTS, ReliabilityFirst and NERC.
---------------------------------------------------------------------------

iv. Commission Proposal
    753. PER-001-0 requires that each transmission operator and 
balancing authority provide operating personnel with the responsibility 
and authority to implement real-time actions to ensure the stable and 
reliable operation of the Bulk Electric System. Documentation 
designating the job description and responsibilities and authorities of 
each operating position of a transmission operator and balancing 
authority must be articulated in ``clear and unambiguous language.'' 
\268\ Further, the required documentation should be readily available 
in the control room to all operating personnel.
---------------------------------------------------------------------------

    \268\ PER-001-0, Measure M1.
---------------------------------------------------------------------------

    754. We believe that the proposed Reliability Standard clarifies 
the level of responsibility and authority that the transmission 
operator and the balancing authority have to act in real-time, which 
will add to the overall reliability of the Bulk-Power System. We note 
that the Blackout Report identified the inadequate training of 
operating personnel as a factor that was common to some major outages 
that it reviewed.\269\ Further, it suggests that prior blackouts could 
have been prevented if the operators had believed that they had the 
responsibility and authority to act.\270\
---------------------------------------------------------------------------

    \269\ Blackout Report at 107.
    \270\ Id. at 110.
---------------------------------------------------------------------------

    755. The Commission agrees with NERC that this Reliability Standard 
should be applicable to all transmission operators and balancing 
authorities. How local transmission and generation control centers are 
incorporated into the definition of transmission operator and generator 
operator is described in the COM Chapter of this NOPR.
    756. Accordingly, the Commission proposes to approve PER-001-0 as 
mandatory and enforceable. We propose to find that the Reliability 
Standard is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest.
c. Operating Personnel Training (PER-002-0)
i. NERC Proposal
    757. PER-002-0 requires that transmission operator and balancing 
authority personnel are adequately trained. Requirement R2 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. According to NERC's 
petition, the purpose of a training program is to ensure that operating 
personnel are capable of competently performing their tasks. 
Requirement R3 lists the criteria that must be met by the training 
program to attain that goal and Requirement R4 calls for operating 
personnel to receive at least five days of training in emergency 
operations each year using realistic simulations of system emergencies.
ii. Staff Preliminary Assessment
    758. While PER-002-0 sets out broad objectives that a training 
program must satisfy, the Staff Preliminary Assessment stated that it 
does not specify the minimum expectations of a training program 
consistent with the roles, responsibilities and authorities of 
operating and support personnel. As such, staff explained that the 
nature, objective and criteria of operator training programs and 
minimum hours of training (other than a requirement of five days per 
year for realistic simulation training) are open to interpretation. 
Staff expressed concern that the lack of specificity in this 
Reliability Standard will allow training programs to vary widely in 
their implementation.
    759. Further, staff stated that the proposed Reliability Standard 
does not tailor training programs according to the needs of reliability 
coordinators, balancing authorities, transmission operators, generator 
operators and operation planning and support personnel with differing 
authorities, responsibilities, roles and tasks. Additionally, staff 
observed that this Reliability Standard should also apply to 
reliability coordinators, generator operators, operations planning and 
operations support staff because they also play an important role in 
maintaining Bulk-Power System reliability.
    760. Finally, the Staff Preliminary Assessment noted that there is 
a widely accepted Systematic Approach to Training (SAT) methodology 
that has been successfully used in the electric industry as well as 
other industries. According to the Staff Preliminary Assessment, PER-
002-0 should be revised to incorporate some of the elements of the SAT 
methodology.

[[Page 64841]]

iii. Comments
    761. NERC agrees with the Staff Preliminary Assessment with respect 
to training issues, with a few minor clarifications. NERC states that 
there must be minimum specific criteria for training critical 
reliability personnel and training must be custom designed and 
delivered to be effective. NERC also agrees with staff on the need to 
expand training requirements to other persons in addition to real-time 
operators. However, NERC believes it more important, at this point, to 
focus its proposed training Reliability Standards on those positions 
directly responsible for real-time operations. NERC states that 
currently work is ongoing to develop new, substantially more robust 
Reliability Standards for training that address staff's points.
    762. EEI supports strengthening the full range of training programs 
and initiatives but believes that a one-size-fits-all approach is 
inappropriate. Also, EEI states that developing strong programs, such 
as those used in the nuclear industry, may result in setting 
requirements that go far beyond those needed for many operations 
personnel. EEI notes that a drafting team has begun development of a 
new Reliability Standard for training, with a possible filing date with 
the Commission near the end of 2006.
    763. ISO/RTO Council notes that many of the Requirements have ill-
defined terms, no measures of compliance and lack specificity. ISO/RTO 
Council argues that rather than defining the objective of the training 
program, PER-002-0 leaves an individual entity to develop a training 
program on its own. Concurring with the Staff Preliminary Assessment, 
NYSRC, NERC and ReliabilityFirst state that PER-002-0 should specify 
the minimum requirements of a training program. Moreover, ISO/RTO 
Council recommends that the PER Reliability Standards should 
specifically identify the positions that are directly responsible for 
complying with the proposed Reliability Standard.
    764. NERC and WECC/OTS support the use of the SAT concept, which 
would customize training to the job requirements of each position. 
Although WECC/OTS endorses the five-day training requirement, it 
asserts that specifying a minimum number of training hours devoted to a 
certain task or establishing a mandatory curriculum within the 
Reliability Standard is inconsistent with the SAT concept. It argues 
that the training needs of one transmission operator may be quite 
different from another due to size, impact on the Interconnection, and 
experience and skill of its operating personnel. ISO/RTO Council 
generally supports a performance-based approach to training and 
metrics.
    765. Although several commenters support the Staff Preliminary 
Assessment,\271\ National Grid maintains that some of staff's comments 
on the PER Reliability Standards are overly prescriptive and appear to 
be mandating various training tools, such as simulation training and 
SAT, without assessing the cost effectiveness of such measures. It 
contends that the PER Reliability Standards should focus on performance 
measures without being overly prescriptive.
---------------------------------------------------------------------------

    \271\ NERC, WECC/OTS and ISO/RTO Council.
---------------------------------------------------------------------------

    766. Along with NERC, WECC/OTS supports expanding the applicability 
of training programs. WECC/OTS further recommends that training 
requirements should apply to all personnel with the ability to affect 
real-time operations of the Bulk-Power System. However, it believes 
that the training programs should focus on positions directly 
responsible for real-time operations at this point. In contrast, 
National Grid expresses concern regarding the Staff Preliminary 
Assessment's suggestion to expand training to other functions with 
responsibilities for Bulk-Power System reliability. Specifically, it 
argues that there is an implication that all employees listed within 
the categories identified by staff would be required to receive 
training even if some have no responsibility for grid reliability. It 
suggests that the staff's comments in this area should be taken by NERC 
as a cue to explore expanding training to necessary areas without 
requiring all employees within a function or category to receive 
training.
    767. WECC/OTS notes that a full scale simulator can be an effective 
tool in operator training, but cautions against a requirement that all 
operating entities employ a full-scale simulator, stating that 
emergency training can be effectively provided through other means, 
i.e., drills or computer models. With regard to the EPAct 2005 
provision for training guidelines for non-nuclear electric energy 
industry personnel, it maintains that the provision should not apply to 
the ERO with the exception of the operation function. Nonetheless, 
WECC/OTS argues that training in other areas cited in EPAct 2005 should 
be covered in a specific course tailored to the function's effect on 
the real-time reliability of the Bulk-Power System. It argues that 
requirements for initial certification, assessment and recertification 
identified in EPAct 2005 should be separated from the requirements of 
system operators.
    768. NYSRC recommends that the Commission conditionally approve 
PER-002-0, while WECC/OTS supports approval of the proposed Reliability 
Standard with the understanding that NERC is currently developing a new 
Reliability Standard to replace PER-002-0 with an emphasis on the SAT 
process.
 iv. Commission Proposal
    769. The Commission proposes to approve PER-002-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    770. Inadequate operator training has been identified as a common 
factor among past major system outages.\272\ In the context of the task 
force investigation of the August 2003 blackout, the Blackout Report 
stated that some reliability coordinators and balancing authority 
operators did not receive adequate training in recognizing and 
responding to system emergencies.\273\ The ``deficiency in training 
contributed to the lack of situational awareness and failure to declare 
an emergency while operator intervention was still possible (before 
events began to occur at a speed beyond human control.)'' \274\
---------------------------------------------------------------------------

    \272\ Blackout Report at 107.
    \273\ Id. at 157.
    \274\ Id.
---------------------------------------------------------------------------

    771. PER-002-0 requires that each transmission operator and 
balancing authority shall be staffed with adequately trained personnel 
and directs the transmission operator and balancing authority to have 
training programs for all their 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 Reliability Standards. 
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 or must comply 
with the Reliability Standards. Reliability coordinators, generator 
operators, operations planning and operations support staff also 
potentially impact the reliable operation of the Bulk-Power System, yet 
these entities are not required to participate in mandatory training 
programs. The Commission agrees with NERC, WECC/OTS and National Grid 
and supports the

[[Page 64842]]

expanding training programs to other personnel with the ability to 
affect real-time operations of the Bulk-Power System. The Commission 
proposes that such expansion be based on the role of the entity rather 
than its size. Further, we note that NERC has stated that it has asked 
its Reliability Standards drafting team to prepare a request for a new 
project to expand the scope of the training requirements to other 
positions essential to reliability of the Bulk-Power System.
    772. After considering the comments of NERC and National Grid that 
the training programs should focus on positions directly responsible 
for real-time operations at this point in time, and in recognition of 
the need to give first priority to real-time operations, the Commission 
proposes a modification of 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. The phasing of the effective date 
would acknowledge the priority of training each group. This 
prioritization is also supported by WECC/OTS which cautions that 
limited training resources may be diverted from system operators to 
other personnel that can effect reliable operation at the expense of 
those responsible for real-time operations.
    773. In order to maintain an adequate level of reliability, the 
Commission proposes to require NERC to modify PER-002-0 in the future 
or to develop a new training Reliability Standard for all personnel who 
may directly impact the reliable operation of the Bulk-Power System or 
for all personnel who have responsibility for compliance with the 
Reliability Standards. These personnel include operations planning and 
operations support staff. We disagree with the comments of EEI and 
believe that this does not imply a one-size-fits-all approach. Rather, 
this course of action ensures the creation of training programs that 
are structured and tailored to the different functions and needs of the 
personnel involved.
    774. A review of operator demographics reveals that a large 
percentage of electrical operators will retire over the next five 
years. As these older and more experienced operators retire, the need 
for structured, comprehensive and effective training programs tailored 
to the needs of the functions and individuals become even more crucial, 
and will need to be developed and implemented for incoming operators 
who will not have benefited from years of on-the-job training, 
mentoring and knowledge transfer from experienced operators. 
Requirement R3 sets out broad objectives that a training program must 
satisfy, yet it does not specify the minimum expectations of an 
effective training program. In its comments, NERC agrees with the Staff 
Preliminary Assessment that PER-002-0 must have minimum expectations 
and specific criteria for training critical reliability personnel. The 
Commission concurs with NERC's comments, calling for measurable 
requirements regarding objectives, content, minimum hours of training 
and types of training in the proposed Reliability Standard. The 
Commission proposes that NERC modify the Reliability Standard to 
include minimum training requirements related to objectives, program 
content, minimum hours of training and types of training with specific 
performance metrics to gauge the effectiveness of the training program.
    775. Although EEI cautions against using the nuclear industry 
training program as a model, we do not believe that the use of an SAT 
method would set requirements that go beyond those needed for many 
operating personnel. We agree with WECC/OTS that training based on SAT 
is a proven approach to identify the tasks and associated skills and 
knowledge necessary to accomplish those tasks, determine the competency 
level of each operator to carry out those tasks, determine the 
competency gaps, then design, implement and evaluate a training plan to 
address each operator's competency gaps.
    776. CenterPoint and National Grid caution against being overly 
prescriptive and propose that the Commission focus on desired outcomes. 
ISO/RTO Council stated that there is no definition for ``adequately 
trained operating personnel'' and suggested the adoption of performance 
metrics to ensure that training results in competent operating 
personnel. These are distinct from measures used to ensure compliance 
with the requirements. The Commission strongly supports the adoption of 
performance metrics to ensure that training results in competent 
operating personnel. However, such performance metrics are not a 
substitute for an SAT developed training program. The Commission 
proposes to require that NERC modify PER-002-0 to include performance 
metrics associated with the effectiveness of the training program.
    777. Effective training programs must be structured and address 
competency gaps of operating personnel. WECC/OTS states that SAT-based 
training plans tailor to the needs of not only various job functions, 
but also to individual operator competency gaps within those functions. 
WECC/OTS and NERC support this approach in identifying the tasks and 
associated skills and knowledge necessary to accomplish the specific 
tasks of each operator. In addition, they support implementing and 
evaluating a unique training plan to address each operator's competency 
gap. NERC stated that the implementation of minimum training 
requirements, as well as an SAT methodology, is essential to ensuring 
system operator competencies. NERC claims that a new Reliability 
Standard is under development which will address the above concerns. 
The Commission proposes that NERC explore the SAT methodology in its 
efforts to establish training plans tailored to the needs of various 
job functions and individuals.
    778. Requirement R4 of the Reliability Standard requires training 
in emergency operations using realistic simulations of system 
emergencies. Several entities currently use full scale operator 
training simulators for this purpose with scenarios derived from actual 
system disturbances supplemented with drills to deal with 
communications during emergencies. WECC/OTS notes that the use of such 
a simulator can be an effective tool in operator training programs, but 
cautions against making this a requirement for all operating entities. 
The Commission notes 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 solicits comments on the benefits and appropriateness of 
required ``hands-on'' training using simulators in dealing with system 
emergencies as identified in the training related recommendations made 
in studies of major outages.\275\
---------------------------------------------------------------------------

    \275\ Id. at 107.
---------------------------------------------------------------------------

    779. The Commission proposes that this Reliability Standard be 
Applicable to transmission operators, balancing authorities, 
reliability coordinators, generator operators, and operations planning 
and operations support staffs that have a direct impact on the reliable 
operation of the Bulk-Power System. How local transmission and 
generation control centers are incorporated into the definition of 
transmission operator and generator operator is described in the COM 
Chapter. The extent of the training shall take into account the need to 
assure real time operators do not suffer because of the training needs 
of non-real time staff.
    780. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the

[[Page 64843]]

Reliability Standard will accomplish the purpose represented to the 
Commission by the ERO and that it will improve the reliability of the 
nation's Bulk-Power System, the Commission proposes to approve 
Reliability Standard PER-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 proposes 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 SAT methodology in its 
development of new training programs; and (5) includes performance 
metrics associated with the effectiveness of the training program.
d. Operating Personnel Credentials (PER-003-0)
i. NERC Proposal
    781. PER-003-0 requires transmission operators, balancing 
authorities and reliability coordinators 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. 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.
ii. Staff Preliminary Assessment
    782. In its Staff Preliminary Assessment, staff stated that this 
Reliability Standard does not specify the minimum competencies that 
operating personnel must demonstrate to meet the certification 
requirements.\276\ Although NERC's System Operator Certification 
Program Manual outlines the requirements for certification, the manual 
is not a part of the proposed Reliability Standard. Therefore, staff 
contended that the Manual is not enforceable.\277\
---------------------------------------------------------------------------

    \276\ Staff Preliminary Assessment at 89-90.
    \277\ North American Electric Reliability Council's Application 
for Certification as the Electric Reliability Organization, Rules of 
Procedure of the Electric Reliability Organization, System Operator 
Certification Program Manual, Appendix 6 available at ftp://www.nerc.com/pub/sys/all_updl/ero/application/ERO-Application-Complete.pdf
.

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

    783. Moreover, staff noted that generator operators, who have 
responsibility for the real-time operation of the Bulk-Power System and 
are directly responsible for complying with NERC Reliability Standards, 
do not require NERC-certification under this Reliability Standard.
iii. Comments
    784. NERC does not agree with the Staff Preliminary Assessment's 
view that the NERC System Operator Certification Program Manual should 
be included in the Reliability Standard to be enforceable. It states 
that this is a procedural document and the Certification Program is 
managed by an independent Personnel Certification Governance Committee 
as required by the standards of the National Organization for 
Competency Assurance and employment law.
    785. WECC/OTS and NYSRC join with comments of the Staff Preliminary 
Assessment in observing that the Applicability and Requirements 
sections of PER-003-0 potentially weaken the enforcement of this 
Reliability Standard. While WECC/OTS encourages Commission approval of 
PER-003-0 with the understanding that NERC or another interested party 
will submit a Standard Authorization Request to more specifically 
define which functions should be performed by certified personnel, 
NYSRC recommends conditional approval of PER-003-0. Although the ISO/
RTO Council does not address staff's comment that the NERC Manual is 
not enforceable, it agrees that the proposed Reliability Standard 
should contain minimum Certification Requirements. It also implies that 
the NERC System Operator Certification Program Manual contains the 
needed level of requirements and measurability. In contrast, WECC/OTS 
opposes including the specific competencies operating personnel must 
demonstrate to meet the certification requirements. It states that 
these details are retained with the certification program governance 
body.
    786. ReliabilityFirst disagrees with the Staff Preliminary 
Assessment's comments regarding PER-003-0. It asserts that personnel 
are obligated to follow the appropriate NERC process to become 
certified. It argues that PER-003-0 should make reference to this as a 
stand-alone manual that could be adjusted and maintained without 
affecting the current Reliability Standard.
iv. Commission Proposal
    787. The Commission proposes to approve PER-003-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    788. PER-003-0 requires applicable entities to staff real-time 
operation positions with NERC-certified personnel. The Commission 
interprets this to include real-time operating positions in a 
transmission operations control center that performs switching 
operations via SCADA for the Bulk-Power System.
    789. Some commenters agree with staff that PER-003-0 should contain 
minimum certification requirements, while others do not. The Commission 
acknowledges the commenter's concerns and the convenience of 
maintaining a procedural document that is separate from the Reliability 
Standard so that it can be modified without requiring a revision to the 
entire Reliability Standard. Nevertheless, the Commission believes that 
the minimum competencies that must be demonstrated to become a 
certified operator and the minimum requirements to remain certified 
should be included in PER-003-0. To address commenter's concerns, we 
propose that the ERO modify PER-003-0 to identify the minimum 
competencies operating personnel must demonstrate to be certified, but 
not include the entire Certification Program Manual.
    790. Additionally, we note that generator operators who have 
responsibility for real-time operation of the Bulk-Power System and who 
are directly responsible for complying with the Reliability Standards 
are not designated in the Applicability section of PER-003-0, and 
therefore, do not require NERC-certification. We agree with the 
concerns articulated in the Staff Preliminary Assessment and we believe 
that this omission has the potential to impact the reliable operation 
of the Bulk-Power System. Therefore, the Commission proposes the 
modification of PER-003-0 to include generator operators as applicable 
entities.
    791. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PER-003-0 as 
mandatory and enforceable. In addition, we propose to direct NERC to 
modify the Reliability Standard to address the Commission's concerns. 
In addition, pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) 
of our

[[Page 64844]]

regulations, the Commission proposes to direct NERC to submit a 
modification to PER-003-0 that: (1) Expands the Applicability to 
include generator operators; (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 (but not include the Certification Program 
Manual).
e. Reliability Coordination--Staffing (PER-004-0)
i. NERC Proposal
    792. PER-004-0 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. Further, 
reliability coordinator operating personnel must have a comprehensive 
understanding of the area of the Bulk-Power System over which they are 
responsible, including familiarity with transmission operators, 
generator operators and balancing authorities, as well as their 
operating practices and procedures, equipment capabilities and 
restrictions, system operating limits and interconnection reliability 
operating limits.\278\ In addition the reliability coordinator must 
complete a minimum of five days per year of emergency operations 
training in addition to the training required to maintain qualified 
operating personnel.
---------------------------------------------------------------------------

    \278\ A comprehensive understanding of a reliability 
coordinator's ``area'' includes: Familiarity with transmission 
operators, generator operators and balancing authorities, as well as 
their operating practices and procedures, equipment capabilities and 
restrictions, system operating limits and interconnection 
reliability operating limits.
---------------------------------------------------------------------------

    793. NERC indicates that it will modify this proposed Reliability 
Standard to address the lack of Measures and Levels of Non-Compliance 
and resubmit the proposal for Commission approval in November 2006.
ii. Staff Preliminary Assessment
    794. The Staff Preliminary Assessment noted that there was no 
formal training program requirement for reliability coordinators 
similar to the program required for transmission operators and 
balancing authority personnel under PER-002-0.
iii. Comments
    795. ReliabilityFirst notes that PER-004-0 does require reliability 
coordinators to be NERC-certified and to complete required training. 
WECC/OTS states that the NERC System Personnel Training Reliability 
Standard, which is under development, includes reliability coordinators 
in the applicability section.
    796. ReliabilityFirst, NYSRC and ISO/RTO all note the Reliability 
Standard's lack of Measures and Levels of Non-Compliance.
iv. Commission Proposal
    797. The Commission proposes to approve PER-004-0 as mandatory and 
enforceable. In addition, we propose directing that NERC develop 
modifications to the Reliability Standard, as discussed below.
    798. A reliability coordinator is the entity with the highest level 
of authority that is responsible for the reliable operation of the 
Bulk-Power System, has a ``wide area view,'' and has the operating 
tools, processes and procedures, including authority to prevent or 
mitigate emergency operating situations in both next-day analysis and 
real-time operations.\279\ Most of the Requirements for PER-004-0 
address training issues pertaining to reliability coordinators, yet 
there is no requirement for a formal training program for reliability 
coordinators that is similar to the program required for transmission 
operators under PER-002-0. We believe that the addition of formal 
training requirements for reliability coordinators will help to ensure 
adequate training and competency for an entity that plays a critical 
role in ensuring the reliability of the interconnected grid. To ensure 
that the training requirements for reliability coordinators are 
comprehensive, we propose that the ERO either modify PER-006-0 to 
include the same quality and clarity as the training requirements for 
other operating personnel as set forth in PER-002-0 or, alternatively, 
given the high priority work that the ERO must accomplish it may want 
to consider including the reliability coordinator as an applicable 
entity in PER-002-0. Similarly, we propose that the ERO either modify 
PER-006-0 to address personnel credentials for reliability coordinators 
in a similar manner as for other operating personnel in PER-003-0 or, 
alternatively, it may address this concern by including reliability 
coordinators as an applicable entity in PER-006-0.
---------------------------------------------------------------------------

    \279\ See NERC glossary at 11.
---------------------------------------------------------------------------

    799. We agree with commenters that Measures and Levels of Non-
Compliance should be added to the proposed Reliability Standard, 
including Measures to address staffing requirements and the minimum 
five days of emergency training.
    800. While the Commission has identified a number of concerns with 
regard to PER-003-0, this proposed Reliability Standard serves an 
important purpose of ensuring that reliability coordinator personnel 
are adequately trained. Further, NERC should provide Measures and 
Levels of Non-Compliance for this proposed Reliability Standard. 
Nonetheless, the Requirements set forth in PER-003-0 are sufficiently 
clear and objective to provide guidance for compliance.
    801. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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 
proposes to direct that NERC 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 Levels of Non-Compliance and Measures that address 
staffing requirements and the requirement for five days of emergency 
training.
10. PRC: Protection and Control
a. Overview
    802. Protection and Control (PRC) systems on Bulk-Power System 
elements are an integral part of reliable grid operation. Protection 
systems are designed to detect and isolate a faulted element from the 
system, thereby limiting the severity and spread of system disturbances 
and preventing possible damage to protected elements. SOLs and IROLs 
are only valid when they recognize the function, settings and 
limitations of the protection system. One of the common factors among 
the major outages from 1965 to 2003 was the lack of coordination of 
system protection.\280\
---------------------------------------------------------------------------

    \280\ Blackout Report at 107.
---------------------------------------------------------------------------

    803. 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.\281\ NERC has recognized that

[[Page 64845]]

the Reliability Standards do not form a complete set of PRC Reliability 
Standards to meet the goal of reliability.\282\
---------------------------------------------------------------------------

    \281\ Topics addressed under the PRC Reliability Standards 
include: system protection coordination, disturbance monitoring, 
under-frequency load shedding (UFLS), special protection systems, 
under-voltage load shedding (UVLS) and their assessments, database, 
event and mis-operation analysis, maintenance and testing 
requirements and performance evaluation.
    \282\ See NERC Planning Standards Phase III-IV, available at 
http://www.nerc.com/~filez/standards/Phase-III-IV.html.

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

    804. Generally, the proposed Reliability Standards in the PRC group 
raise issues related to Measures, Levels of Non-compliance, and 
Requirements. The regional reliability organization is the compliance 
monitor for twelve of the PRC Reliability Standards \283\ and the 
applicable entity for seven of them.\284\
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    \283\ The regional reliability organization is assigned 
compliance monitoring responsibility under the following Reliability 
Standards in the PRC group: PRC-004-1; PRC-005-1; PRC-007-0; PRC-
008-0; PRC-009-0; PRC-010-0; PRC-011-0; PRC-015-0; PRC-016-0; PRC-
017-0; PRC-018-1; PRC-021-1; and PRC-22-1.
    \284\ The regional reliability organization is listed as the 
applicability entity under the following Reliability Standards in 
the PRC group: PRC-002-0; PRC-003-1; PRC-006-0; PRC-012-0; PRC-013-
0; PRC-014-0; and PRC-020-1.
---------------------------------------------------------------------------

b. System Protection Coordination (PRC-001-0)
i. NERC Proposal
    805. Proposed Reliability Standard PRC-001-0 ensures that 
protection systems are coordinated among operating entities by 
requiring transmission operators and generator operators to notify 
appropriate entities of relay or equipment failures that could impact 
system reliability. In addition, these entities must coordinate with 
appropriate entities when new protection systems are installed or when 
existing protection systems are modified.
ii. Staff Preliminary Assessment
    806. The Staff Preliminary Assessment pointed out that Requirement 
R2 of PRC-001-0 instructs transmission operators or generator operators 
to take corrective action as soon as possible where a protective relay 
or equipment failure reduces system reliability. However, PRC-001-0 
does not designate a maximum time period for corrective control 
actions. This is inconsistent with the requirement that system 
operators re-adjust the system within 30 minutes for contingencies 
under the proposed IRO and TOP Reliability Standards. Staff also noted 
that the lack of Measures and Levels of Non-Compliance in this 
Reliability Standard may hinder consistent and effective enforcement.
iii. Comments
    807. NERC agrees with staff that PRC-001-0 requires modification 
and requests that the Commission conditionally approve it. NERC reasons 
that even if a generator operator fails to tend to a protective relay 
failure, other proposed Reliability Standards still require the 
transmission operator and reliability coordinator to ensure reliable 
operation of the grid by mitigating SOL and IROL violations as soon as 
possible. In addition, NERC indicates that it will modify this 
Reliability Standard to include missing Measures and Levels of Non-
Compliance and resubmit it for Commission approval in November 2006.
    808. CPUC argues that ``action adequate to bring the system into 
balance'' may be ambiguous, i.e., a more effective action taken in 35 
minutes may be preferable to a less effective action taken in 28 
minutes in an attempt to follow the 30-minute time limit specified 
under the IRO and TOP Reliability Standards. It also stated that the 
Staff Preliminary Assessment's concern apparently relates to the August 
2003 Blackout, where operators failed to take effective action in the 
very short time frame required to prevent cascading outages throughout 
the region. CPUC questions the extent to which a rigid 30-minute 
maximum time limit would have prevented much of the system dysfunction 
that occurred in August 2003.
    809. National Grid suggests that requiring a maximum time period 
for corrective actions where a protective relay or equipment failure 
reduces reliability inappropriately mixes protection design engineering 
issues with operational issues. National Grid asserts that the proposed 
Reliability Standard addresses design engineering and specifying a 
maximum time period for corrective actions to respond to protective 
equipment failures would be inappropriate. Further, CenterPoint states 
that the amount of time required to diagnose and correct different 
types of failures varies. It explains that investigating and correcting 
relay failures is a fundamentally different exercise from that of real-
time operators taking corrective actions in response to operating 
contingencies that may occur.
    810. ReliabilityFirst agrees that a failed protection system 
element must be replaced as soon as possible, but agrees with staff 
that PRC-001-0 should clearly state that system performance 
requirements must continue to be met when the affected protection 
system element has failed or is out of service. Repair or replacement 
of the failed protection element or an alternate corrective solution, 
such as operator control action, must be implemented to satisfy 
performance requirements. ReliabilityFirst concludes that a specific 
time for repairing the failed protection system element is not 
necessary if performance requirements must be maintained.
iv. Commission Proposal
    811. The Commission proposes to approve PRC-001-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard as discussed below.
    812. We recognize that protection and control systems are integral 
part of reliable grid operation and agree that protection systems 
affect the validity of IROLs. We further note that if a non-redundant 
protection system for a critical element fails and no corrective 
control action is taken, the system could be subject to the risk of 
cascading failure if a critical contingency subsequently occurred.
    813. The Commission emphasizes the importance of immediately 
informing transmission operators and generator operators of any 
protection failure that may affect SOLs and IROLs so that they can take 
corrective control action to maintain reliable system operations. We 
further note that PRC-001-0 or other relevant PRC Reliability Standards 
do not contain such a Requirement.
    814. PRC-001-0 should designate a maximum time limit for corrective 
control action where the failure of a protection system element has 
reduced system reliability and undermined performance requirements. The 
Commission commends NERC's initiative in attempting to address and 
clarify this issue in PRC-001-0. However, we do not agree with NERC 
that even if a generator operator fails to tend to a protective relay 
failure, other proposed Reliability Standards still require the 
transmission operator and reliability coordinator to ensure the 
reliable operation of the grid by mitigating SOL and IROL violations as 
soon as possible, i.e., respecting performance requirements. We believe 
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. Therefore, in addition to clarifying the 
ambiguity in future revision, we propose to require NERC to include a 
requirement that the

[[Page 64846]]

appropriate transmission operators or generator operators should be 
notified immediately upon detection of failures on relays or protection 
systems on Bulk-Power System elements so that they can maintain system 
reliability requirements by taking corrective actions in the same 
manner used to mitigate IROL violations.
    815. The Commission does not agree with National Grid's comment 
that staff's concern inappropriately mixes protection design 
engineering issues with operational issues. Design engineering refers 
to protection system schemes with protective elements, such as relays. 
Furthermore, the applicable entities for design engineering would 
include field protection and control personnel who are responsible for 
carrying out the inspection, replacement and repair of damaged 
protection system elements. PRC-001-0 requires transmission operators 
or generator operators to carry out corrective actions because this 
Reliability Standard addresses system performance requirements. We 
believe that the Staff Preliminary Assessment correctly advocated the 
establishment of a maximum time period for corrective control actions 
when a protective relay or equipment failure reduces reliability, i.e., 
performance requirements that are consistent with mitigating IROL 
violations.
    816. The Commission believes that CenterPoint also misinterpreted 
the Staff Preliminary Assessment's concern. The Staff Preliminary 
Assessment advises the addition of a requirement that transmission 
operators carry out corrective control actions to return the system to 
a secure state, i.e., respecting system performance requirements, by 
recognizing the reduction in IROL due to a failed relay or protection 
system elements in no longer than 30 minutes. It is generally 
understood that the corrective actions stated in this Reliability 
Standard do not include actions requiring the field protection and 
control personnel to respond and repair faulty relays or failed 
protection system elements as this type of repair would normally take 
hours, if not days.
    817. The Commission does not share CPUC's view that the Staff 
Preliminary Assessment is advocating a rigid 30-minute requirement to 
re-adjust the system or fix or replace failed protection system 
elements. Since failures of relays or protection system elements would 
expose the Bulk-Power System to cascading outages through a possible 
failure to respect performance requirements, we believe that 
transmission operators and generator operators must take corrective 
control actions in the same manner used to mitigate IROL violations as 
stipulated in relevant IRO and TOP Reliability Standards, as soon as 
possible but no more than 30 minutes.
    818. The Commission agrees with ReliabilityFirst that protection 
system elements must be replaced as soon as possible, and PRC-001-0 
should clearly state that system performance requirements must continue 
to be met when the affected protection system element is out of 
service.
    819. Although the Commission has identified concerns regarding PRC-
001-0's lack of a maximum interval for corrective control action when a 
protection system element has failed and reduced reliability, i.e., 
system performance requirements, we believe that the proposed 
Reliability Standard provides a good base and is integral to ensuring 
that system protection is coordinated among operating entities. The 
Commission also believes that it is important for NERC to provide 
Measures and Levels of Non-Compliance for the proposed Reliability 
Standard. However, the Requirements set forth in PRC-001-0 are 
sufficiently clear and objective to provide guidance for compliance.
    820. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PRC-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 
proposes to direct that NERC submit a modification to PRC-001-0 that: 
(1) Includes Measures and Levels of Non-Compliance; (2) includes a 
requirement that relevant transmission operators and generator 
operators must 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 can carry out 
the appropriate corrective control actions consistent with those used 
in mitigating IROL violations; and (3) clarifies that, after being 
informed of failures in relays or protection system elements on the 
Bulk-Power System, transmission operators or generator 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.
c. Define Regional Disturbance Monitoring and Requirements (PRC-002-1)
i. NERC Proposal
    821. Proposed Reliability Standard 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.
    822. NERC's August 28, 2006 Supplemental Filing, as corrected on 
September 12, 2006, includes a revised version of PRC-002-0, designated 
as PRC-002-1. This revised Reliability Standard still applies to 
regional reliability organizations. Both of the original Requirements 
have been substantially revised.\285\ Requirement R1 from version 0 was 
substantially revised to require the regional reliability organization 
to establish certain installation requirements for sequence of event 
recording. Requirement R2 from version 0 was modified to replace the 
regional reliability organization with transmission owners and 
generator owners and designated as Requirement R5 in version 1. The 
revised PRC-002-1 includes four new Requirements: Requirement R2 
(installation requirement for fault recording), Requirement R3 
(installation requirement for dynamic disturbance recording), 
Requirement R4 (disturbance data reporting requirements), and 
Requirement R6 (regional reliability organization requirement to 
periodically review, update, and approve regional requirements for 
disturbance monitoring and reporting). In PRC-002-1, two new Measures 
for Requirements R4 and R6 have been added and compliance was modified 
to include new Requirements.
---------------------------------------------------------------------------

    \285\ We note that PRC-002-0 has been revised and separated into 
two Reliability Standards, PRC-002-1 (Define Regional Disturbance 
Monitoring and Reporting Requirements) and PRC-018-1 (Disturbance 
Monitoring Equipment Installation and Data Reporting).
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    823. The Staff Preliminary Assessment noted that PRC-002-0 is a 
fill-in-the-blank standard and identifies the regional reliability 
organization as the sole applicable entity, and PRC-002-1 does as well.
iii. Comments
    824. A number of commenters discussed how the Commission should 
address PRC-002-1 and other Reliability Standards in the PRC group that 
are ``fill-in-the-blank'' standards.\286\

[[Page 64847]]

CPUC and National Grid share the Staff Preliminary Assessment's concern 
that certain ``fill-in-the-blank'' Reliability Standards are not 
written in a manner allowing enforcement against users, owners and 
operators of the Bulk-Power System. They point out that some of these 
Reliability Standards must be ``substantively regional'' due to their 
unique characteristics and the physical realities of various regional 
transmission grids, citing examples such as under-frequency load 
shedding (UFLS) and under-voltage load shedding (UVLS) schemes, which 
are necessarily regionally unique. Further, they state that some are 
``procedurally regional'' because they must be implemented by a 
regional body.\287\ National Grid urges the Commission and NERC that 
any revision of these Reliability Standards must adequately address 
these substantive and procedural concerns.
---------------------------------------------------------------------------

    \286\ CPUC, FRCC, National Grid, NPCC, NYSRC, ReliabilityFirst, 
Southern and TANC. Their comments also apply to PRC-003-1, PRC-006-
0, PRC-012-0, PRC-013-0; PRC-014-0 and PRC-020-1.
    \287\ An example of this is PRC-013-0, which requires the 
establishment of a regional database for special protection systems.
---------------------------------------------------------------------------

    825. Southern indicates that the industry and NERC are currently 
considering revisions to the ``fill-in-the-blank'' standards. It states 
that revision would require a significant amount of time and 
coordination within the industry. Mandatory Reliability Standards must 
enhance and not detract from reliability.
    826. TANC advises the Commission to approve these ``fill-in-the-
blank'' Reliability Standards on an interim basis until the applicable 
Regional Entities and NERC have conducted the appropriate approval 
procedure and are able to re-submit these Reliability Standards in 
final form to the Commission for its approval.
iv. Commission Proposal
    827. Because regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
002-1 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
PRC-002-1 should continue on its present basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice.
d. Regional Procedure for Analysis of Misoperations of Transmission and 
Generation Protection Systems (PRC-003-1)
i. NERC Proposal
    828. 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 have. 
This Reliability Standard requires the regional reliability 
organization to develop a procedure to monitor and review misoperations 
of protection systems as well as the development and documentation of 
corrective actions. As discussed in PRC-002-0, this is one of the 
proposed Reliability Standards referred to as a ``fill-in-the-blank'' 
Reliability Standard.
ii. Staff Preliminary Assessment
    829. Similar to its discussion of PRC-002-0, staff noted that this 
Reliability Standard designates a regional reliability organization as 
the sole applicable entity. Staff was concerned about the feasibility 
of a regional reliability organization serving as the applicable entity 
and the enforceability of the proposed Reliability Standard in the 
mandatory Reliability Standards structure.
iii. Comments
    830. A number of commenters discussed how the Commission should 
address PRC-003 and other Reliability Standards in the PRC group that 
are ``fill-in-the-blank'' standards. In addition, ISO/RTO Council 
states that PRC-003-1 needs to better define the contents of the 
procedures in the Requirements and that the proposed Reliability 
Standard is unclear about how it may be effectively measured.
iv. Commission Proposal
    831. The Commission does not share ISO/RTO Council's view that a 
better definition of the contents of the regional reliability 
organization's procedure is required. We refer to the list of elements 
that are included in Requirements R1.1 to R1.5 to address transmission 
system protection misoperations. In addition, we note that PRC-003-1 
contains two Measures requiring these procedures to be available and 
submitted on a timely basis upon request.
    832. Because the regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
003-1 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
PRC-003-1 should continue on its present basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice.
e. Analysis and Reporting of Transmission Protection System 
Misoperations (PRC-004-1)
i. NERC Proposal
    833. Proposed Reliability Standard 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.
ii. Staff Preliminary Assessment
    834. No substantive issues were identified regarding PRC-004-1.
iii. Comments
    835. MEAG states that, if a distribution provider owns a 
transmission protection system, the distribution provider is also a 
transmission owner according to NERC's glossary definition. MEAG 
comments that it is unnecessary, overbroad and contrary to FPA section 
215 to include distribution providers in any of the proposed PRC 
Reliability Standards when the term ``transmission owner'' is 
sufficient to cover the scope of entities that own transmission 
protection systems.
    836. ISO/RTO Council comments that PRC-004-1 should clarify the 
definition of what the procedures must contain and how PRC-004-1 can be 
effectively measured.
iv. Commission Proposal
    837. We disagree with the ISO/RTO Council that the Requirements and 
Measures of the proposed Reliability Standard are unclear. Requirement 
R1 requires the owners of transmission protection systems to analyze 
all protection system misoperations, take corrective actions and 
provide the associated analysis documents with corrective action plans 
to NERC. Further PRC-004-1 contains Measures that

[[Page 64848]]

these owners have evidence that they analyzed protection system 
misoperations and took corrective actions, with all associated 
documentation provided.
    838. The applicability section of PRC-004-1 provides that, inter 
alia, a ``Distribution Provider that owns a transmission Protection 
System'' must comply with this Reliability Standard. This applicability 
provision makes clear that the Reliability Standard applies only to a 
subset of distribution providers. We believe that this approach is 
appropriate. With regard to MEAG's concern, the Commission disagrees 
with MEAG that a distribution provider by virtue of owning transmission 
protection equipment becomes a transmission owner, which would then be 
subject to all of the Reliability Standards applicable to a 
transmission owner.
    839. Reliability Standard PRC-004-1 serves an important purpose in 
ensuring that transmission and generation protection system 
misoperations affecting the reliability of the Bulk-Power System are 
analyzed and mitigated. For the reasons discussed above, the Commission 
believes that Reliability Standard PRC-004-1 is just, reasonable, not 
unduly discriminatory or preferential, and in the public interest; and 
proposes to approve it as mandatory and enforceable.
f. Transmission Protection System Maintenance and Testing (PRC-005-1)
i. NERC Proposal
    840. Proposed Reliability Standard 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.
ii. Staff Preliminary Assessment
    841. The Staff Preliminary Assessment stated that protection 
systems must be maintained and tested at regular intervals to ensure 
that they will operate as intended when called upon and that 
maintenance intervals vary depending on the type and nature of the 
protection system, as well as the reliability impact of a potential 
failure of that system. Staff identified several Reliability Standards 
in the PRC group addressing the maintenance and testing of different 
protection systems that are technically deficient because they do not 
specify the criteria to determine the appropriate maintenance 
intervals, and they do not specify maximum allowable maintenance 
intervals for the protections systems.\288\
---------------------------------------------------------------------------

    \288\ Staff identified several other PRC Reliability Standards 
such as PRC-005-1, PRC-008-0, PRC-011-0 and PRC-017-0 that contain 
similar concerns.
---------------------------------------------------------------------------

    842. Staff cited PRC-006-0 as good example of a Reliability 
Standard that requires periodic assessments of the effectiveness of 
regional UFLS programs at least once every five years regardless of the 
circumstance.
iii. Comments
    843. NERC states that it welcomes discussion and debate on the 
proper study and maintenance intervals for regular and special 
protection systems. It will consider these comments in the re-
authorization of these Reliability Standards or the development of 
future Reliability Standards. Within its existing scope, the NERC 
System Protection and Controls Task Force will examine all PRC 
Reliability Standards for consistency and technical completeness. It 
will then propose any appropriate modifications through the standards 
process.
    844. ISO/RTO Council echoes the concerns of the Staff Preliminary 
Assessment that the proposed Reliability Standard must define the 
missing maintenance intervals.
    845. ReliabilityFirst contends that the purpose of PRC-005-1 does 
not call for specific justification for allowable maintenance 
intervals, it calls for intervals only. However, it urges NERC to 
develop maximum allowable intervals based on reliability-centered study 
results developed by the regions and companies therein.
iv. Commission Proposal
    846. The Commission proposes to approve PRC-005-1 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard as discussed below.
    847. Proposed Reliability Standard PRC-005-1 does not specify the 
criteria to determine the appropriate maintenance intervals, nor does 
it specify maximum allowable maintenance intervals for the protections 
systems. The Commission therefore proposes that NERC include a 
requirement that maintenance and testing of these protection systems 
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.
    848. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PRC-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 
proposes to direct that NERC 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.
g. Development and Documentation of Regional UFLS Programs (PRC-006-0)
i. NERC Proposal
    849. Proposed Reliability Standard PRC-006-0 ensures the 
development of a regional UFLS 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 is a ``fill-
in-the-blank'' standard that requires the regional reliability 
organization to develop, coordinate, document and assess UFLS program 
design and effectiveness at least every five years.
ii. Staff Preliminary Assessment
    850. The Staff Preliminary Assessment identified two concerns for 
PRC-006-0: (1) A regional reliability organization is identified as the 
sole applicable entity; and (2) it lacks the proper specificity for an 
integrated and coordinated approach for the protection systems for 
generators, transmission lines and UFLS and UVLS programs as 
recommended by the Blackout Report.\289\
---------------------------------------------------------------------------

    \289\ Blackout Report, Recommendation No. 21 at 159.
---------------------------------------------------------------------------

    Staff also pointed out that the proposed Reliability Standard 
requires a periodic assessment of the effectiveness of the regional 
UFLS programs and design details at least once every five years, which 
is a good example of a maximum allowable interval without specific 
justification.
iii. Comments
    851. NERC claims that it is addressing Staff's concern that PRC-
006-0 lacks an integrated and coordinated approach to protection for 
generators, transmission

[[Page 64849]]

lines and UFLS and UVLS programs within its work on the ``fill-in-the-
blank'' proposed Reliability Standards. However, NERC points out that 
Requirement R3 of EOP-003-0 obligates transmission operators and 
balancing authorities to coordinate load shedding plans among other 
interconnected transmission operators and balancing authorities.
    852. Alcoa contends that proposed Reliability Standards PRC-006-0 
and EOP-003-0 essentially assign similar responsibilities to different 
entities, thereby creating the potential for ambiguity. It states that 
while EOP-003-0 applies to transmission operators and balancing 
authorities and PRC-006-0 applies to regional reliability 
organizations, requirements in both proposed Reliability Standards 
mandate the design of a load shedding scheme, including frequency set 
points as a design component, under abnormal system conditions.
    853. CenterPoint believes that the proposed Reliability Standard 
adequately addresses the integration and coordination issues, but does 
not address coordination between the generator low voltage ride-through 
requirement, UVLS and dynamic voltage recovery requirements. Further, 
it states that such coordination is not addressed by the proposed 
Reliability Standard because the underlying requirements are missing.
    854. ReliabilityFirst suggests that NERC should develop an 
Interconnection-based program and use the programs developed by the 
regions within the Interconnection as a starting point. It believes 
that the primary objective of the proposed Reliability Standards is to 
meet system performance requirements and suggests that more definitive 
measurable requirements should be developed to create an integrated and 
coordinated approach to Bulk-Power System protection.
iv. Commission Proposal
    855. Because the regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
006-0 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
PRC-006-0 should continue on its current basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice. Although we do not propose to approve or remand 
with regard to MOD-002-0 at this time, we address comments and our 
additional concerns regarding this Reliability Standard below.
    856. The Commission commends NERC's initiative in adopting 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. Responding to 
NERC's comments on Requirement R3 of EOP-003-0, the Commission cautions 
that it only addresses a relatively small portion of the coordination 
of load shedding plans among other interconnected entities, but still 
lacks the main and overall integration and coordination requirements 
for all protection systems in the Bulk-Power System.
    857. The Commission disagrees with Alcoa that Reliability Standards 
PRC-006-0 and EOP-003-0 essentially assign similar responsibilities to 
different entities, thereby creating the potential for ambiguity. There 
are distinctive features of UFLS programs which are designed to trip 
load automatically within seconds upon detection of abnormal system 
conditions due to the imbalance of generation and load resulting in 
rapidly declining interconnected system frequencies. Therefore, the 
design and coordination of UFLS programs must be region-wide or 
Interconnection-wide to ensure their effectiveness as covered by PRC-
006-0. The load shedding plans that are covered in EOP-003-0 are also 
required as an operating measure of last resort to address system 
emergencies in which declining system frequency may not be a prevailing 
indicator. Instead, system voltages may fast approach voltage 
instability, system elements may be severely overloaded or an IROL of a 
critical interface may be severely exceeded. All of these are 
indicators of an imminent threat of cascading outages while system 
operators have exhausted all available corrective actions to return the 
system to a secure state. In addition, load shedding plans usually 
consist of several components including UFLS or UVLS with different 
levels of response time to facilitate load shedding. Some load shedding 
capability is achieved via remote SCADA control from the transmission 
operators' control room and some via manual disconnection by load 
serving entities under direct order from a transmission operator or 
reliability coordinator during system emergencies. In some cases, 
transmission operators may use system reconfiguration to disconnect 
large blocks of load as a part of their load shedding plans. The 
Commission views PRC-006-0 and EOP-003-0 as two separate and necessary 
Reliability Standards and the small overlap between the two is 
necessary to ensure that effective load shedding capabilities are 
available to address a wide range of emergency operating conditions.
    858. The Commission disagrees with CenterPoint that adequate 
integration and coordination is already included in PRC-006-0 because 
this is contrary to NERC's initiative in adopting an integrated and 
coordinated approach to protection for generators, transmission lines 
and UFLS and UVLS programs. However, we support CenterPoint's 
recommendation that the generator under-voltage ride-through capability 
is an important element that should be included in the integrated and 
coordinated approach among relay protection for generators and 
transmission lines and the use of UFLS and UVLS programs.
    859. In response to ReliabilityFirst's suggestion to include 
additional definitive measures to meet system performance, the 
Commission believes that the technical requirements should first 
include the integrated and coordinated approach in Bulk-Power System 
protection, including the frequency response of the interconnection to 
load and generation loss. Compliance Measures should be definitive to 
ensure these technical requirements are met.
h. Assuring Consistency With Regional UFLS Program Requirements (PRC-
007-0)
i. NERC Proposal
    860. Proposed Reliability Standard PRC-007-0 requires transmission 
owners, transmission operators, load-serving entities, and distribution 
providers to provide, and annually update, their under-frequency data 
to facilitate the regional reliability organization's maintenance of, 
and updates to, the UFLS program database. Transmission owners and 
distribution providers must provide documentation of their UFLS program 
to the regional reliability organization.
ii. Staff Preliminary Assessment
    861. No substantive issues were identified regarding PRC-007-0.
iii. Comments
    862. CPUC states that PRC-007-0 is an example of a Reliability 
Standard that should be mandatory on a national level, but for which it 
is appropriate for the details of implementation to be

[[Page 64850]]

delegated to a regional reliability organization. ISO/RTO Council 
states that PRC-007-0 fails to define an acceptable UFLS program.
iv. Commission Proposal
    863. With regard to ISO/RTO Council's comment, the specification of 
an acceptable UFLS program is the subject of PRC-006-0. In contrast, 
PRC-007-0 provides that, if an entity has a UFLS program, the program 
must be consistent with its regional reliability organization's 
requirements.
    864. The Commission believes that there are no substantive issues 
with this proposed Reliability Standard. We note that, once approved, 
the proposed Reliability Standard will be applied and enforced on a 
national scale as suggested by CPUC.
    865. Accordingly, the Commission proposes to approve PRC-007-0 as 
mandatory and enforceable. We believe that the proposed Reliability 
Standard is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest.
i. Under Frequency Load Shedding Equipment Maintenance Programs (PRC-
008-0)
i. NERC Proposal
    866. Proposed Reliability Standard 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.
ii. Staff Preliminary Assessment
    867. According to the Staff Preliminary Assessment, PRC-008-0 does 
not specify the criteria to determine appropriate maintenance intervals 
or the maximum allowable interval to ensure effectiveness, as discussed 
in detail in the Staff Preliminary Assessment section of this 
rulemaking under PRC-005-1. No other substantive issues were identified 
for this proposed Reliability Standard.
iii. Comments
    868. Commenter's statements regarding maximum allowable intervals 
for the performance of maintenance and testing programs have been 
presented in detail under the comments for PRC-005-1.
iv. Commission Proposal
    869. The Commission notes that the commenters generally share 
staff's concern that the proposed Reliability Standard does not specify 
the criteria to determine the appropriate maintenance intervals, nor 
does it specify maximum allowable maintenance intervals for the 
protection systems. The Commission agrees and proposes to require NERC 
to modify the proposed Reliability Standard to include a requirement 
that maintenance and testing of UFLS programs must be carried out 
within a maximum allowable interval that is appropriate to the type of 
relay used and the impact on the reliability of the Bulk-Power System.
    870. Accordingly, the Commission proposes to approve Reliability 
Standard PRC-008-0 as mandatory and enforceable. In addition, the 
Commission proposes to direct that NERC 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.
j. UFLS Performance Following an Under Frequency Event (PRC-009-0)
i. NERC Proposal
    871. Proposed Reliability Standard PRC-009-0 ensures that the 
performance of an UFLS system is analyzed and documented following an 
under frequency event by requiring the transmission owner, transmission 
operator, load-serving entity and distribution provider to document 
their operation in accordance with the regional reliability 
organization's program and to provide that documentation to the 
regional reliability organization and NERC upon their request.
ii. Staff Preliminary Assessment
    872. Staff noted that, although the proposed Reliability Standard 
contains the reporting requirement for operation events for UFLS, there 
is no similar reporting requirement for operation events for UVLS in 
the proposed Reliability Standards that are associated with UVLS 
programs.
iii. Comments
    873. ReliabilityFirst supports the development of a companion UVLS 
Reliability Standard with reporting requirements that are similar to 
this UFLS Reliability Standard. Likewise, NERC acknowledges the 
concerns of the Staff Preliminary Assessment, noting the lack of a 
reporting requirement for operation events of UVLS and plans to address 
this omission in its work on the ``fill-in-the-blank'' proposed 
Reliability Standards that are associated with UVLS.
    874. ISO/RTO Council states that, due to the fact that PRC-009-0 
inappropriately relies on the undefined UFLS programs of regional 
reliability organizations, NERC must review and approve the regional 
reliability organizations' programs before the proposed Reliability 
Standard can go into effect.
    875. TAPS states that PRC-009-0 requires distribution providers 
with a transmission protection program to analyze an under-frequency 
event and document the post-mortem. It cautions that it may be 
difficult and unduly burdensome for a small entity to perform given 
limited access to event data and the need to perform a stability 
analysis.
    876. CenterPoint suggests adopting a performance metric approach 
rather than a ``fill-in-the-blank'' approach to this Reliability 
Standard. It contends that compliance should be straightforward since 
transmission and distribution service providers are supposed to trip a 
certain amount of load under specified under-frequency conditions. 
Therefore, either the utility tripped the required amount of load or it 
did not, perhaps with some bandwidth.
iv. Commission Proposal
    877. The Commission discusses ISO/RTO Council's comments on the 
general issue that regional Reliability Standards must be approved by 
the ERO and the Commission before they become effective above in the 
section on Common Issues.
    878. The Commission does not find any material difference between 
CenterPoint's suggestion to use a performance metric approach and the 
Requirements in this proposed Reliability Standard. We believe 
performance metrics, especially leading metrics, are excellent 
complementary components in Reliability Standards which enable further 
enhancement and effectiveness of these Reliability Standards.
    879. With respect to TAPS' concern regarding the size of 
distribution providers and load serving entities, the Commission 
discusses this issue in the Common Issues section of this NOPR.
    880. The Commission believes that the proposal serves an important 
purpose in ensuring that the performance of an UFLS system is analyzed 
and documented following an under frequency event. Further the proposed 
Requirements are sufficiently clear and objective to provide guidance 
for compliance. Accordingly, the Commission proposes to approve PRC-
009-0 as mandatory and enforceable. We believe that the proposed 
Reliability Standard is just, reasonable, not unduly

[[Page 64851]]

discriminatory or preferential, and in the public interest.
k. Assessment of the Design and Effectiveness of UVLS Program (PRC-010-
0)
i. NERC Proposal
    881. Proposed Reliability Standard PRC-010-0 requires transmission 
owners, transmission operators, load-serving entities, and distribution 
providers to periodically conduct and document an assessment of the 
effectiveness of the UVLS program.\290\ This assessment shall be 
conducted with the associated transmission planner and planning 
authority.
---------------------------------------------------------------------------

    \290\ At least every five years or as required by changes in 
system conditions.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    882. The Staff Preliminary Assessment raised the concern that this 
proposed Reliability Standard on UVLS, similar to PRC-006-0 on UFLS, is 
not specific enough to address Blackout Report Recommendation No. 21 
concerning an integrated and coordinated approach for the protection 
systems for generators, transmission lines and UFLS and UVLS 
programs.\291\
---------------------------------------------------------------------------

    \291\ Blackout Report at 159.
---------------------------------------------------------------------------

iii. Comments
    883. NERC states that it has made progress in responding to 
Blackout Recommendation No. 21 on the Evaluation of Applicability of 
UVLS programs. The NERC Planning Committee reviewed each regional 
reliability organization's assessment of the feasibility and benefits 
of installing UVLS capability. In addition, the NERC Planning Committee 
has completed a report entitled, ``Review of Regional Evaluations of 
Under-voltage Load Shedding Capability in Response to NERC Blackout 
Recommendation 8b,'' \292\ with follow-up recommendations to be 
completed by the NERC Planning Committee and the regions, along with an 
implementation plan. NERC further states that the work is ongoing under 
the supervision of the NERC Planning Committee and will result in 
requests for new standards as the work is completed and suitable 
methods and criteria are developed.
---------------------------------------------------------------------------

    \292\ Available at http://www.nerc.com/~filez/reports.html.

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

    884. CenterPoint questions the need for this Reliability Standard 
and the other three Reliability Standards that address other UVLS 
requirements,\293\ while acknowledging that there is a significant need 
for UVLS for some systems. CenterPoint contends that it is unreasonable 
and unnecessary to require examination and documentation of any and all 
UVLS trips. Further, it states that producing unnecessary Reliability 
Standards for utilities that install UVLS schemes could have the 
adverse effect of discouraging utilities that might benefit from UVLS 
by installing the schemes or, alternatively, punishing the utilities 
that do so.
---------------------------------------------------------------------------

    \293\ PRC-010-0, PRC-020-1 and PRC-021-1.
---------------------------------------------------------------------------

    885. MEAG seeks a clarification in the specific instance where the 
transmission owner owns and maintains a transmission protection system, 
e.g., a UFLS or UVLS system, and where some of the associated relays 
are designed to trip a distribution breaker owned by a customer.
    886. ReliabilityFirst suggests an integrated and coordinated 
approach to Bulk-Power System protection, as discussed above in the 
context of PRC-006-0.
iv. Commission Proposal
    887. The Commission commends the initiative and efforts that have 
been taken by NERC and industry in addressing UVLS requirements as 
recommended by the Blackout Report and expects to review these 
improvements in the proposed Reliability Standards associated with UVLS 
in their future revisions.
    888. The Commission believes that Reliability Standards of UVLS are 
required in the same manner as Reliability Standards for line and 
generation protection, UFLS or special protection systems since all of 
them are required to ensure reliable system operation. Therefore, we 
disagree with CenterPoint's view that UVLS Reliability Standards are 
not necessary.
    889. In response to a question raised by MEAG regarding the 
ownership of an UFLS or UVLS installed by a transmission owner on a 
breaker owned by a customer, the transmission owner remains the owner. 
The transmission owner or transmission operator can trip the breaker 
automatically or have a delegated agreement with the customer to trip 
the breaker in case of an UFLS or UVLS event. The Commission believes 
that the Reliability Standard should be interpreted to achieve its 
reliability goal. This can be accomplished by each entity performing 
their required maintenance and operational activities or by one entity 
doing the required activities. However, the UFLS or UVLS system must be 
maintained from the sensors that detect the event to the actual opening 
of the circuit breaker.
    890. In response to ReliabilityFirst's suggestion to include 
additional definitive measures to meet system performance, the 
Commission believes that the technical requirements should include an 
integrated and coordinated approach in Bulk-Power System protection, 
including the frequency response of the interconnection to load and 
generation loss. Compliance Measures should be definitive to ensure 
these technical requirements are met.
    891. The Commission believes that Reliability Standard PRC-010-0 
serves an important purpose in requiring the periodical assessment of 
the effectiveness of a UVLS program. Further, the proposed Requirements 
are sufficiently clear and objective to provide guidance for 
compliance.
    892. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PRC-010-0 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 
proposes to direct that NERC 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 
lines, generator's low voltage ride-through capabilities, and UFLS and 
UVLS programs.
l. Under Voltage Load Shedding System Maintenance and Testing (PRC-011-
0)
i. NERC Proposal
    893. Proposed Reliability Standard PRC-011-0 requires transmission 
owners and distribution providers to implement their UVLS equipment 
maintenance and testing program and provide program results to regional 
reliability organization.
ii. Staff Preliminary Assessment
    894. Staff expressed concern that PRC-011-0 does not specify the 
criteria to determine the appropriate maintenance intervals or maximum 
allowable intervals for protection systems to ensure effectiveness has 
been articulated in detail in the same section in PRC-005-1.
iii. Comments
    895. NERC indicates that it will consider maximum intervals; and 
ISO/RTO Council and other commenters

[[Page 64852]]

agree with the Staff Preliminary Assessment.\294\
---------------------------------------------------------------------------

    \294\ While commenters raise these concerns primarily in the 
context of PRC-005-1, their comments apply to PRC-011-0 as well.
---------------------------------------------------------------------------

iv. Commission Proposal
    896. PRC-011-0 does not specify the criteria to determine the 
appropriate maintenance intervals, nor does it specify maximum 
allowable maintenance intervals for the protections systems. The 
Commission proposes that NERC include a Requirement that maintenance 
and testing of these UFLS programs must be carried out within a maximum 
allowable interval that is appropriate to the type of the relay used 
and the impact of these UFLS on the reliability of the Bulk-Power 
System.
    897. The Commission believes that Reliability Standard PRC-011-0 
serves an important purpose in requiring transmission owners and 
distribution providers to implement their UVLS equipment maintenance 
and testing programs. Further, the proposed Requirements are 
sufficiently clear and objective to provide guidance for compliance.
    898. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PRC-011-0 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 
proposes to direct that NERC 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 applicable relay and the impact on the reliability of the Bulk-
Power System.
m. Special Protection System Review Procedure (PRC-012-0)
i. NERC Proposal
    899. Proposed Reliability Standard PRC-012-0 requires regional 
reliability organizations to ensure that all special protection systems 
\295\ are properly designed, meet performance requirements and are 
coordinated with other protection systems. Maintenance and testing 
programs must be developed and special protection system misoperations 
must be analyzed and corrected.
---------------------------------------------------------------------------

    \295\ A special protection system is a unique system designed to 
automatically take corrective actions to protect the system under 
abnormal or predetermined conditions, excluding the coordinated 
tripping of circuit breakers to isolate faulted components, which is 
typically the purpose of other protection devices.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    900. Similar to its discussion of PRC-002-1, staff noted that 
Reliability Standard designates a regional reliability organization as 
the sole applicable entity.
iii. Comments
    901. A number of commenters discussed how the Commission should 
address PRC-012-0 and other fill-in-the-blank standards in the PRC 
group that require compliance by regional reliability 
organizations.\296\
---------------------------------------------------------------------------

    \296\ 296 CPUC, FRCC, National Grid, NPCC, NYSRC, 
ReliabilityFirst, Southern and TANC. Their comments also apply to 
PRC-003-1, PRC-006-0, PRC-012-0, PRC-013-0; PRC-014-0 and PRC-020-1.
---------------------------------------------------------------------------

iv. Commission Proposal
    902. Because the regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
012-0 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
PRC-012-0 should continue on its current basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice.
n. Special Protection System Database (PRC-013-0)
i. NERC Proposal
    903. Proposed Reliability Standard 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 pertinent information on special protection systems.
ii. Staff Preliminary Assessment
    904. Similar to its discussion of PRC-002-1, staff noted that this 
Reliability Standard designates a regional reliability organization as 
the sole applicable entity.
iii. Comments
    905. A number of commenters discussed how the Commission should 
address PRC-012-0 and other fill-in-the-blank standards in the PRC 
group that require compliance by regional reliability organizations.
    906. ISO/RTO Council states that this Reliability Standard 
identifies only categories rather than the detailed data useful for 
ensuring that a meaningful special protection system database is 
maintained.
    907. National Grid identifies this Reliability Standard as one of 
those it refers to as ``procedurally regional.'' That is, the 
requirement is set on a national level but is implemented regionally. 
In the case of PRC-013-0, all relevant entities would be required to 
provide information to databases established and maintained by some 
regional body. National Grid explains that this is one example of a 
legitimate ``fill-in-the-blank'' Reliability Standard.
iv. Commission Proposal
    908. The Commission believes that the current Requirements and 
Measures in the proposed Reliability Standard are adequate, and 
therefore, disagrees with ISO/RTO Council's comments in this regard. 
Requirement R1 includes three categories of data with each category 
providing a more detailed description of required data. Measure M1 
requires that each owner with a special protection system must have the 
corresponding database as specified in the proposed Reliability 
Standard.
    909. We agree with National Grid that the database should be 
maintained on a regional basis. However, Regional Entities have not 
undergone an approval process under section 215. Therefore, we cannot 
yet enforce this requirement.
    910. Because the regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
013-0 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
PRC-013-0 should continue on its current basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice.

[[Page 64853]]

o. Special Protection System Assessment (PRC-014-0)
i. NERC Proposal
    911. Proposed Reliability Standard 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, compliance with NERC Reliability 
Standards, as well as the effectiveness of special protection systems, 
at least once every five years.
ii. Staff Preliminary Assessment
    912. Similar to its discussion of PRC-002-1, staff noted that this 
Reliability Standard designates a regional reliability organization as 
the sole applicable entity.
    913. The Staff Preliminary Assessment noted that the maximum 
allowable interval of at least once every five years as a Requirement 
for assessing the effectiveness of the special protection systems is a 
good example of a maximum allowable interval without specific 
justification.
iii. Comments
    914. A number of commenters discussed how the Commission should 
address PRC-012-0 and other fill-in-the-blank standards in the PRC 
group that require compliance by regional reliability organizations.
iv. Commission Proposal
    915. Because the regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
014-0 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits the regional procedures or a single continent-wide 
procedure. In the interim, compliance with PRC-014-0 should continue on 
its current basis, and the Commission considers compliance with the 
Reliability Standard to be a matter of good utility practice.
p. Special Protection System Data and Documentation (PRC-015-0)
i. NERC Proposal
    916. 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 for 
existing, new, or functionally modified special protection systems.
ii. Staff Preliminary Assessment
    917. No substantive issues were identified for the proposed 
Reliability Standard.
iii. Comments
    918. The ISO/RTO Council believes that the time period used for 
assessing compliance is not clear in this Reliability Standard.
iv. Commission Proposal
    919. The Commission believes that there are no substantive issues 
identified for this proposed Reliability Standard.
    920. We disagree with ISO/RTO Council's view that the compliance 
time period is not clear. Requirement 3 of this Reliability Standard 
requires documentation to be provided within 30 days for compliance 
requirements.
    921. Accordingly, the Commission proposes to approve PRC-015-0 as 
mandatory and enforceable. We believe that the proposed Reliability 
Standard is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest.
q. Special Protection System Misoperations (PRC-016-0)
i. NERC Proposal
    922. Proposed Reliability Standard 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.
ii. Staff Preliminary Assessment
    923. No substantive issues were identified for the proposed 
Reliability Standard.
iii. Comments
    924. ISO/RTO Council is concerned that this Reliability Standard 
fails to identify the analysis sufficient for reviewing special 
protection system operations and the type of corrective action that 
must be taken to avoid misoperations. It also believes that reports on 
special protection system misoperations should be routinely provided to 
the regional reliability organization and NERC.
iv. Commission Proposal
    925. We disagree with ISO/RTO Council that PRC-016-0 does not 
identify the analysis sufficient for reviewing special protection 
systems and the type of corrective actions required to avoid 
misoperations. However, we agree that reports on special protection 
system misoperations should be routinely provided to the regional 
reliability organization and NERC and propose to require NERC to 
provide that routine reporting be limited to misoperations of special 
protection systems that have Interconnection-wide reliable impact and 
routine submission of the corrective action plans upon implementation 
instead of the current requirement of 90 days upon request.
    926. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PRC-016-0 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 
proposes to direct that NERC submit a modification to PRC-016-0 that 
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 for the type of relaying used 
and the impact of these special system protection programs on the 
reliability of the Bulk-Power System.
r. Special Protection System Maintenance and Testing (PRC-017-0)
i. NERC Proposal
    927. Proposed Reliability Standard PRC-017-0 requires transmission 
owners, generator owners, and distribution providers to provide the 
regional reliability organization with documentation on special 
protection system maintenance, testing and implementation plans.
ii. Staff Preliminary Assessment
    928. Staff expressed concern that this Reliability Standard does 
not specify the criteria to determine the appropriate maintenance 
intervals or maximum allowable intervals for protection systems to 
ensure effectiveness.
iii. Comments
    929. The comments provided by ISO/RTO Council and NERC regarding 
maximum allowable intervals in carrying out maintenance and testing 
programs in the PRC Reliability Standards have been presented in detail 
in PRC-005-1.

[[Page 64854]]

iv. Commission Proposal
    930. PRC-017-0 does not specify the criteria to determine the 
appropriate maintenance intervals, nor does it specify maximum 
allowable maintenance intervals for the protections systems. The 
Commission proposes to require NERC to include 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 the impact of these 
special protection system programs on the reliability of the Bulk-Power 
System.
    931. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard PRC-017-0 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 
proposes to direct that NERC 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.
s. Disturbance Monitoring Equipment Installation and Data Reporting 
(PRC-018-1)
i. NERC Proposal
    932. Proposed Reliability Standard PRC-018-1 ensures that 
disturbance monitoring equipment is installed and disturbance data is 
reported in accordance with comprehensive requirements for installing 
disturbance monitoring equipment.
ii. Staff Preliminary Assessment
    933. This is a new Reliability Standard and it was not assessed in 
the Staff Preliminary Assessment.
iii. Comments
    934. Because this Reliability Standard was not discussed in the 
Staff Preliminary Assessment, no comments have been filed.
iv. Commission Proposal
    935. The Commission notes that the proposed Reliability Standard 
addressed Blackout Report Recommendation No. 28 by requiring the 
transmission owner and generator owner to install disturbance 
monitoring equipment and report disturbance data. The Commission 
commends the initiative and efforts taken by NERC and industry in 
addressing this recommendation.
    936. Accordingly, the Commission proposes to approve PRC-018-1 as 
mandatory and enforceable. We believe that the proposed Reliability 
Standard is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest.
t. Under-Voltage Load Shedding Program Database (PRC-020-1)
i. NERC Proposal
    937. Proposed Reliability Standard 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.
ii. Staff Preliminary Assessment
    938. Staff noted that this version 1 Reliability Standard was 
recently approved by the NERC Board of Trustees, effective May 1, 2006, 
and does not address the applicability concerns articulated in the 
Staff Preliminary Assessment.
    939. In addition, similar to its discussion of PRC-002-1, staff 
noted that this Reliability Standard designates a regional reliability 
organization as the sole applicable entity. Staff was concerned about 
the feasibility of a regional reliability organization serving as the 
applicable entity and the enforceability of the proposed Reliability 
Standard in the mandatory Reliability Standards structure.
iii. Comments
    940. A number of commenters discussed how the Commission should 
address PRC-020-0 and other fill-in-the-blank standards in the PRC 
group that require compliance by regional reliability organizations.
iv. Commission Proposal
    941. Because the regional procedures have not been submitted to the 
Commission, it is not possible to determine at this time whether PRC-
020-1 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 
will not propose to accept or remand this Reliability Standard until 
the ERO submits additional information. In the interim, compliance with 
PRC-020-1 should continue on its current basis, and the Commission 
considers compliance with the Reliability Standard to be a matter of 
good utility practice.
u. Under-Voltage Load Shedding Program Data (PRC-021-1)
i. NERC Proposal
    942. Proposed Reliability Standard 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 
its system and other related protection schemes to its regional 
reliability organization's data base.
ii. Staff Preliminary Assessment
    943. No substantive issues were identified for the proposed 
Reliability Standard PRC-021-1.
iii. Comments
    944. CenterPoint seems to promote eliminating this Reliability 
Standard as stated previously in PRC-010-0.
iv. Commission Proposal
    945. The Commission believes that Reliability Standards for UVLS 
are required in the same manner as Reliability Standards for line and 
generation protection, UFLS or special protection systems since all of 
them are required to ensure reliable system operations. Therefore, we 
disagree with CenterPoint's view that UVLS Reliability Standards are 
not needed.
    946. The Commission proposes to approve, as mandatory and 
enforceable, Reliability Standard PRC-021-1 as just, reasonable, not 
unduly discriminatory or preferential, and in the public interest.
v. Under-Voltage Load Shedding Program Performance (PRC-022-1)
i. NERC Proposal
    947. Proposed Reliability Standard PRC-022-1 requires transmission 
operators, load-serving entities, and distribution providers to provide 
analysis, documentation on UVLS operations and misoperations to the 
regional reliability organization.
ii. Staff Preliminary Assessment
    948. No substantive issues were identified regarding Reliability 
Standard PRC-022-1.
iii. Comments
    949. No comments were filed.
iv. Commission Proposal
    950. The Commission believes that there are no substantive issues 
for this

[[Page 64855]]

proposed Reliability Standard. Therefore, the Commission proposes to 
approve, as mandatory and enforceable, Reliability Standard PRC-022-1 
as just, reasonable, not unduly discriminatory or preferential, and in 
the public interest.
11. TOP: Transmission Operations
a. Overview
    951. The eight proposed 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.
b. Reliability Responsibilities and Authorities (TOP-001-0)
i. NERC Proposal
    952. TOP-001-0 requires that: (a) The 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 load-serving 
entity to take emergency actions when directed to do so in order to 
keep the transmission system intact. The reliability goal of TOP-001-1 
is to: (1) Ensure that system operators have the authority to take 
actions and direct others to take action to maintain Bulk-Power System 
facilities within limits; (2) protect transmission, generation, 
distribution, and customer equipment; and (3) prevent cascading 
failures of the interconnected grid. Further, NERC indicates that it 
plans to modify TOP-001-0 to address the lack of Measures and Levels of 
Non-Compliance.
ii. Staff Preliminary Assessment
    953. The Staff Preliminary Assessment did not identify any 
substantive issues regarding TOP-001-0, other than noting that it does 
not contain Measures or Levels of Non-Compliance.
iii. Comments
    954. MEAG states that, under Requirement R2 a transmission operator 
must take immediate actions to shed load to alleviate an emergency, and 
Requirement R4 obligates distribution providers and load-serving 
entities to do the same. MEAG contends that Requirement R4 should be 
eliminated because, to the extent that a transmission owner relies on a 
distribution provider or load serving entity to respond to a system 
emergency, including load shedding, this should be done through a 
formal agreement with specific protocols that all parties have agreed 
to follow. MEAG states that, as long as Requirement R4 is included in 
the Reliability Standard, an entity may make faulty assumptions about 
the emergency response of another entity.
    955. MRO states that Requirements 7.1, 7.2, and 7.3, which relate 
to coordination when a generation or transmission facility is removed 
from service, appear to be instructions rather than requirements. It 
asks the Commission to revise or remove these Requirements.
iv. Commission Proposal
    956. The Commission proposes to approve TOP-001-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    957. Requirement R1 of TOP-001-0 states that a transmission 
operator must have the responsibility and clear decision-making 
authority ``to take whatever actions are needed to ensure the 
reliability of its area.'' Neither the Reliability Standard nor the 
NERC glossary explains what is meant by a transmission operator's 
``area.'' We interpret the term to mean the area in which the 
transmission facilities under the transmission operator's control are 
located.\297\
---------------------------------------------------------------------------

    \297\ We note that NERC's reliability functional model (Function 
Definitions and Responsible Entities, version 2, approved by the 
Board of Trustees Feb. 10, 2004) defines Reliability Authority Area, 
Balancing Authority Area, Transmission Planning Area, and Planning 
Authority Area, but does not define Transmission Operator Area.
---------------------------------------------------------------------------

    958. We are not persuaded by MEAG's suggestion to eliminate 
Requirement R4 and utilize a formal agreement to determine the response 
of a distribution provider or load serving entity to a system 
emergency. As set forth in Requirement R1, each transmission operator 
must have the responsibility and corresponding decision-making 
authority to take ``whatever actions are needed'' to ensure reliability 
in an emergency. This includes the curtailment of transmission service 
and load shedding. Eliminating the general obligation set forth in 
Requirement R4 that a distribution provider or load serving entity must 
``comply with all reliability directives of the transmission operator * 
* * unless such action would violate safety, equipment, regulatory or 
statutory requirements,'' and replacing it with formal agreements would 
result not only in regional differences but differences in the ability 
of a transmission operator to respond to an emergency on a system-by-
system and contract-by-contract basis. Rather than enhancing 
reliability, we believe that such latitude could result in the 
deterioration of Bulk-Power System reliability.
    959. MRO claims that Requirements R7.1, R7.2, and R7.3 appear to be 
instructions rather than requirements. Requirement R7 provides that 
each transmission operator and generator operator shall not remove 
facilities from service if removing those facilities would burden a 
neighboring system unless certain events occur that are delineated in 
Requirements R7.1, R7.2 and R7.3. While MRO does not explain what it 
considers to be the difference between an instruction and a 
requirement, we interpret that, read together as a whole Requirement R7 
articulates binding obligations on a transmission operator and is 
properly characterized as a requirement.
    960. As mentioned above, TOP-001-0 does not contain Measures or 
Levels of Non-Compliance. However, we believe that the Requirements set 
forth in TOP-001-0 are sufficiently clear and objective to provide 
guidance for compliance. Moreover, TOP-001-0 serves the vital purpose 
of ensuring that transmission operators and others have clear decision-
making authority to take appropriate actions or direct the actions of 
others to return the transmission system to normal conditions during an 
emergency.
    961. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to

[[Page 64856]]

approve Reliability Standard TOP-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 proposes to direct that NERC submit a 
modification to TOP-001-0 that includes Measures and Levels of Non-
Compliance.
c. Normal Operations Planning (TOP-002-1)
i. NERC Proposal
    962. TOP-002-1 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 proposed Reliability 
Standard covers a broad array of matters, including: (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. Further, NERC indicates that it plans to modify 
the Reliability Standard to address the lack of Measures and Levels of 
Non-Compliance.
    963. Two Requirements of particular note are R7 and R14. 
Requirement R7 of TOP-002-1 provides that each balancing authority 
shall plan to meet capacity and energy reserve requirements, including 
being able to deliver power in the case of any single contingency. 
Requirement R14 directs each generator operator to notify its balancing 
authority and transmission operator of changes in: (1) real and 
reactive power output capabilities.\298\
---------------------------------------------------------------------------

    \298\ On August 28, 2006, NERC submitted TOP-002-1 for approval, 
which replaces TOP-002-0. TOP-002-1 simply deletes the Requirement 
R14.2, which required automatic voltage regulators. According to 
NERC, the deleted requirement is now included in the recently 
revised VAR-001-1 and is therefore unnecessary in TOP-002-1.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    964. The Staff Preliminary Assessment noted that Requirement R7 
specifies that capacity and energy reserves must be deliverable to 
local areas in case of a single contingency.\299\ Other Reliability 
Standards require that the system operate in a manner that allows it to 
be returned to a stable state within 30 minutes after a contingency 
occurs with the capacity to withstand another contingency without 
cascading.\300\ In contrast, the Reliability Standard does not require 
the next-day planning analysis to identify control actions that are 
needed to bring the system back to a stable state within 30 minutes 
after a contingency occurs with the capacity to withstand another 
contingency without cascading.\301\ The Staff Preliminary Assessment 
noted that this may present a potential vulnerability as operators may 
not be aware of available control actions or may not have control 
actions, other than firm load shedding, available to adjust the system 
after a first contingency occurs.
---------------------------------------------------------------------------

    \299\ Although the Staff Preliminary Assessment addresses 
concerns regarding the TOP-002-0, many of these same concerns apply 
to TOP-002-1 as well.
    \300\ See proposed Reliability Standard IRO-005-1.
    \301\ System operators should operate the Bulk-Power System such 
that firm load will continue to be supplied after a contingency. The 
operations planning function should provide the system operators 
with information (control actions) concerning what actions may be 
needed to avoid cascading after the worst contingency has occurred.
---------------------------------------------------------------------------

    965. The Staff Preliminary Assessment also pointed out a potential 
gap in the analysis of and planning for contingencies. This Reliability 
Standard refers to a ``single contingency'' and is defined as the loss 
of a transformer, transmission circuit, single DC pole or generator, 
but does not include the assessment of outages of multiple elements 
that would be removed from service as a result of a single component 
failure.\302\ Thus, the loss of a single relay, breaker, control system 
component or transmission tower may affect multiple system elements. 
However, these circumstances are not required to be considered in the 
analysis of, and planning for, contingencies.
---------------------------------------------------------------------------

    \302\ Failure of an electrical component includes relay and 
control system failures, which may remove more than one element.
---------------------------------------------------------------------------

    966. Finally, the Staff Preliminary Assessment stated that, 
although Requirement R14 of the Reliability Standard recognizes the 
need to communicate changes in generator ``real and reactive capability 
as well as the status of automatic voltage regulators,'' it does not 
include a similar requirement to communicate changes in the status of 
power system stabilizers.
iii. Comments
    967. NERC states that, contrary to the Staff Preliminary 
Assessment, Requirement R11 of the Reliability Standard does require 
next-day studies. NERC further states that next-day analysis should not 
have to identify control actions. Rather, it is intended to provide a 
look into the next day so that the transmission operator can then 
develop operating strategies. Appropriate real-time control actions may 
diverge from those identified by a transmission operator's previous-day 
studies, and therefore, according to NERC, the Reliability Standard 
does not identify control actions to be followed by the operators. 
Similarly, NERC states that it is impractical to identify and study all 
possibilities in next-day analysis.
    968. Regarding staff's concern regarding the lack of analysis of 
multiple system elements, NERC responds that Requirement R6 instructs 
each balancing authority and transmission operator to meet NERC, 
regional reliability organization, subregional and local reliability 
requirements. Thus, the Reliability Standard recognizes that some 
situations require operating in a manner that provides protection 
against the failure of multiple system elements. However, NERC adds 
that it will review Requirement R7 to ensure that reserves can be 
deployed to meet the requirements of the disturbance control 
Reliability Standard, BAL-002-0.
    969. MidAmerican and MRO point out that the availability for the 
sale of short-term firm transmission service is based on calculations 
taking into account single element events. Any effort to define single 
contingencies in terms of multiple elements will result in a 
significant decrease in available transmission capability; resulting in 
a negative impact on competition in the wholesale market. MRO also 
maintains that technology does not allow for comprehensive assessment 
of outages of multiple elements due to a single component failure.
    970. Regarding the Staff Preliminary Assessment's statement that 
the status of power system stabilizers should be communicated in TOP-
002-0, NERC notes that this is covered by a separate Reliability 
Standard, VAR-001-0, under Requirements R4 and R9.
    971. Requirements R3 and R4 provide that each load serving entity 
and generator operator shall coordinate its operations with its 
balancing authority and transmission service provider, ``where 
confidentiality agreements allow.'' Alcoa objects to this phrase, 
contending that a load serving entity or generator operator may evade 
these coordination requirements by simply not executing a 
confidentiality agreement.
iv. Commission Proposal
    972. The Commission proposes to approve TOP-002-1 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications

[[Page 64857]]

to the Reliability Standard, as discussed below.
    973. While Requirement R11 requires next day studies, as mentioned 
above, TOP-002-1 does not require the next-day planning analysis to 
identify control actions that are needed to bring the system back to a 
stable state within 30 minutes after a contingency occurs with the 
capacity to withstand another contingency without cascading. Operators 
should have at their disposal and be aware of control actions to adjust 
the Bulk-Power System within 30 minutes to avoid cascading after the 
worst contingency has occurred. Such control actions include 
reconfiguring the transmission system, recalling facilities from 
planned outages, and ensuring availability of generation and reactive 
power resources. These control actions should be determined as part of 
day ahead operations planning. While NERC suggests that it would be 
impractical to study every possibility to identify control actions, we 
believe that in fact only a limited number of critical facilities 
associated with IROLs would require analysis to identify control 
actions aimed at avoiding cascading outages. Accordingly, we propose 
directing that NERC modify TOP-002-1 to include identification of 
control actions that can be implemented within 30 minutes as a part of 
the next-day analysis and communication of these control actions to 
system operators.
    974. NERC's glossary 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.'' 
\303\ Requirement R7 of TOP-002-1 requires that each balancing 
authority plan to meet capacity and energy reserve requirements, 
including deliverability/capability for any single contingency.\304\ 
Although the NERC glossary defines ``contingency,'' we are concerned 
that the phrase ``single contingency'' is open to interpretation and 
that deliverability is not defined. The Commission proposes to 
interpret contingency as discussed in the transmission planning chapter 
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.
---------------------------------------------------------------------------

    \303\ NERC glossary at 3.
    \304\ See R7 of TOP-002-0.
---------------------------------------------------------------------------

    975. The Staff Preliminary Assessment suggested that TOP-002-0 
should include a requirement to communicate a change in the status of 
power system stabilizers. In response, NERC comments that this is 
addressed in VAR-001-0, which requires that each generator operator 
provide information to its transmission operator on the status of 
generation reactive power resources including the status of power 
system stabilizers. We agree with NERC and do not propose any changes 
in this regard.
    976. We share Alcoa's concern regarding the possible interference 
with the coordination demanded in Requirements R3 and R4 if that 
coordination is dependent upon the execution of a confidentiality 
agreement. Generally, the effectiveness of a Reliability Standard 
should not be predicated upon the existence of a confidentiality 
agreement or any other private agreement. If some Reliability Standards 
require a confidentiality agreement, the Commission believes that the 
matter should be addressed separately and globally so that it applies 
to all Reliability Standards rather than designating that a specific 
requirement is subject to existence of a confidentiality agreement. 
Accordingly, we propose to direct that NERC modify Requirements R3 and 
R4 by deleting references to confidentiality agreements. Rather, NERC 
should address the issue separately to ensure that necessary 
protections are in place related to confidential information.
    977. While we have identified concerns with regard to TOP-002-1, we 
believe that the proposed Reliability Standard 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. As mentioned above, TOP-002-1 does not contain Measures 
or Levels of Non-Compliance. The Commission believes that it is 
important for NERC to provide Measures and Levels of Non-Compliance. 
Nonetheless, the Requirements set forth in TOP-002-1 are sufficiently 
clear and objective to provide guidance for compliance.
    978. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard TOP-002-1 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 
proposes to direct that NERC submit a modification to TOP-002-1 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 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.
    979. Regarding outages of multiple elements caused by the failure 
of single element, NERC comments that it will review the Requirement R7 
to ensure that reserves can be deployed to meet its disturbance control 
Reliability Standard, BAL-002-0. However, MidAmerican and MRO assert 
that any effort to define single contingencies in terms of multiple 
elements will result in a significant decrease in available 
transmission capability (ATC) and will, therefore, have a negative 
impact on competition in the wholesale market. As discussed in the TPL 
Chapter, the simulations used for either planning or calculating 
available transmission capability must be consistent with the number of 
elements that will be removed from service in the physical system.
d. Planned Outage Coordination (TOP-003-0)
i. NERC Proposal
    980. TOP-003-0 requires transmission operators, generator operators 
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.
ii. Staff Preliminary Assessment
    981. TOP-003-0 requires that each transmission provider must 
provide outage information on transmission lines and transformers 
greater than 100 kV and each generator operator must provide outage 
information for generators greater than 50 MW. The Staff Preliminary 
Assessment observed that these Requirements assume that only systems 
greater than 100 kV or generators above 50 MW will affect the 
reliability of interconnected operations. Staff stated that, although 
this assumption may be true in most instances, a justification should 
be provided for the threshold of 100 kV for transmission and 50 MW for 
generation outages. Staff further stated that the loss of transmission 
lines or transformers less than 100 kV and generators less than 50 MW 
may affect system stability in load pockets or remote sections of the 
grid depending upon system conditions.

[[Page 64858]]

    982. The Staff Preliminary Assessment noted that, while a related 
Reliability Standard, TOP-002-0, requires the coordination of planned 
outages on a current-day, next-day and seasonal basis for normal 
operations planning, TOP-003-0 only requires next-day reporting for 
planned outages and does not include longer range planning. The Staff 
Preliminary Assessment expressed the concern that this gap may affect 
reliability because proper assessment of the system and coordination 
between generation and transmission outages may not occur. Moreover, 
the lack of information may also have an impact on TTC/ATC 
calculations. Staff also noted that the Levels of Non-Compliance are 
based on designating a process for providing information, but they do 
not contain requirements for the actual provision of that information
iii. Comments
    983. NERC comments that the 100 kV and 50 MW thresholds may need to 
be reviewed over time. However, NERC believes that the Commission 
should approve TOP-003-0 as proposed because transmission operators, 
balancing authorities and reliability coordinators should decide which 
facilities to include in their operations planning assessments.
    984. Allegheny agrees that the 100 kV and 50 MW thresholds may not 
be appropriate in all situations. However, Allegheny points out that 
transmission operators and reliability coordinators typically 
coordinate all planned outages that may have a significant impact on 
interconnected operations. Rather than lowering the thresholds to 
include all facilities, Allegheny suggests that transmission operators 
and reliability coordinators identify significant facilities through 
system studies. MidAmerican and MRO recommend that the thresholds 
should not be lowered because this will slow down the coordination of 
outages for higher voltage facilities and larger generators.
    985. ISO/RTO Council believes that any size or voltage threshold 
must be justified based on its potential impact to reliability. In 
addressing lower voltage levels, ReliabilityFirst comments that system 
operators typically evaluate and monitor lower voltages levels to 
ensure they do not impact the reliability of the Bulk Electric System. 
However, ReliabilityFirst believes that the assessment and monitoring 
of these lower voltage levels should be included in the Reliability 
Standard for uniformity and consistency.
iv. Commission Proposal
    986. The Commission notes that outage information is important to 
both reliable operation and to the calculation of available transfer 
capability. 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 impacted 
transmission operators and reliability coordinators with sufficient 
lead time to coordinate outages. The Commission requests industry input 
on what constitutes sufficient lead time for planned outages.
    987. NERC, Allegheny, ISO/RTO Council, and ReliabilityFirst agree 
with the Staff Preliminary Assessment that the thresholds for providing 
outage information should be reviewed. While we agree with commenters 
that lowering the threshold might slow down the coordination process, 
we are also concerned that the thresholds of 100 kV and 50 MW may not 
include all facilities that have a significant impact on the operation 
of Bulk-Power System. For example, emergency operations would require, 
at a minimum, that there are adequate blackstart resources available if 
needed. Thus, while in the longer-term a review of the existing 
thresholds is appropriate, at this time, we propose directing NERC to 
modify TOP-003-0, Requirement R1 to provide that a generator operator 
or transmission operator must provide planned outage information for 
any facility above 100 kV and 50 MW and any other facility below these 
thresholds that, in the opinion of the transmission operator, balancing 
authority, or reliability coordinator, would have a direct impact on 
the operation of Bulk-Power System.
    988. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard TOP-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, the Commission 
proposes to direct that NERC 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 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.
e. Transmission Operations (TOP-004-0)
i. NERC Proposal
    989. TOP-004-0 requires transmission operators to operate the 
transmission system within SOL and IROL. 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 reliability goal of TOP-004-0 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. Further, NERC indicates 
that it plans to modify TOP-004-0 to address the lack of Measures and 
Levels of Non-Compliance.
ii. Staff Preliminary Assessment
    990. The Staff Preliminary Assessment noted that a regional review 
of the potential impact of multiple outages in day-ahead operations 
planning is included in Requirement R3 for TOP-004-0. However, staff 
observed that the conditions under which multiple outages can occur 
remain undefined.
    991. The proposed Reliability Standard requires the operation of 
the system within IROL and SOL. When the system enters an unknown state 
(i.e., any state for which operating limits have not been determined), 
Requirement R4 instructs the operator to ``restore operations to 
respect proven reliable power system limits within 30 minutes.'' Staff 
cautioned that the phrase ``within 30 minutes'' could be interpreted as 
a grace period. However, such an interpretation may not be consistent 
with the intent that, while 30 minutes has been adopted by the industry 
as a reasonable time period, it is expected that corrective actions 
will be taken as soon as possible and without delay.
iii. Comments
    992. NERC responds to the Staff Preliminary Assessment, stating 
that the specification of 30 minutes is not meant to suggest that 
system operators should take as long as 30 minutes. Rather, it is meant 
to provide system operators with the flexibility to respond to 
emergencies in the manner they determine is best, even if it is not the 
fastest alternative. In addition, NERC asserts that: (1) 30 minutes is 
based on decades of system

[[Page 64859]]

operations experience; (2) system operators do not treat ``within 30 
minutes'' as a grace period and it has not come across situations when 
system operators waited for 29 minutes before taking an appropriate 
action; and (3) although a system is not allowed to drift in and out of 
a secure state, sometimes it enters an unknown state that was not 
studied and it is appropriate to allow the system operators a 
reasonable amount of time to bring the system back to the normal state.
    993. MidAmerican comments that, if IROL cannot be exceeded even for 
one minute, operators will need to maintain a margin at significant 
cost and there will be a resulting negative impact on competition.
iv. Commission Proposal
    994. The Commission proposes to approve TOP-004-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard as discussed below.
    995. Requirement R4 of TOP-004-0 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. We agree with NERC that 30 minutes is a reasonable period 
within which operators should return the system to a reliable operating 
state. However, as stated in the Staff Preliminary Assessment it may be 
interpreted as a grace period to the detriment of reliability and 
therefore the Commission proposes that Requirement R4 be modified to 
state that the system should be restored to respect proven reliable 
power system limits as soon as possible and no longer than 30 minutes.
    996. With respect to NERC's comment that the system is not allowed 
to drift in and out of a reliable state, the Commission is concerned 
that neither TOP-004-0 nor the IRO Reliability Standards address this 
issue and that some entities may be engaging in this practice to the 
detriment of reliability. The Commission proposes to require that NERC 
survey and report the operating practices and actual experiences 
surrounding drifting into and out of IROL limits.\305\
---------------------------------------------------------------------------

    \305\ The issue of drifting in and out of IROL limits is 
discussed in the IRO chapter and provides specifics of proposed 
survey in greater detail. See discussion for IRO-005-1.
---------------------------------------------------------------------------

    997. The Staff Preliminary Assessment noted that while Requirement 
R3 states that, when practical, the system must be operated to respect 
multiple outages as specified by the regional reliability organization 
policy it does not define conditions under which such multiple outages 
must be considered. We 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 a multiple outage 
approaches that of single element outage. The Commission proposes that 
Requirement R3 be modified to define conditions under which the system 
must be operated to respect multiple outages.
    998. The Commission notes that TOP-004-0 does not contain Measures 
or Levels of Non-Compliance. TOP-004-0 serves an important reliability 
goal of ensuring that the Bulk-Power System facilities are operated 
within safe limits, thereby protecting transmission, generation, 
distribution and customer equipment and preventing cascading failures. 
The Commission believes that it is important for NERC to provide 
Measures and Levels of Non-Compliance elements for this proposed 
Reliability Standard. Nonetheless, the proposed Requirements set forth 
in TOP-004-0 are sufficiently clear and objective to provide guidance 
for compliance.
    999. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard TOP-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 
proposes to direct that NERC submit a modification to TOP-004-0 that 
(1) includes Measures and Levels of Non-Compliance; (2) clarifies that 
the 30 minute response time is not a grace period; and (3) defines in 
Requirement R3, high risk conditions under which the system must be 
operated to respect multiple outages. In addition, we propose to direct 
that the ERO perform a survey of the prevailing operating practices and 
actual operating experiences surrounding drifting in and out of IROL 
limits. As part of the survey, we would require all reliability 
coordinators to report any violations of IROLs, their causes, the date 
and time of the violation, 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.
f. Operational Reliability Information (TOP-005-1)
i. NERC Proposal
    1000. TOP-005-1 ensures that reliability information is shared 
among reliability coordinators, transmission operators and balancing 
authorities.\306\ It requires the transmission operator and the 
balancing authority to provide operating data to each other and to the 
reliability coordinator and provides a list of typical operating data 
that must be provided. TOP-005-1 also provides that, as a condition of 
receiving data from the NERC's Interregional Security Network,\307\ 
each data recipient must execute a confidentiality agreement.
---------------------------------------------------------------------------

    \306\ NERC states that, effective November 1, 2006, proposed 
Reliability Standard TOP-005-1 will replace existing Reliability 
Standard, TOP-005-0.
    \307\ 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.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    1001. Staff noted that Attachment 1 of TOP-005-1 entitled, 
``Electric System Reliability Data,'' which specifies the types of 
operating data that reliability coordinators, balancing authorities and 
transmission operators are expected to share, does not include the 
operational status of special protection systems and power system 
stabilizers. The Staff Preliminary Assessment raised the concern that 
the absence of this information could lead to an erroneous assessment 
of system capability.
iii. Comments
    1002. NERC agrees with Commission Staff that Attachment 1 of TOP-
005-1 should be modified to include special protection systems and 
power system stabilizers.
    1003. ReliabilityFirst states that information pertaining to the 
special protection systems is included in Attachment 1, section 2.6, 
which refers to ``new or degraded special protection systems.''
    1004. ISO/RTO Council argues that the Commission should direct NERC 
to eliminate the requirement that each data recipient sign a 
confidentiality agreement. It claims that the requirement to sign a 
confidentiality agreement is an administrative matter, not a 
reliability issue.
iv. Commission Proposal
    1005. ReliabilityFirst points out that the operational information 
pertaining to the ``new or degraded special protection systems'' is 
included in Attachment 1. However, a special

[[Page 64860]]

protection system may be turned on or off and not be degraded. 
Awareness of the operational state is different from knowing that 
degradation has occurred. In addition, Attachment 1 does not contain 
information about power system stabilizers. While Attachment 1 contains 
a large amount of data pertaining to Bulk-Power System reliability, 
inclusion of information about the operation status of special 
protection systems will provide a more comprehensive list. We agree 
with NERC and propose that Attachment 1 be modified to include the 
status of special protection systems and power system stabilizers.
    1006. We agree with ISO/RTO Council that the reference to execution 
of confidentiality agreement should be deleted from the Reliability 
Standard and NERC should address the issue separately and globally as 
we indicate above in our discussion of TOP-002-1.
    1007. TOP-005-1 furthers an important reliability goal of ensuring 
that reliability entities have the operating data needed to monitor 
system conditions within their area. Further, the Requirements set 
forth in TOP-005-1 are sufficiently clear and objective to provide 
guidance for compliance. Accordingly, giving due weight to the 
technical expertise of the ERO and with the expectation that the 
Reliability Standard will accomplish the purpose represented to the 
Commission by the ERO and that it will improve the reliability of the 
nation's Bulk-Power System, the Commission proposes to approve 
Reliability Standard TOP-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 proposes to direct that NERC 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.
g. Monitoring System Conditions (TOP-006-0)
i. NERC Proposal
    1008. TOP-006-0 requires that operating personnel 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. NERC indicates that it plans to modify TOP-006-0 to 
address the lack of Measures and Levels of Non-Compliance.
ii. Staff Preliminary Assessment
    1009. The Staff Preliminary Assessment noted that, while TOP-006-0 
identifies data requirements it does not identify any minimum 
acceptable tools and capabilities to turn the data into information to 
aid in situational awareness. Staff explained that reliability 
coordinators, transmission operators and balancing authorities must be 
aware of the status of their respective systems, and such situational 
awareness cannot be obtained by viewing massive amounts of raw data.
iii. Comments
    1010. NERC agrees with the Staff Preliminary Assessment that 
situational awareness is ``key'' to operating an interconnected 
electric system reliably and that data collection is only one component 
of a successful situational awareness strategy. NERC, however, states 
that whether a Reliability Standard should specify how data should be 
analyzed and presented to the system operator or reliability 
coordinator requires further discussion, including discussions with 
vendors who supply situational awareness and visualization tools.
    1011. ReliabilityFirst comments that due to the variety of 
equipment used to manage the Bulk-Electric System, it is impractical to 
specify the type of software and processes acceptable for monitoring.
    1012. MRO states that Requirement R3, which requires an applicable 
entity to provide ``appropriate technical information'' concerning 
protective relays, should be revised to clarify the phrase, 
``appropriate technical information.''
iv. Commission Proposal
    1013. The Commission proposes to approve TOP-006-0 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    1014. The Blackout Report states that ``a principal cause of the 
blackout was a lack of situational awareness, which was in turn a 
result of inadequate tools and back-up capabilities.'' \308\ In 
addition, in reviewing common factors between the August 2003 blackout 
and other major outages the Blackout Report states ``power system data 
may be available but not be presented to operators or coordinators as 
information they can use in making appropriate decisions.'' \309\ While 
TOP-006-0 requires that a significant amount of data be provided to 
operating personnel, we agree with NERC that this is only one component 
of a successful situational awareness strategy. The data must be 
converted into information that operators can use to assess the state 
of the system and its vulnerability, should a contingency occur, and 
take appropriate actions to maintain a reliable system. We note that 
the Requirement R7 of Reliability Standard IRO-002-0 requires that 
reliability coordinators have adequate tools such as state estimation, 
pre and post contingency analysis capabilities and wide area overview 
displays. We believe that similar tools should be made available to 
transmission providers and balancing authorities and propose that the 
ERO add a new Requirement in this Reliability Standard to provide 
adequate tools to transmission operators and balancing authorities, 
which will provide them situational awareness.
---------------------------------------------------------------------------

    \308\ See Blackout Report at 159.
    \309\ Id. at 108.
---------------------------------------------------------------------------

    1015. Although we agree with NERC that further discussions may be 
needed with vendors who supply situational awareness and visualization 
tools, modification of TOP-006-0 should not have to wait for those 
discussions to occur. A variety of off-the-shelf tools are currently 
available from vendors and in use across the industry. At a Commission 
sponsored technical conference on July 14, 2004, staff presented its 
views on minimum requirements and best practices for reliability tools 
for the purpose of initiating discussions on what these minimum 
reliability capabilities ought to be. We believe that identification of 
the types of tools and what they should minimally accomplish would 
improve the proposed Reliability Standard. Entities that must comply 
with TOP-006-0 could choose among the available software tools that 
accomplish the desired goal or meet the Requirement set forth in the 
Reliability Standard. Accordingly, we propose to direct NERC to modify 
TOP-006-0 to include a requirement for a minimum set of tools for 
transmission operators and balancing authorities that will aid in 
situational awareness.
    1016. We agree with MRO that the phrase ``appropriate technical 
information'' is open to interpretation and propose to direct that NERC 
modify TOP-006-0, Requirement R3, to identify the specific type of 
technical information concerning protective relays that should be 
provided.
    1017. TOP-006-0 serves an important reliability goal of requiring 
monitoring

[[Page 64861]]

of essential Bulk-Power System parameters such as the status of power 
system elements, real and reactive power flows, voltages and frequency 
to ensure that the system and its equipment are operated in a reliable 
and safe manner. The Commission believes that it is important for NERC 
to provide Measures and Levels of Non-compliance for this proposed 
Reliability Standard. Nonetheless, the proposed Requirements set forth 
in TOP-006-0 are sufficiently clear and objective to provide guidance 
for compliance.
    1018. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO, and 
that it will improve the reliability of the nation's Bulk-Power System 
the Commission proposes to approve Reliability Standard TOP-006-0 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 
proposes to direct that NERC submit a modification to TOP-006-0 that: 
(1) Includes Measures and Levels of Non-compliance elements; (2) 
includes a new requirement related to the provision of a minimum set of 
analysis tools that will aid in situational awareness; and (3) 
clarifies the meaning of ``appropriate technical information'' 
concerning protective relays.
h. Reporting SOL and IROL Violations (TOP-007-0)
i. NERC Proposal
    1019. TOP-007-0 requires that violations of SOL and IROL are 
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 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, it requires that the 
reliability coordinator take action to mitigate an SOL or IROL 
violation if the transmission operator's actions are not effective.
ii. Staff Preliminary Assessment
    1020. As indicated above, TOP-007-0 requires that, ``[f]ollowing a 
[c]ontingency or other event that results in an IROL violation, the 
transmission operator shall return its transmission system to within 
IROL as soon as possible, but not longer than 30 minutes.''\310\ The 
Staff Preliminary Assessment explained that the phrase ``or other 
event'' in this Requirement is open to interpretation. One 
interpretation is that it allows IROLs to be exceeded under normal pre-
contingency conditions, provided the system can be returned to a secure 
state within 30 minutes. Another, more conservative, interpretation is 
that the Requirement does not allow IROLs to be exceeded under normal 
pre-contingency conditions, and that after a contingency occurs the 
system must be returned to a secure condition as soon as possible and 
no later than 30 minutes. The Staff Preliminary Assessment cautioned 
that, if the system is operated in a less conservative manner during 
the period where IROL is exceeded, even a single system contingency 
could cause instability, uncontrolled separation, and even a cascading 
blackout.
---------------------------------------------------------------------------

    \310\ Reliability Standard TOP-007-0, Requirement R2.
---------------------------------------------------------------------------

iii. Comments
    1021. NERC states that SOL and IROL need better definition, also 
noting that SOL and IROL are operating states that system operators 
must move away from as quickly as possible. It will consider revising 
the standard to clarify that a contingency is not required to violate 
the SOL and IROL limits. NERC notes that it has commissioned an 
Operating Limit Definition Task Force to work on this matter and the 
Task Force is expected to submit its recommendation by the end of 2006.
    1022. Also seeking more definition and detail on SOL and IROL, 
ReliabilityFirst urges the acceleration of standards now being 
developed to clarify SOL and IROL. However, it adds that it would be 
impractical to identify and study all possibilities for alleviating SOL 
and IROL.
    1023. ISO/RTO Council agrees with the Staff Preliminary Assessment 
that this Reliability Standard is open to interpretation. However, ISO/
RTO Council states that it is appropriate to give system operators 
discretion in making real-time system operating decisions. It comments 
that a more prescriptive standard would unduly restrict system 
operators and the nature of real-time operations requires giving these 
entities some leeway. Thus, the ISO/RTO Council recommends that the 
Commission approve TOP-007-0 in its present form.
    1024. MRO recommends that an IROL violation exceeding 30 minutes be 
reported to NERC within 48 hours rather than the 72 hours allowed under 
the compliance section of this Reliability Standard.
iv. Commission Proposal
    1025. As noted in our discussion in IRO-005 and TOP-004, the 
Commission is concerned about systems drifting in and out of SOL and 
IROL violations. One source of justification for that practice is the 
term ``other event.'' We agree with NERC that SOL and IROL need better 
definitions and TOP-007-0 could be improved by making the requirements 
clearer. Our proposal for a survey in IRO-005 and TOP-004 to collect 
data will give us more information about the extent of the problem with 
regard to drifting in and out of SOL and IROL violations.
    1026. Regarding MRO's recommendation that IROL violations exceeding 
30 minutes be reported to NERC within 48 hours, we will leave this 
determination to NERC because we consider this to be a matter of 
administrative convenience.
    1027. TOP-007-0 serves an important reliability goal of ensuring 
that when critical limits are violated, the violations are reported and 
appropriate actions taken to avoid any cascading outages. The 
Commission believes that it is important that NERC address the 
ambiguity regarding IROL violations, discussed above. Nonetheless, the 
proposed Requirements set forth in TOP-007-0 are sufficiently clear and 
objective to provide guidance for compliance.
    1028. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission believes that Reliability Standard TOP-007-0 is just, 
reasonable, not unduly discriminatory or preferential, and in the 
public interest; and proposes to approve it as mandatory and 
enforceable.
    1029. The Commission solicits comment on potentially overlapping 
matters addressed in Reliability Standards TOP-007-0 and TOP-008-0. The 
title and the purpose of TOP-007-0 state that it ensures that SOL and 
IROL violations are being reported, but we believe that only 
Requirement R1 relates to reporting. The remaining requirements in TOP-
007-0, R2, R3 and R4, go beyond reporting of violations and provide 
that the transmission operator will take actions on its own or as 
directed by the reliability coordinator. We observe that proposed 
Reliability Standard TOP-008-0 addresses the same subject. In fact,

[[Page 64862]]

Requirement R1 of TOP-008-0 is similar to Requirement R3 of TOP-007-0. 
It appears that both Reliability Standards deal with the same subject, 
but more emphasis is placed on reporting in TOP-007-0. If two separate 
Reliability Standards address similar topics, the purpose statement 
should succinctly capture the intent of each Reliability Standard.
i. Response to Transmission Limit Violations (TOP-008-0)
i. NERC Proposal
    1030. TOP-008-0 requires a transmission owner to take immediate 
steps to mitigate SOL and IROL violations. NERC indicates that it plans 
to modify TOP-008-0 to address the lack of Measures and Levels of Non-
Compliance.
ii. Staff Preliminary Assessment
    1031. The Staff Preliminary Assessment did not identify any 
substantive issues in TOP-008-0, other than noting that it does not 
contain Measures or Levels of Non-Compliance.
iii. Comments
    1032. No comments were submitted regarding TOP-008-0.
iv. Commission Proposal
    1033. We observe that proposed Reliability Standard TOP-007-0 
addresses the same subject.
    1034. Requirements R1 through R4 provide that the transmission 
operator shall take certain actions to mitigate the effects of SOL and 
IROL violations. No role is specified for the reliability coordinator. 
A reliability coordinator plays a key role in the reliability of the 
Bulk-Power Systems and should be involved in the decision-making 
process of bringing the system back within operating limits as soon as 
possible. A parallel Reliability Standard covering this subject, TOP-
007-0, identifies a role for the reliability coordinator. The 
Commission proposes to require NERC to modify TOP-008-0 to apply to 
reliability coordinators.
    1035. TOP-008-0 serves an important reliability goal of ensuring 
that when critical limits are violated, appropriate actions are taken 
to avoid any cascading outages. The Commission believes that it is 
important for NERC to provide Measures and Levels of non-compliance 
elements for this proposed Reliability Standard. Nonetheless, the 
proposed Requirements set forth in TOP-008-0 are sufficiently clear and 
objective to provide guidance for compliance.
    1036. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve Reliability Standard TOP-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 
proposes to direct that NERC submit a modification to TOP-008-0 that: 
(1) includes Measures and Levels of Non-compliance elements; and (2) 
includes reliability coordinators in the Applicability section.
12. TPL: Transmission Planning
a. Overview
    1037. 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 and the need for 
transmission upgrades, developing and evaluating a range of 
transmission reinforcement and upgrade options and selecting the 
preferred option, taking into account the time needed to place the 
facilities 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 \311\ and (2) the information required to assess regional 
compliance with planning criteria and for self-assessment of regional 
reliability.\312\ The differing definitions of the Bulk-Power System 
and bulk electric system discussed above is central to the concerns 
raised by this group of Reliability Standards.\313\ That issue has 
important implications for the range of contingencies that must be 
evaluated and facilities to be simulated in the transmission planning 
process.
---------------------------------------------------------------------------

    \311\ See TPL-001-0, TPL-002-0, TPL-003-0, and TPL-004-0.
    \312\ See TPL-005-0 and TPL-006-0.
    \313\ See discussion of Bulk Power System v. bulk electric 
system in section III.D.5 above.
---------------------------------------------------------------------------

    1038. 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 demand.
b. General Issues
    1039. Both the Staff Preliminary Assessment and commenters raise a 
number of issues that apply generally to Reliability Standards TPL-001-
0 through TPL-004-0. We address these issues here and, in addition, 
apply our general discussion when addressing each individual 
Reliability Standard.
i. Staff Preliminary Assessment
    1040. Staff stated that, in general, the TPL Reliability Standards 
raise issues regarding requirements that are ambiguous, and ``limited 
sets of contingencies,'' i.e, they do not address outages of multiple-
elements resulting from some probable single events and critical system 
conditions.\314\
---------------------------------------------------------------------------

    \314\ Staff Preliminary Assessment at 108.
---------------------------------------------------------------------------

    1041. NERC responds that, while the proposed Reliability Standards 
need review and incremental improvement, staff's criticisms of the TPL 
group of Reliability Standards are overstated. Likewise, EEI believes 
that the TPL group of proposed Reliability Standards is technically 
sound and sufficiently detailed. NERC contends that the purpose of 
Reliability Standards is not to make the Bulk-Power System failure-
proof, but to ensure it is able to meet specific performance 
requirements under normal conditions and following

[[Page 64863]]

single contingencies and certain credible multiple-contingencies. The 
TPL standards require assessment of multiple-contingency and extreme 
contingency events but do not require that the system be able to 
withstand such events without loss of firm load and, according to NERC, 
requiring this would be impractical and extremely costly.
    1042. The Commission agrees with NERC that the Reliability 
Standards are not intended to make the Bulk-Power System failure-proof. 
Nor do we 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 
believe that the planning-related Reliability Standards could be 
improved to better take into account probable contingencies when 
planning studies are conducted. Much of our proposal is consistent with 
the possible means of improvement recognized by NERC in its comments 
responding to the Staff Preliminary Assessment. Further, we note 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.\315\ Accordingly, we propose 
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.
    ii. Stressing the System During Simulations
---------------------------------------------------------------------------

    \315\ Examples include practices cited in NERC's ``Examples of 
Excellence'' found in its Readiness Audits, 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.
---------------------------------------------------------------------------

    1043. Staff stated that, when carrying out power systems 
simulations it is important to ensure that the system under study is 
sufficiently stressed so that any underlying weaknesses or deficiencies 
can be identified and to test the performance of the system under study 
for a wide variety of probable scenarios. It suggested that such 
simulations ``would determine the most onerous sets of system 
conditions * * *'' \316\ Staff stated that system conditions are as 
important as contingencies in evaluating the performance of present and 
future systems, but that the Reliability Standards do not require that 
sensitivity studies be carried out or specify the rationale for 
determining critical system conditions and study years.
---------------------------------------------------------------------------

    \316\ Staff Preliminary Assessment at 109.
---------------------------------------------------------------------------

    1044. A number of commenters reacted strongly to staff's suggestion 
regarding the use of simulations to determine ``the most onerous sets 
of system conditions.'' CenterPoint states that planning for the most 
onerous set of conditions would have an unreasonable impact on 
transmission rates and the need for new transmission lines.
    1045. MRO and MidAmerican support clarifying ambiguities but prefer 
that Reliability Standards not become overly prescriptive in a way that 
would restrict engineering judgment. For example, MRO comments that 
sensitivity studies should be performed as part of the planning 
process, but it recommends that the planning entity develop the system 
conditions, planning years, and other aspects of the sensitivity 
scenarios. ReliabilityFirst adds that defining a checklist for planning 
would encourage planners to rely on the checklist to the exclusion of 
good engineering judgment.
    1046. The TPL Reliability Standards require Transmission Planners 
and Planning Authorities to conduct system performance assessments. 
Such assessments must address specific topics, including ``critical 
system conditions and study years as deemed appropriate by the entity 
performing the study.'' \317\ As noted by staff and commenters,\318\ 
system conditions are as important as contingencies in evaluating the 
performance of present and future systems. The Commission is concerned 
that this Requirement allows complete discretion to the entity 
performing the study and does not provide any parameters or criteria 
for such an entity to determine critical system conditions and study 
years in a rational and consistent manner.
---------------------------------------------------------------------------

    \317\ E.g., Reliability Standard TPL-001-0, Requirement R1.3.
    \318\ See Staff Preliminary Assessment at 109. See also 
CenterPoint, MidAmerican and MRO comments.
---------------------------------------------------------------------------

    1047. With regard to CenterPoint's comment, we agree that it is not 
realistic to expect the ERO to develop a Reliability Standard that 
anticipates every conceivable critical operating condition applicable 
to unknown future configurations for regions with various 
configurations and operating characteristics. The practical solution 
that has been implemented by many in the industry is to perform 
sensitivity studies that define and provide documentation of the impact 
on the system. For that reason, we believe 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. While Requirement R1.3 identifies firm transfers, selected 
demand levels, existing and planned facilities, reactive power 
resources, and control devices, a sensitivity study to determine 
critical system conditions should consider such additional matters as 
the range of load power factors, generation retirements, generation 
dispatch and transaction patterns, controllable loads and DSM at 
specific locations, and transmission outages, including outages of 
reactive power devices. The Commission is not precluding other 
approaches to define and document critical system conditions that have 
been proven to be effective.\319\ We propose that the ERO modify the 
relevant TPL Reliability Standards accordingly. Further we propose that 
the results of these studies be documented to support the selection of 
critical system conditions used in assessing system performance.
---------------------------------------------------------------------------

    \319\ While contingencies have been defined in Table I, the 
Commission does not believe systems conditions lend themselves to a 
table or a simple list.
---------------------------------------------------------------------------

iii. Element-Based vs. Event-Based Contingencies
    1048. As explained in the TPL overview above, Table 1 of the TPL 
Standards 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. The Staff Preliminary 
Assessment explained that the single unanticipated failure of some 
elements in the Bulk-Power System can result in the loss of multiple 
elements. Because of the resulting impact on reliability, some regions 
base their groupings according to the event irrespective of the number 
of elements forced out of service (as opposed to categorizing 
contingencies according to elements forced out of service). For such a 
region, a single event that results in the loss of multiple elements, 
e.g., a lightning strike, that simultaneously forces out of service 
both circuits of a double circuit tower line, is considered a single 
contingency similar to the loss of a single element such as a 
generator. What is acceptable in one region may not be acceptable in 
another region because of historical adoption of reliability criteria 
rather than physical differences in systems.

[[Page 64864]]

    1049. Most commenters that address this topic oppose an event-based 
contingency planning approach on the grounds that it is difficult to 
perform, too conservative, too costly to the public, too rigid, or not 
based on the probabilities of outages occurring in the real 
system.\320\ National Grid, on the other hand, supports event-based 
contingency planning on the contention that it provides a more robust 
analysis. The Commission believes that planning standards must 
influence system design and not the other way around. To achieve this 
objective, planning standards should promote system designs that result 
in the minimum set of elements being removed from service for 
``unanticipated failures of system elements.'' \321\ The Commission 
notes that entities with planning responsibility for approximately half 
of the load in the nation 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 outages identified in Table 1. Simply put, the 
Commission believes that the simulations should faithfully duplicate 
what will happen in the actual power system and not a generic listing 
of outages.
---------------------------------------------------------------------------

    \320\ See, e.g., CenterPoint, EEIm Mid American, New York 
Commission and ReliabilityFirst.
    \321\ Section 215(a) of the FPA defines ``Reliable Operation'' 
as ``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 sudden disturbance, 
including a Cybersecurity Incident, or unanticipated fialure of 
system elements'' (emphasis added).
---------------------------------------------------------------------------

    1050. In addition, the Bulk-Power System 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 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, then the Commission proposes that 
this is what should be simulated.
    1051. Planning for Cybersecurity incidents have not been part of 
the traditional planning study process. One approach is to identify 
specific vulnerabilities based on the designs at specific locations and 
then study the impact of those vulnerabilities. The Commission is 
interested in comments from industry on this subject such as whether 
planning for cybersecurity events should be addressed in the planning 
standards or in the CIP standards.
c. System Performance Under Normal (No Contingency) Conditions (TPL-
001-0)
i. NERC Proposal
    1052. Proposed Reliability Standard TPL-001-0 deals with planning 
relevant 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.\322\ NERC states in its 
application that the proposed Reliability Standard ensures 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.\323\ 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.
---------------------------------------------------------------------------

    \322\ The NERC glossay 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.
    \323\ The performance requirements are set forth in Category A 
of Table I of the standard.
---------------------------------------------------------------------------

    1053. The Requirements of TPL-001-0 specify 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 normal 
conditions. 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.
ii. Staff Preliminary Assessment
    1054. The Staff Preliminary Assessment explained that TPL-001-0 
does not require the consideration of planned outages, which are a 
common occurrence, in assessing system performance. Staff also stated 
that the Reliability Standard does not require sensitivity studies to 
define critical conditions and that footnote (a) to Table 1--which 
states in part that ``Applicable Ratings may include Emergency Ratings 
applicable for short durations as required to permit operating steps 
necessary to maintain system control'' and therefore only pertains to 
contingency conditions--should be clarified that it is only applicable 
to Categories B, C, and D, i.e., situations involving system 
contingencies or failures of system components.
    1055. Staff noted that the purpose statement for this Reliability 
Standard is identical to those for TPL-002, TPL-003 and TPL-004 
although the goal and requirements are different. The transmission 
planning Reliability Standards TPL-001-0 through TPL-004-0 define 
various categories of conditions to be simulated. Staff noted that 
Requirement R1.3 in each of these Reliability Standards allows fewer 
than the specific study elements identified in Table 1 to be selected 
from each of the categories for assessments with the approval by the 
associated regional reliability organization, even though selection of 
fewer elements may impact neighboring systems.
iii. Comments
    1056. MRO comments that the Requirements of TPL-001-0 need 
clarification because it is not clear as to what is required. In 
addition, it asserts that staff appears to indicate that Order No. 2003 
and TPL-001-0 have separate requirements which must be followed. To 
avoid the creation of dual Reliability Standards, MRO maintains that 
the Commission should explain how the Requirements of this Reliability 
Standard relate to the requirements of Order No. 2003 and clarify that 
entities will only be required to comply with a single set of 
reliability requirements.
    1057. ReliabilityFirst disagrees that footnote (a) to Table 1 is 
ambiguous. It states that emergency ratings are not applicable when all 
facilities are in service.
    1058. ISO/RTO Council comments that Requirement 1 of TPL-001-0 
should define more clearly which entity

[[Page 64865]]

is classified as a ``planning authority.'' It also recommends that 
because the planning authority only has authority to plan for system 
expansion, the word ``consider'' used in Requirement R2 in connection 
with lead times necessary for implementation should be changed to 
``estimate.''
iv. Commission Proposal
    1059. The Commission proposes to approve TPL-001-0 as a mandatory 
and enforceable Reliability Standard. In addition, we propose to direct 
that NERC develop modifications to the Reliability Standard, as 
discussed below.
    1060. Transmission Planning requires information on forecasted 
loads and probable generation plans to supply those loads. While 
information on forecasted loads, energy, interruptible loads and direct 
control load management over the next ten years are required to be made 
available by the MOD Reliability Standards, there is no requirement to 
inform transmission planners and planning authorities of new or 
retiring generation resources. We seek 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. If transmission 
planners and planning authorities currently experience difficulty 
obtaining this information, how should this potential information gap 
be addressed?
    1061. In assessing system performance, TPL-001-0 requires entities 
to cover ``critical system conditions and study years,'' as deemed 
appropriate by the entity performing the study. As discussed above 
regarding Stressing the System During Simulations, the Reliability 
Standard does not specify the rationale for determining critical system 
conditions and study years. Consistent with our discussion of this 
issue above, the Commission proposes that the ERO modify TPL-001-0 to 
require that critical system conditions be determined by conducting 
sensitivity studies covering such factors as load power factors, 
different likely generation expansion scenarios including generation 
retirements, alternative generation dispatch and transaction patterns, 
controllable loads and DSM at specific locations, and transmission 
outages, including outages of reactive power devices. The Commission 
would expect that the results of these studies would be used to 
document the selection of critical system conditions and study years 
used in assessing system performance.\324\
---------------------------------------------------------------------------

    \324\ The Commission expects that the results of the sensitivity 
studies taken together would form the basis for evaluating adherence 
to criteria, i.e., adhering to system performance expectations 
following contingencies specified in Table 1. Failure of one 
sensitivity study of a very low probability simulation would not, by 
itself, warrant the need for mitigation plans. However, if the 
simulations, taken as a whole, show miltiple areas of weaknesses or 
criteria violations, then mitigation plans would be required.
---------------------------------------------------------------------------

    1062. The Commission notes that load models used in system studies 
have a significant impact on system performance, particularly as they 
relate to the dynamic performance of the system. The Commission 
proposes that the Reliability Standard be modified to require 
documentation of load models used in system studies and supporting 
rationale for their use.
    1063. Requirement R1.3 of TPL-001-0 provides that the Planning 
Authority and Transmission Planner must provide studies and system 
simulations to support its planning assessment, and that the ``specific 
elements selected [for the study] shall be acceptable to the associated 
Regional Reliability Organization(s).'' As we have discussed elsewhere, 
the Commission believes that the regional reliability organization 
should not have such a role in the context of mandatory Reliability 
Standards. Rather, the ERO or the appropriate Regional Entity(s) should 
provide this oversight. Also, given that neighboring systems may be 
adversely impacted, the Commission proposes that the neighboring 
systems be involved in the determination and review of system 
conditions and contingencies to be assessed.
    1064. As mentioned above, staff noted that TPL-001-0 does not 
require the consideration of planned outages. While Reliability First 
agrees with staff, CenterPoint disagrees because operators schedule 
planned outages at times when the reliability risk is minimized. 
Planned outages are an every day occurrence that, if excluded, would 
not provide an accurate assessment of system conditions. Accordingly, 
the Commission proposes to direct that NERC modify TPL-001-0 to require 
consideration of planned outages of critical equipment. We note that 
TPL-002-0 through TPL-004-0 require consideration of planned outages.
    1065. NERC and other commenters agree with staff that footnote (a) 
to Table 1 requires clarification. The NERC Transmission Issues 
Subcommittee (TIS) \325\ recommended that footnote (a) be modified to 
state explicitly that emergency ratings apply to Category B and C 
(contingency conditions) and not to Category A (system intact). The 
Commission proposes that footnote (a) be modified in the revised 
Reliability Standard as recommended by TIS and that the normal facility 
rating be in accordance with Reliability Standard FAC-008-1 and normal 
voltages be in accordance with Reliability Standard VAR-001-1.
---------------------------------------------------------------------------

    \325\ NERC Transmission Issues Subcommittee, Evaluation of 
Criteria, Methods, and Practices Used for System Design, Planning 
and Analysis in Response to NERC Blackout Recommendation 13c (Nov. 
28, 2005) (NERC TIS Report) at 15.
---------------------------------------------------------------------------

    1066. While the Commission has identified a number of concerns with 
regard to TPL-001-0, this proposed Reliability Standard serves an 
important purpose by ensuring the Bulk-Power System is planned to meet 
the system performance requirements under normal conditions. Further, 
the Requirements set forth in TPL-001-0 are sufficiently clear and 
objective to provide guidance for compliance.
    1067. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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, the Commission 
proposes to direct that NERC 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) as 
discussed above.
d. System Performance Following Loss of a Single Element (TPL-002-0)
i. NERC Proposal
    1068. Proposed Reliability Standard TPL-002-0 concerns planning 
system relevant 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. NERC states that the Reliability Standard 
ensures that the future Bulk-Power System is planned to meet the system 
performance requirements of a

[[Page 64866]]

system, 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.\326\ Meeting these requirements means two things. First, 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, 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. The 
Reliability Standard applies both to near-term and longer-term planning 
horizons.
---------------------------------------------------------------------------

    \326\ The performance requirements are set forth in Category B 
of Table I of the Reliability Standard.
---------------------------------------------------------------------------

    1069. TPL-002-0 specifies that the planning authority and 
transmission planner must demonstrate through a valid assessment that 
the 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 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.
ii. Staff Preliminary Assessment
    1070. Staff stated that its general concerns regarding stressing 
the system during simulations and event-based contingencies apply to 
TPL-002-0. In other words, TPL-002-0 does not require sensitivity 
studies to define critical conditions and does not address the 
unanticipated failure of some single elements in the Bulk-Power System 
that result in subsequent loss of multiple elements. Staff also stated 
that footnotes associated with Table 1, which are meant to aid the 
interpretation of the performance requirements, are ambiguous and need 
to be clarified so that they are applied appropriately and consistently 
by all the entities to whom they apply. In particular staff noted that 
for TPL-002-0 footnote (b) to the Reliability Standard is sufficiently 
ambiguous to allow differing interpretations.\327\
---------------------------------------------------------------------------

    \327\ Footnote (b) reads states ``Planned or controlled 
interruption of electric supply to radial customers or some local 
Network customers, connected to or supplied by the Faulted element 
or by the affected area, may occur in certain areas without 
impacting the overall reliability of the interconnected transmission 
systems. To prepare for the next contingency, system adjustments are 
permitted, including curtailments of contracted Firm (non-recallable 
reserved) electric power transfers.''
---------------------------------------------------------------------------

    1071. Staff further noted that while the Reliability Standard 
defines various categories of conditions to be simulated, the specific 
study elements selected from each of the categories for assessments are 
subject to approval by the associated regional reliability 
organization, even though they may impact neighboring utilities and 
reliability coordinators.
iii. Comments
    1072. NERC states that the reliability Standards do not consider 
load shedding acceptable for single contingency events. As such, 
footnote (b) provides a limited exception to the general rule against 
serving load from a radial transmission line.
    1073. In addition to its comments regarding stressing the system 
discussed above, NERC comments that it intends to pursue the following 
improvements: (1) Expand the list of Category B contingencies, and 
differentiate between an element (i.e., circuit) and a system of 
elements (i.e., multi-circuit line or DC bi-pole); (2) review Category 
B and C contingencies based not only on probability, but also on 
reliability risk and consider including risk quantification methodology 
in the Reliability Standards; and (3) clarify footnote (b) of Table 1 
to address staff's concern.
    1074. CenterPoint disagrees with staff that planners should 
specifically plan for planned outages plus unplanned outages. According 
to CenterPoint, it suffices that operators currently schedule planned 
outages at times when reliability risk is minimized. Further, it 
contends that planning for one planned outage in addition to outages 
prescribed in the TPL Reliability Standards would make an N-1 
requirement effectively an N-2 requirement. Based on that premise, it 
argues that no utility has software to exhaustively test every 
conceivable combination of outages or that it would be worthwhile to do 
so.
    1075. ReliabilityFirst and TAPS also agree that footnote (b) needs 
clarification. However, ReliabilityFirst comments that the wording 
simply reflects how the system is actually built rather than indicating 
a lower level of performance.
    1076. The ISO/RTO Council comments that the process for determining 
load levels for purposes of Requirement 1 of TPL-002-0 needs to be 
standardized, and local area networks and system adjustments should be 
specifically defined.
    1077. MRO finds an inconsistency in Table 1. Under the ``Loss of 
Demand or Curtailed Firm Transfers'' column for category B the entries 
are all ``No.'' However, footnote (b) indicates that curtailments of 
contracted firm transfers are permitted. MRO states that the ``no'' 
response in this column may need to be revised to ``Planned/
Controlled'' as it is used for other categories of disturbances.
iv. Commission Proposal
    1078. The Commission proposes to approve TPL-002-0 as a mandatory 
and enforceable Reliability Standard. In addition, we propose to direct 
that NERC develop modifications to the Reliability Standard, as 
discussed below.
    1079. The Commission notes that, like TPL-001-0, 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 does not specify the rationale for 
determining critical system conditions and study years. The Commission 
therefore proposes to direct NERC to modify TPL-002-0 to require that 
critical system conditions be determined in the same manner as we 
propose with regard to TPL-001-0. The Commission also proposes that the 
results of these studies be documented to support the selection of 
critical system conditions and study years used in assessing system 
performance. We also note that load models used in system studies have 
a significant impact on system performance, particularly as they relate 
to the dynamic performance of the system. The Commission proposes that 
the documentation of system studies include a description of the load 
models used including supporting rationale for their use. The 
Commission expects the ERO to provide consistency and quality control 
in these interpretations and that over time one or more performance 
metrics would be

[[Page 64867]]

developed to assess the rigor of these evaluations.
    1080. The Commission commends NERC's initiative on improving the 
TPL standards and proposes that NERC modify the Reliability Standard to 
expand category B to achieve consistency in continent-wide Reliability 
Standards.
    1081. With regard to CenterPoint's concerns, we disagree that 
planned outages would be considered the same as an unexpected 
contingency that would effectively turn an N-1 scenario into an N-2 
scenario. Further, the studies/assessments should recognize that 
planned outages are not scheduled for peak periods and when required 
the system is adjusted to accommodate the planned outage. However, we 
do not believe that fact justifies ignoring planned outages altogether, 
as suggested by CenterPoint. While TPL-002-0 requires consideration of 
planned outages at those demand levels for which planned outages are 
performed, it does not address situations in which 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 
as required for reliability. Therefore, the Commission proposes that 
the ERO modify the Reliability Standard by developing a new requirement 
that would include the reliability impact of an entity's existing spare 
equipment strategy, address the unavailability of long lead time 
critical facilities. Critical facilities are those facilities that 
impact IROLs and deliverability of generation to firm load.
    1082. Order No. 661 requires all wind generators to remain online 
during voltage disturbances for specified time periods and associated 
voltage levels. Category B and some Category C events capture these 
disturbances for planning study purposes.\328\ We understand that the 
TPL Reliability Standards implicitly require all generators to ride 
through these same types of voltage disturbances and remain in service 
after the fault is cleared. The Commission proposes to direct NERC to 
modify TPL-002-0 to explicitly state this requirement.
---------------------------------------------------------------------------

    \328\ Interconnection for Wind Energy, Order No. 661, 70 FR 
34993 (June 16, 2005), FERC Stats. & Regs. ] 31,186 (2005), order on 
reh'g, Order No. 661-A, 70 FR 75,005 (Dec. 19, 2005), FERC Stats. & 
Regs. ] 31,198 (2005).
---------------------------------------------------------------------------

    1083. Several commenters agree with staff that a number of 
footnotes of Table 1 could be enhanced. We agree with TIS with respect 
to footnote (a), which is applicable to TPL-002-0. This states, in 
part, ``[a]pplicable ratings may include Emergency Ratings applicable 
for short durations as required to permit operating steps necessary to 
maintain system control.'' \329\ TIS states that on the basis of its 
review of criteria, methods and practices used for system design, 
planning and analysis across the NERC reliability regions, the footnote 
is intended to provide flexibility to the responsible planning entity 
to decide the appropriate planning response. That response could be to 
plan for a facility addition or enhancement, or to develop and document 
an operating guide or procedure that can be reliably implemented to 
achieve the required system performance for the event in question. In 
the latter case, the operating action must be completed in sufficient 
time to return the system to a secure operating state with no 
additional loss of firm load. The Commission proposes to require that 
the phrase ``permit operating steps necessary to maintain system 
control'' be clarified to state that the operating steps required to 
relieve emergency loadings and return the system to a normal state do 
not include firm load shedding. The Commission also proposes that these 
required operating steps be identified and be capable of returning the 
system to the normal secure state within the 30 minute allowable 
period.
---------------------------------------------------------------------------

    \329\ NERC TIS Report at 15.
---------------------------------------------------------------------------

    1084. Footnote (b) to Table 1 raises three issues that need to be 
addressed. Two relate to the use of planned or controlled load 
interruptions under certain circumstances, and the third relates to the 
use of system adjustments including curtailment of firm transfers to 
prepare for the next contingency. NERC and TAPS agree with the Staff 
Preliminary Assessment that footnote (b) of Table 1 could be enhanced 
with regard to its intended interpretation for contingencies associated 
with transmission lines used to serve or supply load. NERC states that 
it does not consider shedding load acceptable for single contingency 
events. The Commission agrees and thus proposes to require NERC 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).\330\ For purposes of clarity, the 
Commission proposes to require that the phrase ``to prepare for the 
next contingency, system adjustments are permitted, including 
curtailments of contracted Firm (non-recallable reserved) electric 
power transfers'' be deleted from footnote (b). This statement is more 
appropriate for Category C events and is already captured by footnote 
(c) to Table 1, which is applicable to Category C events.
---------------------------------------------------------------------------

    \330\ Load associated with the failure could be radial load 
supplied by the transmission element that is assumed to be removed 
from service, load supplied from separate transmission elements that 
are both removed from service due to a single failure, or load that 
is tapped onto a single transmission element.
---------------------------------------------------------------------------

    1085. While all commenters agree with staff on the need to clarify 
footnote (b), the Commission has proposed above that footnote (b) be 
clarified to allow no firm load or firm transactions to be interrupted 
except consequential load loss. NERC identifies another concern with 
its example, specifically, the acceptable magnitude and duration of 
consequential load loss. The Commission believes that the Reliability 
Standard should provide some limits on the magnitude and duration of 
consequential load loss. While the Commission does not propose to 
require any specific maximum consequential load loss level or maximum 
load loss duration at this time, we do propose to require that those 
values be documented by all users of the Bulk-Power System.
    1086. MRO points to the same ambiguity in Table 1 that staff 
identified in the Staff Preliminary Assessment. The Commission 
interprets Table 1 to specify no permitted loss of demand or 
curtailment of firm transfers for Category B contingencies. If the 
Reliability Standard intended to use Planned/Controlled demand loss, it 
would have stated such, as they do in other portions of the same table. 
It is footnote (b) that introduces the ambiguity, and the Commission 
proposes that the footnote be viewed as identifying rare exceptions, 
such as radial customers.
    1087. The Commission proposes to require that the purpose statement 
of TPL-002-0 be modified to reflect the specific goal of the 
Reliability Standard.
    1088. While the Commission has identified a number of concerns with 
regard to TPL-002-0, this proposed Reliability Standard serves an 
important purpose by ensuring that the future Bulk-Power System is 
planned to meet the system performance requirements of a system, with 
the loss of one element. Further, the Requirements set forth in TPL-
002-0 are sufficiently clear and objective to provide guidance for 
compliance.
    1089. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission

[[Page 64868]]

by the ERO and that it will improve the reliability of the nation's 
Bulk-Power System, the Commission proposes to approve Reliability 
Standard TPL-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 proposes to direct that NERC submit a modification to 
TPL-002-0 that: (1) Requires that critical system conditions be 
determined in the same manner as we propose to require for TPL-001-0; 
(2) requires the inclusion of the reliability impact of the entities' 
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), as discussed above.
e. System Performance Following Loss of Two or More Elements (TPL-003-
0)
i. NERC Proposal
    1090. NERC states that proposed Reliability Standard TPL-003-0 
ensures 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.
    1091. 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.
ii. Staff Preliminary Assessment
    1092. Commission staff stated in its Staff Preliminary Assessment 
that TPL-003-0 does not require sensitivity studies to define critical 
conditions and study years, does not base its contingencies on probable 
events, and as a result has contingencies included that would be more 
appropriate in Category B contingencies treated under TPL-002-0. Staff 
also stated that footnotes associated with TPL-003-0 in Table 1, which 
are meant to aid the interpretation of the performance requirements, 
are ambiguous and require clarification to permit appropriate and 
consist application.
    1093. Staff noted that the purpose statement for TPL-003-0 is 
identical to those for TPL-001, TPL-003 and TPL-004, although the 
Reliability Standard has a different goal and different requirements. 
Staff further noted that while the Reliability Standard defines various 
categories of conditions to be simulated, the specific study elements 
selected from each of the categories for assessments are subject to 
approval by the associated regional reliability organization, even 
though they may impact neighboring utilities and reliability 
coordinators.
iii. Comments
    1094. ISO/RTO Council comments that Requirement 2 of TPL-003-0 does 
not clearly define ``simulation'' and does not define ``inability to 
respond.'' In addition, several commenters note that the footnotes in 
Table 1 of the TPL group of Reliability Standards could be enhanced, 
including footnote (c) of Table 1.
iv. Commission Proposal
    1095. The Commission proposes to approve proposed Reliability 
Standard TPL-003-0 as a mandatory and enforceable Reliability Standard. 
In addition, we propose to direct that NERC develop modifications to 
the Reliability Standard, as discussed below.
    1096. The Commission notes that, like TPL-001-0 and TPL-002-0, in 
assessing system performance, TPL-003-0 requires entities to cover 
``critical system conditions and study years'' as deemed appropriate by 
the entity performing the study, but does not specify the rationale for 
determining critical system conditions and study years. The Commission 
therefore proposes that NERC modify TPL-003-0 to require that critical 
system conditions be determined in the same manner discussed above with 
regard to TPL-001-0. The Commission also proposes that the results of 
these studies be documented to support the selection of critical system 
conditions and study years used in assessing system performance. Also 
the Commission notes that load models used in system studies have a 
significant impact on system performance, particularly as they relate 
to the dynamic performance of the system. The Commission proposes that 
the documentation of system studies include a description of the load 
models used including supporting rationale for their use.
    1097. Several commenters agree with Commission staff that a number 
of footnotes in Table 1 to the Reliability Standard could be enhanced. 
The reference to ``controlled interruption'' of load in regard to 
footnote (c), which is applicable to TPL-003-0, suggests the 
possibility of automatic load shedding through the use of Special 
Protection Systems or safety nets such as Under Voltage Load Shedding 
Schemes. Alternatively, a defined manual load interruption could be 
used to deal with short-time emergency thermal overloads. The 
Commission proposes to require that the ERO modify footnote (c) to 
provide specificity regarding the use of the term ``controlled 
interruption'' of load. Further, the Commission proposes that, in 
modifying TPL-003-0, the ERO require documentation and identification 
of the firm load that is subject to the controlled interruption. To 
avoid any undue negative impact on competition, third-party impact 
studies would be permitted to implement the same or less controlled 
load interruption as used by the transmission owner.
    1098. The performance requirements for Category C events stipulate 
``no cascading outages.'' The NERC Transmission Issues Subcommittee 
identified a concern regarding the determination of whether cascading 
outages result in the evaluation of Category C events.\331\ This 
concern relates to the use of thermal overload or low voltage proxies 
to judge the likelihood of subsequent line or generator trips. The 
Commission proposes to require NERC to modify the Reliability Standard 
to require the applicable entities to define and document the proxies 
necessary to simulate cascading outages and to

[[Continued on page 64869]]

From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 64869-64879]] Mandatory Reliability Standards for the Bulk-Power System

[[Continued from page 64868]]

[[Page 64869]]

require that the ERO approve the proxies.
    1099. Category C3 of TPL-003-0 involves a situation in which two 
single contingencies occur, with manual system adjustments permitted 
after the first contingency to prepare for the next one. Proposed 
Reliability Standard IRO-005-0 requires that the manual system 
adjustments be implemented as soon as possible and no later than 30 
minutes after the first contingency has occurred. 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. Recognizing this risk and its potential 
consequences, some entities plan and operate their systems so that they 
are able to withstand the simultaneous occurrence of the two 
contingencies for major load pockets.\332\ The Commission solicits 
comments on the value and appropriateness of including such a 
requirement in TPL-003-0.
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    \331\ See NERC TIS Report.
    \332\ Two entities are Consolidated Edison Company of New York 
and Public Service Electric and Gas.
---------------------------------------------------------------------------

    1100. The Commission also notes that TPL-003-0 would be enhanced if 
its purpose statement were tailored to reflect the specific goal of the 
Reliability Standard and that each requirement should correspond with 
one or more Measures and each Measure should correspond to a Level of 
Non-Compliance.
    1101. While the Commission has identified a number of concerns with 
regard to TPL-003-0, this proposed Reliability Standard serves an 
important purpose by ensuring that the future Bulk-Power System is 
planned to meet the system performance requirements of a system with 
the loss of multiple elements. Further, the Requirements set forth in 
TPL-003-0 are sufficiently clear and objective to provide guidance for 
compliance.
    1102. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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, the Commission 
proposes to direct that NERC 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) clarifies footnote (c) as discussed above; (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, as discussed above.
f. System Performance Following Extreme Events (TPL-004-0)
i. NERC Proposal
    1103. NERC states the proposed Reliability Standard TPL-004-0 
ensures 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 does this by requiring that the transmission 
planner and the planning authority to evaluate and document annually 
the risks and consequences of Category D contingencies (i.e., extreme 
events resulting in loss of two or more elements or cascading) for the 
near-term (five-year) planning horizon.
    1104. 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.
ii. Staff Preliminary Assessment
    1105. ``Extreme events'' are low probability but high impact 
events. Staff noted that while the Reliability Standards require 
assessments of extreme events, documentation of the results and 
submission to the regional reliability organization, they do not 
require that consideration be given either to reducing the probability 
of the loss of multiple elements or mitigating the impact.
    1106. Staff also stated that this proposed Reliability Standard 
does not require that assessment results be shared with impacted 
entities or communicated to operations planning staff and control room 
operators. Staff noted that TPL-004-0 does not address scenarios that 
are equal to or more severe than actual weather events, such as 
hurricanes that affect the Southern United States and ice storms in the 
north.
iii. Comments
    1107. ISO/RTO Council believes that Requirement R1 of TPL-004-0 
needs to be revised to provide better definition of terms and 
obligations and requires review to determine whether it is too 
prescriptive in specifying responses to extreme contingencies. ISO/RTO 
Council also believes that before Requirement R2 can be enforced, 
regional seasonal assessments should be provided to the regional 
reliability organizations.
    1108. MRO does not believe that it is practical to develop 
deterministic criteria for extreme events. MRO and the New York 
Commission state that Reliability Standards should not require 
improvements that are not justified by very low probability events. 
However, a Reliability Standard should require assessment and 
consideration of actions necessary to resolve such events. MidAmerican 
recommends that transmission planning Reliability Standards permit 
probabilistic approaches to responding to extreme events and events in 
Category D of Table 1. While the probability of extreme events often 
does not warrant system improvements, it does make sense to require 
consideration of mitigating actions or improvements whose cost is 
justified by the expected benefits.
    1109. ReliabilityFirst recommends that consideration should be 
given to establishing some record of studies and identifying system 
weaknesses. CenterPoint states it does not believe that companies 
should be required to share planning assessments because it relates 
more to open access tariff concerns than reliability. In addition, 
sharing assessments would promote the unnecessary disclosure of 
critical energy infrastructure information.
iv. Commission Proposal
    1110. The Commission proposes to approve proposed Reliability 
Standard TPL-004-0 as a mandatory and enforceable Reliability Standard. 
In addition, we propose to direct that NERC develop modifications to 
the Reliability Standard, as discussed below.
    1111. The Commission notes that, like Reliability Standards TPL-
001-0 through TPL-003-0, TPL-004-0 requires entities assessing system 
performance to cover ``critical system

[[Page 64870]]

conditions and study years'' the entity performing the study deems 
appropriate, but it does not specify the rationale for determining 
critical system conditions and study years. The Commission therefore 
proposes that NERC modify TPL-004-0 to require that critical system 
conditions be determined in the same manner as discussed above with 
regard to TPL-001-0. The Commission also proposes that the results of 
these studies be documented to support the selection of critical system 
conditions and study years used in assessing system performance. Also 
the Commission notes that load models used in system studies have a 
significant impact on system performance, particularly as they relate 
to the dynamic performance of the system. The Commission proposes that 
the documentation of system studies include a description of the load 
models used including supporting rationale for their use.
    1112. MidAmerican and MRO agree with Commission staff that 
consideration must be given to mitigating actions associated with 
impacts of extreme events. MidAmerican proposes using an approach to 
take into account probability, impact and value to customers of 
reliability. MRO cautions against requiring improvements that cannot be 
justified. NERC also states that Reliability Standards should not 
require compliance with a high-impact, low probability contingency 
imposed on a low probability base case. The Commission agrees that the 
Reliability Standard should not require improvements for low 
probability events that cannot be justified. However, the Commission 
proposes that NERC modify TPL-004-0 to require the identification of 
options for reducing the probability or impacts of extreme events that 
cause cascading outages. The Commission also proposes that these 
options be documented together with a supporting rationale for cases 
where such options were not pursued.
    1113. In determining the range of extreme events to be assessed, 
staff noted that a number of recent high risk events, such as the 
hurricanes affecting the southern United States and the ice storm in 
the north, resulted in a greater impact on the Bulk-Power System in 
terms of the number of elements forced out of service than events 
listed in TPL-004-0. The Commission proposes that the contingency list 
of Category D be expanded to include similar events.
    1114. Staff noted that the Reliability Standard does not explicitly 
require that the results of assessments be shared with impacted 
entities or communicated to operations planning staff and control room 
operators. While CenterPoint disfavors such information sharing, we 
believe that sharing assessment results would serve an important 
reliability purpose as it would provide system operators and impacted 
entities with an opportunity to mitigate the identified impact. 
However, we agree with CenterPoint that any such requirement should 
make clear that that critical energy infrastructure information should 
not be unnecessarily disclosed.
    1115. The Commission also notes that TPL-004-0 would be enhanced if 
its purpose statement would be tailored to reflect the specific goal of 
the standard. In addition, the Commission proposes that each 
requirement should correspond to one or more measures and each measure 
should correspond to a level of non-compliance.
    1116. While the Commission has identified a number of concerns with 
regard to TPL-004-0, this proposed Reliability Standard serves an 
important purpose by ensuring that the future Bulk-Power System is 
evaluated to assess the risks and consequences of an extreme event 
involving the loss of multiple elements. Further, the Requirements set 
forth in TPL-004-0 are sufficiently clear and objective to provide 
guidance for compliance.
    1117. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes 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, the Commission 
proposes to direct that NERC 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.
g. Regional and Interregional Self-Assessment Reliability Reports (TPL-
005-0)
i. NERC Proposal
    1118. NERC states that proposed Reliability Standard TPL-005-0 
ensures that each regional reliability organization conducts 
reliability assessments of its existing and planned regional bulk 
electric system annually by requiring the regional reliability 
organization 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.
ii. Staff Preliminary Assessment
    1119. Staff noted that the Reliability Standard identifies the 
regional reliability organization as the applicable entity.
iii. Comments
    1120. NYSRC recommends that this proposed Reliability Standard be 
withdrawn, as it anticipates that regional reliability organizations 
will develop regional transmission planning standards due to regional 
differences specific to their region. CenterPoint also suggests that 
the proposed Reliability Standard be eliminated.
    1121. ISO/RTO Council states that the term and extent of 
assessment, as well as the study years, are not appropriately defined; 
the process for determining load levels needs to be standardized; and 
local area networks and system adjustments need to be specifically 
defined.
iv. Commission Proposal
    1122. Consistent with our discussion in the Common Issues section 
above, the Commission will not propose any action on TPL-005-0, as it 
applies only to regional reliability organizations. Accordingly, the 
Reliability Standard will remain pending at the Commission. The 
Commission believes that, in the long-run, the Regional Entities should 
be responsible for conducting reliability assessments of the existing 
and planned regional system. However, during the current period of 
transition, the regional reliability organizations should continue to 
perform this role as they have in the past.
    1123. In addition, the Commission agrees with the ISO/RTO Council 
regarding the shortcomings in the Reliability Standard it has 
identified and proposes that NERC address these issues in the revision 
to the Reliability Standard.

[[Page 64871]]

h. Assessment Data From Regional Reliability Organizations (TPL-006-0)
i. NERC Proposal
    1124. NERC states that proposed Reliability Standard TPL-006-0 
ensures 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.
ii. Staff Preliminary Assessment
    1125. Staff noted that the Reliability Standard identifies the 
regional reliability organization as the applicable entity.
iii. Comments
    1126. NYSRC recommends that this Reliability Standard be withdrawn 
because it anticipates that regional reliability organizations will 
develop regional transmission planning standards based on regional 
differences specific to their regions. CenterPoint also suggests 
eliminating this Reliability Standard.
    1127. ISO/RTO Council suggests that, for the ERO to be successful 
at assessing overall reliability, it must identify what data and 
reports it needs to review in order to ensure that adequate planning is 
being conducted.
iv. Commission Proposal
    1128. Consistent with our discussion in the Common Issues section 
above, the Commission will not propose any action on TPL-006-0, as it 
applies only to regional reliability organizations. Accordingly, the 
Reliability Standard will remain pending at the Commission. The 
Commission believes that, in the long-run, the Regional Entities should 
be responsible for providing 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. However, during the current period of 
transition, the regional reliability organizations should continue to 
perform this role as they have in the past.
13. VAR: Voltage and Reactive Control
a. Overview
    1129. 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. Because there is 
significant overlap between VAR-001-0 and version 1 Reliability 
Standards, the Commission will address them collectively below, giving 
due consideration to the new Requirements in addressing the proposed 
disposition of VAR-001-1 and VAR-002-1.
b. Voltage and Reactive Control (VAR-001-1 and VAR-002-1)
i. NERC Proposal
    1130. NERC explains that VAR-001-1 requires the transmission 
operator to monitor and control voltage levels, reactive flows, and 
reactive resources, in order to keep these parameters within their 
reliability limits. Further, it requires a generator operator to 
provide critical operating data to its transmission operator, and to 
maintain generator field excitation at proper levels. The proposed 
Reliability Standard would apply to transmission operators, generator 
operators and purchasing-selling entities.
    1131. In its August 28, 2006 Supplemental Filing, NERC indicates 
that VAR-001-1 includes three new Requirements, designated R3, R4 and 
R11, which apply to transmission operators. Requirement R9 from VAR-
001-0, which applies to generator operators, is now replaced with five 
Requirements in VAR-002-1. Both Reliability Standards include Measures 
and Levels of Non-Compliance.
ii. Staff Preliminary Assessment
    1132. The VAR Reliability Standard requires each transmission owner 
to ``acquire sufficient reactive resources within its areas to protect 
the voltage levels under normal and Contingency conditions'' and 
``maintain system and Interconnection voltages within established 
limits.'' \333\ The Staff Preliminary Assessment stated that these 
Requirements may not be sufficient to assure reliable operation when 
operating power systems under conditions that make them vulnerable to 
voltage collapse.\334\ Staff noted that voltage instability has been a 
common causal factor in major power outages worldwide and voltage 
magnitudes alone are poor indicators of voltage stability.
---------------------------------------------------------------------------

    \333\ See VAR-001-1, Requirements R2 and R8.
    \334\ Staff Preliminary Assessment at 118 (although the Staff 
Preliminary Assessment addresses concerns regarding the version 0 
VAR Reliability Standard, many of these same concerns apply to the 
version 1 VAR Reliability Standards as well).
---------------------------------------------------------------------------

    1133. The Staff Preliminary Assessment explained that the proposed 
Reliability Standard does not require applicable entities to perform 
operations planning studies that would identify the minimum permissible 
pre-contingency voltage levels and reactive power reserves to ensure 
stable post-contingency voltages. In addition, the standard does not 
require similar voltage stability assessments to be carried out 
periodically during real-time operations so that system operators can 
continuously respond to changing system conditions.
    1134. Because voltage and reactive control is an integral part of 
Interconnection Reliability Operating Limits and voltage collapse can 
result in widespread cascading outages, staff expressed concern that 
reliable operation of the Bulk-Power System requires that reliability 
coordinators be authorized to direct and coordinate voltage and 
reactive control among operating entities in an Interconnection, and 
accordingly this standard should also apply to reliability 
coordinators. Similarly, staff noted that Requirement R5, which 
requires each purchasing-selling entity to arrange for reactive 
resources to satisfy its reactive requirements identified by its 
transmission service provider, does not currently apply to load-serving 
entities, even though a load-serving entity is responsible for 
significantly more load than a purchasing-selling entity. Therefore, 
the Reliability Standard should also apply to load-serving entities.
    1135. Finally, staff noted that the proposed reliability standard 
does not address Recommendation No. 23 of the Blackout Report, 
``[s]trengthen reactive power and voltage control practices in all NERC 
regions.'' \335\ However, staff noted that NERC did respond to the 
recommendation by establishing the Transmission Issues Subcommittee 
(TIS) which completed an evaluation of reactive power planning and 
voltage control practices.
---------------------------------------------------------------------------

    \335\ Blackout Report at 160.
---------------------------------------------------------------------------

iii. Comments
    1136. NERC states that the proposed reactive power and voltage 
control

[[Page 64872]]

Reliability Standard is adequate and necessary to protect the 
reliability of the Bulk-Power System. It points out that, in addition 
to the proposed Reliability Standard, a number of other Version 0 
standards in the IRO, TOP, and TPL series address reactive power and 
voltage control requirements and suggests that the proposed Reliability 
Standards should be viewed in their entirety in assessing their 
adequacy.
    1137. Nonetheless, NERC states that staff is correct that 
additional consideration regarding the development of the Reliability 
Standard related to reactive power and voltage control, reactive 
reserves, and the related subject of under-voltage load shedding is 
required. It explains that, in response to the Blackout Report 
recommendations related to reactive power and voltage control, the NERC 
Planning Committee prepared a report titled ``Evaluation of Reactive 
Power Planning and Voltage Control Practices,'' which was accepted by 
the NERC board of Trustees in May 2005. NERC states that it is 
committed to developing, as a high priority, new Reliability Standards 
that will incorporate the recommendations of the Planning Committee's 
report. NERC does not agree with the Staff Preliminary Assessment 
concerning the lack of applicability of the standard to load-serving 
entities. NERC contends that a load-serving entity that purchases 
outside resources to serve its load and uses transmission service to 
import that energy acts as a purchasing-selling entity and must arrange 
reactive support services pursuant to VAR-001-0.
    1138. ReliabilityFirst, on the other hand, agrees with staff's 
concern that the proposed Reliability Standard should apply to load-
serving entities and reliability coordinators. As a general matter and 
in the specific context of the proposed Reliability Standard, 
ReliabilityFirst states the work by NERC's drafting team to develop 
missing compliance elements must be expedited. In addressing staff's 
primary issues with this standard, ReliabilityFirst states that 
acceptable variations in voltage used by operating personnel should be 
minimized by the development of more defined terms.
iv. Commission Proposal
    1139. The Commission proposes to approve VAR-001-1 as mandatory and 
enforceable. In addition, we propose to direct that NERC develop 
modifications to the Reliability Standard, as discussed below.
    1140. As explained in the Staff Preliminary Assessment, the 
proposed Reliability Standard requires a transmission owner to 
``acquire sufficient reactive resources within its area to protect the 
voltage levels under normal and Contingency conditions'' \336\ and 
``maintain system and Interconnection voltages within established 
limits.'' \337\ In the Commission's view, technical requirements 
containing terms such as ``established limits'' or ``sufficient 
reactive resources'' are not definitive enough to address voltage 
instability and to ensure reliable operations.\338\ As an example of 
the Commission's concept of a more effective requirement, NERC should 
consider WECC's Reliability Criteria, which contain specific and 
definitive technical requirements on voltage and margin 
application.\339\ The Commission's view is also consistent with the 
NERC Transmission Issue Subcommittee's findings in its ``Evaluation of 
Reactive Power Planning and Voltage Control Practices.'' \340\ The 
Commission notes that VAR-001-1, while adding three new Requirements 
that apply to transmission operators regarding voltage and reactive 
control, still lacks the specific and technical Requirements on voltage 
and margin application to prevent voltage instability.\341\ Therefore, 
the Commission proposes directing NERC to modify VAR-001-1 to include 
more detailed and definitive requirements on ``established limits'' and 
``sufficient reactive resources'' to prevent voltage instability and to 
ensure reliable operations. These requirements for ensuring voltage 
stability shall be included in operations planning studies and real-
time assessment in addition to real time operation.
---------------------------------------------------------------------------

    \336\ VAR-001-1, Requirement R2.
    \337\ VAR-001-1, Requirement R8.
    \338\ See Staff Preliminary Assessment at 118, citing Blackout 
Report at 36 (``voltage magnitude alone is a poor indicator of 
voltage stability'').
    \339\ WECC's Reliability Criteria at 32 states ``For transfer 
paths, post-transient voltage stability is required with the path 
modeled at a minimum of 105% of the path rating (or Operational 
Transfer Capability) for system normal conditions (Category A) and 
for single contingencies (Category B). For multiple contingencies 
(Category C), post-transient voltage stability is required with the 
path modeled at a minimum of 102.5% of the path rating (or 
Operational Transfer Capability).
    \340\ See http://www.NERC.com/pub/sys/all_updl/pc/tis/TIS_Reactive_Recom7a_BOTapprvd_050305
.

    \341\ VAR-001-1 Requirement R3 requires transmission owners to 
specify criteria that exempt generators from complying with 
Requirement R4. Requirement R4 requires transmission owners to 
specify a voltage or reactive power schedule to be maintained by 
generators. Requirement R11 requires transmission operators to 
provide documentation to generator owners on necessary step-up 
transformer tap changes.
---------------------------------------------------------------------------

    1141. While real-time operations are covered by other standards, 
the requirement to perform periodic voltage stability analysis in real-
time operations is not directly addressed. Because of its importance to 
Bulk-Power System reliability, as discussed in section ii above, the 
Commission proposes that it be directly addressed in VAR-001-1.
    1142. Section 215(b) of the FPA provides that users, owners and 
operators of the Bulk-Power System must comply with a Commission-
approved Reliability Standard. As discussed above, NERC's proposed 
Reliability Standards identify the entities to which a particular 
Reliability Standard would apply according to the NERC Functional 
Model. According to NERC's proposal, VAR-001-1 would apply to 
transmission operators and purchasing-selling entities. In Requirement 
R5, purchasing-selling entities are required to arrange for reactive 
resources to satisfy their reactive requirements as identified by their 
transmission service provider. Because purchasing-selling entities are 
either self-providing or purchasing the reactive resources, they are 
clearly users of the Bulk-Power System.
    1143. The Commission believes that NERC's proposed applicability 
provision in VAR-001-1, in terms of the Functional Model, should be 
expanded to include ``reliability coordinators'' and ``load-serving 
entities.'' According to NERC's petition, ``load-serving entities'' are 
energy providers for end use customers, and NERC's functional model 
defines the load serving function as responsible for ``secur[ing] 
energy and transmission service (and related Interconnected Operations 
Services) to serve the end-use customer.'' \342\ Reliability 
coordinators and load-serving entities are operators and users of the 
bulk-power system respectively, and should be included in the 
applicability of this standard as discussed in more detail below.
---------------------------------------------------------------------------

    \342\ NERC glossary at 9.
---------------------------------------------------------------------------

    1144. In a complex power grid such as the one which 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 ReliabilityFirst concurred) that the applicability of 
this proposed Reliability Standard extend to both reliability 
coordinators and load-serving entities. Since reliability coordinators 
are the highest level of authority overseeing the reliability of the 
Bulk-Power System, it is important to include them as an applicable 
entity to maintain adequate voltage and reactive resources. As for 
load-serving entities, NERC states that

[[Page 64873]]

VAR-001-0 (and NERC's statement applies equally to VAR-001-1) is 
indirectly applicable to a load-serving entity in its role as a 
purchasing-selling entity to the extent that it purchases outside 
resources to serve its load and uses transmission service to import 
that energy. Although the Commission agrees with this statement to the 
extent that a load-serving entity is purchasing point-to-point 
transmission service to serve its load, it is not clear that a load-
serving entity would become a purchasing-selling entity when utilizing 
network service to meet its load obligations. The Commission is 
interested in comments concerning NERC's assertion that all load 
serving entities are also purchasing-selling entities.
    1145. We propose directing NERC to add reliability coordinators and 
load-serving entities to the existing list of applicable entities for 
VAR-001-1 for added clarity. VAR-001-1 recognizes that energy purchases 
of purchasing-selling entities can increase reactive power consumption 
on the Bulk-Power System and that they must supply what they consume. 
Load-serving entities also consume reactive power. We note that in many 
cases load response and load-side investment can reduce the need for 
reactive power capability in the system.\343\ Therefore, we propose to 
include controllable load among the reactive resources to satisfy 
reactive requirements.
---------------------------------------------------------------------------

    \343\ See Principles of Efficient and Reliable Reactive Power 
Supply and Consumption: FERC Staff Report (2005).
---------------------------------------------------------------------------

    1146. We are also interested in comments on the acceptable ranges 
of net power factor range at the interface that the load serving 
entities receive service from the Bulk-Power System during normal and 
extreme load conditions.
    1147. While the Commission has identified a number of concerns with 
regard to VAR-001-1, we believe that the proposal serves an important 
purpose in requiring users, owners and operators of the Bulk-Power 
System to maintain facilities within voltage limits. The Commission 
believes it is important for NERC to include Requirements which contain 
added specificity; and additional Requirements to perform voltage 
stability assessments during real-time operations. Nonetheless, the 
proposed requirements set forth in VAR-001-1 are sufficiently clear and 
objective to provide guidance for compliance.
    1148. Accordingly, giving due weight to the technical expertise of 
the ERO and with the expectation that the Reliability Standard will 
accomplish the purpose represented to the Commission by the ERO and 
that it will improve the reliability of the nation's Bulk-Power System, 
the Commission proposes to approve 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 
proposes to direct that NERC submit a modification to VAR-001-1 that: 
(1) Includes detailed and definitive requirements on ``established 
limits'' and ``sufficient reactive resources'' as discussed above, and 
identifies acceptable margins above the voltage instability points; (2) 
includes Requirements to perform voltage stability assessments 
periodically during real-time operations; and (3) expands the 
applicability to include reliability coordinators and load-serving 
entities.
    1149. The Commission commends NERC and industry for their efforts 
in expanding on Requirement R9, which applied to generator operators in 
VAR-001-0, and making it into several detailed Requirements in VAR-002-
1, which apply to generator operators and generator owners, complete 
with Measures and Levels of Non-Compliance to ensure appropriate 
generation operation to maintain network voltage schedules.
    1150. Accordingly, the Commission believes that Reliability 
Standard VAR-002-1 is just, reasonable, not unduly discriminatory or 
preferential, and in the public interest; and proposes to approve it as 
mandatory and enforceable.
14. Glossary of Terms Used in Reliability Standards
a. NERC Proposal
    1151. In its petition, NERC submitted, and requested approval of 
the Glossary of Terms Used in Reliability Standards. NERC states that 
the glossary, which defines terms used in Reliability Standards, 
initially became effective on April 1, 2005. The glossary is updated 
whenever a new or revised Reliability Standards is approved that 
includes a new term or definition. 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.
b. Staff Preliminary Assessment
    1152. While staff did not globally address the NERC glossary, it 
did express concern regarding the definition of bulk electric system in 
the glossary. Staff stated that differences between the Bulk-Power 
System in section 215 of the FPA and the NERC definition of bulk 
electric system could create a discrepancy that results in reliability 
``gaps.'' \344\ Further, in its discussion of planning (TPL) 
Reliability Standards, staff expressed concern regarding the statutory 
definition of Reliable Operation as it would impact the contingencies 
to be considered in setting system performance expectations set forth 
in the TPL standard.
---------------------------------------------------------------------------

    \344\ Staff Preliminary Assessment at 25-26.
---------------------------------------------------------------------------

c. Comments
    1153. Commenters note that some glossary terms are not consistent 
with the definition for those same terms in the ERO's Rules of 
Procedure. They point to the definition of regional reliability 
organization and load serving entity as examples. Comments on the term 
Bulk-Power System and Reliable Operation are included with the TPL 
chapter.
d. Commission Proposal
    1154. The Commission believes that the NERC glossary is an 
important supplement to understanding the mandatory and enforceable 
Reliability Standards. While we are generally satisfied with the NERC 
glossary, we believe that it is appropriate that NERC modify the 
glossary to include terms defined in section 215(a) of the FPA. 
Further, in the general Applicability discussion we explained our 
specific concerns regarding potential differences between the statutory 
term Bulk-Power System and the NERC term bulk electric system and how 
to bring consistency between the two terms. Further, in our discussion 
of general issues concerning the communication (COM) Reliability 
Standards, we identified specific concerns regarding the definitions of 
transmission operator and generator operator. We propose to direct that 
NERC modify the glossary to reflect these concerns.
    1155. With regard to commenters concerns regarding the consistency 
of definitions between the glossary and the ERO Rules of Procedure, we 
believe that the ERO documents should be consistent in their definition 
of a specific term. However, we will leave it to the ERO's discretion 
whether the glossary or the Rules of Procedure should be modified to 
assure consistency in the definition of any particular term.
    1156. Accordingly, the Commission proposes to approve the Glossary 
of Terms Used in Reliability Standards. In addition, we propose to 
direct that NERC submit, a modification to the

[[Page 64874]]

glossary that: (1) Includes the statutory definitions of Bulk-Power 
System, Reliable Operation, Reliability Standard, as set forth in 
section 215 (a); (2) modifies the definitions of ``transmission 
operator'' and ``generator operator'' to include aspects unique to ISO/
RTO and pooled resource organizations; (3) modifies the definition of 
``bulk electric system'' consistent with our discussion in the Common 
Issues section above; and (4) modifies the definition of terms 
concerning reserves (such as operating reserves) to include demand side 
management, including controllable load.

IV. Information Collection Statement

    1157. The Office of Management and Budget (OMB) regulations require 
that OMB approve certain reporting and recordkeeping (collections of 
information) imposed by an agency.\345\ The information contained here 
is also subject to review under Section 3507(d) of the Paperwork 
Reduction Act of 1995.\346\ As stated above, these 107 proposed 
Reliability Standards--of which the Commission proposes to approve 83 
in a final rule--make up the current NERC standards that the electric 
industry currently is expected to comply with on a voluntary basis. 
Therefore, in proposing to adopt the Reliability Standards, the 
Commission would adopt reporting requirements that have been 
implemented on a voluntary basis for many years in most instances. 
Because the reporting requirements are usual and customary practices in 
the industry, and respondents incur the time and financial resources in 
the course of their regular activity, the transition from voluntary to 
mandatory Reliability Standards effected by this Proposed Rule will not 
increase the reporting burden nor impose any additional information 
collection requirements.
---------------------------------------------------------------------------

    \345\ 5 CFR 1320.11.
    \346\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    1158. However, we also recognize that there may be some smaller 
entities such as municipal utilities, cooperatives and small generators 
that may not have been members of NERC and may not have been 
participants in NERC's voluntary standards program. For such entities, 
compliance with the proposed mandatory Reliability Standards will 
include compliance with reporting requirements for the first time.
    1159. It is difficult to determine exactly how many entities fall 
into this category. First, as discussed above with regard to 
applicability issues, not every proposed Reliability Standard would 
apply to every user, owner or operator of the Bulk-Power System, and 
each proposed Reliability Standard contains its own set of reporting 
requirements. For example, only 24 proposed Reliability Standards would 
apply to generators, which contain 142 reporting requirements.
    1160. Further, as discussed in greater detail below with regard to 
small business flexibility, NERC has indicated that it will propose 
specific limits on the applicability of Reliability Standards to small 
entities that do not have a material impact on the Bulk-Power System. 
While we do not pre-judge this proposal, we note that Commission 
acceptance of such a proposal could also have a significant impact on 
the reporting burden of small entities that have not previously 
complied with the NERC standards on a voluntary basis.
    1161. In addition, some small entities may join together in Joint 
Action Agencies or other such organizations that will be responsible 
for certain aspects of their members' compliance with mandatory 
Reliability Standards. Such umbrella organizations may lessen the 
reporting burden of individual users, owners and operators. 
Accordingly, the reporting burden estimate below, while based on the 
Commission's best information, is subject to numerous variables. 
Although there is considerable uncertainty regarding the number of 
entities or the burden on those entities for which compliance with 
reliability standards will be a new exercise and not a customary 
practice, the Commission provides below what it believes to be a 
reasonable estimate based on available information.

                                             Public Reporting Burden
----------------------------------------------------------------------------------------------------------------
                                                 Number of        Number of     Number of hours    Total annual
               Data collection                  respondents       responses      per  response        hours
----------------------------------------------------------------------------------------------------------------
FERC-725A...................................           2,000                1              100          200,000
----------------------------------------------------------------------------------------------------------------

    Information Collection Costs: The Commission seeks comments on the 
costs on complying with these requirements. It has projected the 
average annualized cost to be the following:
    1162. Title: Bulk Power System Mandatory Reliability Standards.
    1163. Action: Proposed Collection.
    1164. OMB Control No. To be Determined.
    1165. Respondents: Businesses or other for profit; not for profit 
institutions.
    1166. Frequency of Responses: On Occasion.
    1167. Necessity of the Information: This proposed rule implements 
section 215(d)(2) of the FPA, which provides 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.
    1168. Internal Review: The Commission has reviewed the proposed 
reliability standards and made a determination that these requirements 
are necessary to implement section 215 of the Energy Policy Act of 
2005. These requirements conform to the Commission's plan for efficient 
information collection, communication and management within the energy 
industry. The Commission has to assure itself, by means of internal 
review, that there is specific, objective support for the burden 
estimates associated with the information requirements.
    1169. Interested person may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426 [Attention: 
Michael Miller, Office of the Executive Director, Phone: (202) 502-
8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov.
    1170. For submitting comments concerning the collection(s) of 
information and the associated burden estimate(s), please send your 
comments to the contact listed above and to the Office of Information 
and Regulatory Affairs, Office of Information and Regulatory Affairs, 
Washington, DC

[[Page 64875]]

20503 [Attention: Desk Officer for the Federal Energy Regulatory 
Commission, phone (202) 395-4650, fax: (202) 395-7285, e-mail: 
oira_submission@omb.eop.gov.

V. Environmental Analysis

    1171. 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.\347\ The 
actions proposed 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.\348\
---------------------------------------------------------------------------

    \347\ 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).
    \348\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act Certification

    1172. The Regulatory Flexibility Act of 1980 (RFA) \349\ requires 
that a rulemaking contain either a description and analysis of the 
effect that the proposed rule will have on small entities or a 
certification that the rule will not have a significant economic impact 
on a substantial number of small entities. The RFA mandates 
consideration of regulatory alternatives that accomplish the stated 
objectives of a proposed rule and that minimize any significant 
economic impact on a substantial number of small entities and sends the 
certification to the Chief Counsel for Advocacy of the Small Business 
Administration (SBA). The SBA's Office of Size Standards develops the 
numerical definition of a small business. (See 13 CFR 121.201.) For 
electric utilities, a firm is small if, including its affiliates, it is 
primarily engaged in the transmission, generation and/or distribution 
of electric energy for sale and its total electric output for the 
preceding 12 months did not exceed four million megawatt hours.
---------------------------------------------------------------------------

    \349\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

    1173. Section 215(b) of the FPA requires all users, owners and 
operators of the Bulk-Power System to comply with Commission-approved 
Reliability Standards. As discussed above, each proposed Reliability 
Standard submitted for approval by NERC applies to some subset of 
users, owners and operators. Each proposed Reliability Standard 
includes an ``applicability'' statement that identifies the functional 
classes of entities responsible for compliance. Such functional classes 
include reliability coordinators, balancing authorities, transmission 
operators, transmission owners, generator operators, generator owners, 
interchange authorities, transmission service providers, market 
operators, planning authorities, transmission planners, resource 
planners, load-serving entities, purchasing-selling entities, and 
distribution providers.\350\
---------------------------------------------------------------------------

    \350\ See NERC Petition at 9-10.
---------------------------------------------------------------------------

    1174. As explained by NERC, a generator operator, for example, 
could include any entity that operates a generator interconnected to 
the grid, be it a large unit in excess of 1,000 MW or a small generator 
of one MW or less. NERC states that to ensure that Reliability 
Standards are applied cost effectively and that the applicability of 
Reliability Standards is focused on entities having a material impact 
on Bulk-Power System reliability; it will begin providing greater 
specificity in the applicability section of a Reliability 
Standard.\351\ For example, a Reliability Standard may identify 
limitations on applicability based on electric facility 
characteristics, such as generators with a minimum nameplate rating or 
a transmission facility energized at a specified kV level or 
greater.\352\ NERC plans to establish a set of guidelines to address 
this matter.
---------------------------------------------------------------------------

    \351\ Id. at 81-82.
    \352\ Id. at 10.
---------------------------------------------------------------------------

    1175. The Commission believes that the proposed Reliability 
Standards may cause some small entities to experience significant 
economic impact. While the Commission is mindful of the possible impact 
on small entities, the Commission is also concerned that Bulk-Power 
System reliability not be compromised based on an unwillingness of 
entities, large or small, to incur reasonable expenditures necessary to 
preserve such reliability. As we explained in Order No. 672:

    A proposed Reliability Standard may take into account the size 
of the entity that must comply with the Reliability Standard and the 
cost to those entities of implementing the proposed Reliability 
Standard. However, the ERO should not propose a ``lowest common 
denominator'' Reliability Standard that would achieve less than 
excellence in operating system reliability solely to protect against 
reasonable expenses for supporting this vital national 
infrastructure. For example, a small owner or operator of the Bulk 
Power-System must bear the cost of complying with each Reliability 
Standard that applies to it.\353\

    \353\ Order No. 672 at P 330.
---------------------------------------------------------------------------

    1176. While we cannot rule on the merits until a specific proposal 
has been submitted, we believe that reasonable limits on applicability 
based on size may be an acceptable alternative to lessen the economic 
impact on the proposed rule on small entities.\354\ We emphasize, 
however, that any such limits must not weaken Bulk-Power System 
reliability.
---------------------------------------------------------------------------

    \354\ See, discussion of Applicability to Small Entities, 
section III.B.3. above.
---------------------------------------------------------------------------

VII. Comment Procedures

    1177. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due January 2, 2007. Comments must 
refer to Docket No. RM06-16-000, and must include the commenter's name, 
the organization represented, if applicable, and the commenter's 
address. Comments may be filed either in electronic or paper format.
    1178. Comments may be filed electronically via the eFiling link on 
the Commission's Web site at http://www.ferc.gov. The Commission 

accepts most standard word processing formats and commenters may attach 
additional files with supporting information in certain other file 
formats. Commenters filing electronically do not need to make a paper 
filing. Commenters that are not able to file comments electronically 
must send an original and fourteen (14) copies of their comments to: 
Federal Energy Regulatory Commission, Office of the Secretary, 888 
First Street, NE., Washington, DC 20426.

VIII. Document Availability

    1179. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's 

Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    1180. From the Commission's Home Page on the Internet, this 
information is available in the Commission's document management 
system, 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.
    1181. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours. For assistance, please contact FERC 
Online Support at

[[Page 64876]]

1-866-208-3676 (toll free) or 202-502-6652 (e-mail at 
FERCOnlineSupport@FERC.gov), or the Public Reference Room at 202-502-

8371, TTY 202-502-8659 (e-mail at public.referenceroom@ferc.gov).

List of Subjects in 18 CFR Part 40

    Electric power, Reporting and recordkeeping requirements.

    By direction of the Commission.
Magalie R. Salas,
Secretary.

    In consideration of the foregoing, the Commission proposes to amend 
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 North American Electric Reliability Corporation which 
can be obtained from the Commission's Public Reference Room at 888 
First Street, NE., Room 2A, Washington, DC 20426.
    (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 make each effective 
Reliability Standard available on its Internet Web site.

    Note: The following appendices will not be published in the Code 
of Federal Regulations.

  Appendix A.--Proposed Disposition of Standards, Glossary and Regional
                               Differences
------------------------------------------------------------------------
                                                            Proposed
     Reliability standard               Title             disposition
------------------------------------------------------------------------
BAL-001-0....................  Real Power Balancing    Approve.
                                Control Performance.
BAL-002-0....................  Disturbance Control     Approve; direct
                                Performance.            modification.
BAL-003-0....................  Frequency Response and  Approve; direct
                                Bias.                   modification.
BAL-004-0....................  Time Error Correction.  Approve; direct
                                                        modification.
BAL-005-0....................  Automatic Generation    Approve; direct
                                Control.                modification.
BAL-006-1....................  Inadvertent             Approve; direct
                                Interchange.            modification.
CIP-001-0....................  Sabotage Reporting....  Approve; direct
                                                        modification.
COM-001-0....................  Telecommunications....  Approve; direct
                                                        modification.
COM-002-1....................  Communications and      Approve; direct
                                Coordination.           modification.
EOP-001-0....................  Emergency Operations    Approve; direct
                                Planning.               modification.
EOP-002-1....................  Capacity and Energy     Approve; direct
                                Emergencies.            modification.
EOP-003-0....................  Load Shedding Plans...  Approve; direct
                                                        modification.
EOP-004-0....................  Disturbance Reporting.  Approve; direct
                                                        modification.
EOP-005-1....................  System Restoration      Approve; direct
                                Plans.                  modification.
EOP-006-0....................  Reliability             Approve; direct
                                Coordination--System    modification.
                                Restoration.
EOP-007-0....................  Establish, Maintain,    Pending.
                                and Document a
                                Regional Blackstart
                                Capability Plan.
EOP-008-0....................  Plans for Loss of       Approve; direct
                                Control Center          modification.
                                Functionality.
EOP-009-0....................  Documentation of        Approve.
                                Blackstart Generating
                                Unit Test Results.
FAC-001-0....................  Facility Connection     Approve.
                                Requirements.
FAC-002-0....................  Coordination of Plans   Approve; direct
                                for New Facilities.     modification.
FAC-003-1....................  Transmission            Approve; direct
                                Vegetation Management   modification.
                                Program.
FAC-004-0....................  Methodologies for       Withdrawn.
                                Determining
                                Electrical Facility
                                Ratings.
FAC-005-0....................  Electrical Facility     Withdrawn.
                                Ratings for System
                                Modeling.
FAC-008-1....................  Facility Ratings        Approve; direct
                                Methodology.            modification.
FAC-009-1....................  Establish and           Approve.
                                Communicate Facility
                                Ratings.
FAC-012-1....................  Transfer Capabilities   Pending.
                                Methodology.
FAC-013-1....................  Establish and           Approve; direct
                                Communicate Transfer    modification.
                                Capabilities.
INT-001-1....................  Interchange             Approve; direct
                                Transaction Tagging.    modification.
INT-002-0....................  Interchange             Withdrawn.
                                Transaction Tag
                                Communication and
                                Assessment.
INT-003-1....................  Interchange             Approve; direct
                                Transaction             modification.
                                Implementation.
INT-004-1....................  Interchange             Approve; direct
                                Transaction             modification.
                                Modifications.
INT-005-1....................  Interchange Authority   Approve; direct
                                Distributes Arranged    modification.
                                Interchange.
INT-006-1....................  Response to             Approve; direct
                                Interchange Authority.  modification.
INT-007-1....................  Interchange             Approve.
                                Confirmation.
INT-008-1....................  Interchange Authority   Approve.
                                Distributes Status.
INT-009-1....................  Implementation of       Approve.
                                Interchange.
INT-010-1....................  Interchange             Approve.
                                Coordination
                                Exceptions.
IRO-001-0....................  Reliability             Approve; direct
                                Coordination--Respons   modification.
                                ibilities and
                                Authorities.
IRO-002-0....................  Reliability             Approve; direct
                                Coordination--Facilit   modification.
                                ies.
IRO-003-1....................  Reliability             Approve; direct
                                Coordination--Wide      modification.
                                Area View.
IRO-004-1....................  Reliability             Approve; direct
                                Coordination--Operati   modification.
                                ons Planning.
IRO-005-1....................  Reliability             Approve; direct
                                Coordination--Current   modification.
                                Day Operations.
IRO-006-3....................  Reliability             Approve; direct
                                Coordination--Transmi   modification.
                                ssion Loading Relief.
IRO-014-1....................  Procedures, Processes,  Approve.
                                or Plans to Support
                                Coordination Between
                                Reliability
                                Coordinators.

[[Page 64877]]

IRO-015-1....................  Notifications and       Approve.
                                Information Exchange
                                Between Reliability
                                Coordinators.
IRO-016-1....................  Coordination of Real-   Approve.
                                time Activities
                                Between Reliability
                                Coordinators.
MOD-001-0....................  Documentation of TTC    Pending.
                                and ATC Calculation
                                Methodologies.
MOD-002-0....................  Review of TTC and ATC   Pending.
                                Calculations and
                                Results.
MOD-003-0....................  Procedure for Input on  Pending.
                                TTC and ATC
                                Methodologies and
                                Values.
MOD-004-0....................  Documentation of        Pending.
                                Regional CBM
                                Methodologies.
MOD-005-0....................  Procedure for           Pending.
                                Verifying CBM Values.
MOD-006-0....................  Procedures for Use of   Approve; direct
                                CBM Values.             modification.
MOD-007-0....................  Documentation of the    Approve; direct
                                Use of CBM.             modification.
MOD-008-0....................  Documentation and       Pending.
                                Content of Each
                                Regional TRM
                                Methodology.
MOD-009-0....................  Procedure for           Pending.
                                Verifying TRM Values.
MOD-010-0....................  Steady-State Data for   Approve; direct
                                Transmission System     modification.
                                Modeling and
                                Simulation.
MOD-011-0....................  Regional Steady-State   Pending.
                                Data Requirements and
                                Reporting Procedures.
MOD-012-0....................  Dynamics Data for       Approve; direct
                                Transmission System     modification.
                                Modeling and
                                Simulation.
MOD-013-1....................  RRO Dynamics Data       Pending.
                                Requirements and
                                Reporting Procedures.
MOD-014-0....................  Development of          Pending.
                                Interconnection-
                                Specific Steady State
                                System Models.
MOD-015-0....................  Development of          Pending.
                                Interconnection-
                                Specific Dynamics
                                System Models.
MOD-016-1....................  Actual and Forecast     Approve; direct
                                Demands, Net Energy     modification.
                                for Load,
                                Controllable DSM.
MOD-017-0....................  Aggregated Actual and   Approve; direct
                                Forecast Demands and    modification.
                                Net Energy for Load.
MOD-018-0....................  Reports of Actual and   Approve.
                                Forecast Demand Data.
MOD-019-0....................  Forecasts of            Approve; direct
                                Interruptible Demands   modification.
                                and DCLM Data.
MOD-020-0....................  Providing               Approve; direct
                                Interruptible Demands   modification.
                                and DCLM Data.
MOD-021-0....................  Accounting Methodology  Approve; direct
                                for Effects of          modification.
                                Controllable DSM in
                                Forecasts.
MOD-024-1....................  Verification of         Pending.
                                Generator Gross and
                                Net Real Power
                                Capability.
MOD-025-1....................  Verification of         Pending.
                                Generator Gross and
                                Net Reactive Power
                                Capability.
PER-001-0....................  Operating Personnel     Approve.
                                Responsibility and
                                Authority.
PER-002-1....................  Operating Personnel     Approve; direct
                                Training.               modification.
PER-003-0....................  Operating Personnel     Approve; direct
                                Credentials.            modification.
PER-004-0....................  Reliability             Approve; direct
                                Coordination--Staffin   modification.
                                g.
PRC-001-0....................  System Protection       Approve; direct
                                Coordination.           modification.
PRC-002-0....................  Define and Document     Pending.
                                Disturbance
                                Monitoring Equipment
                                Requirements.
PRC-003-1....................  Regional Requirements   Pending.
                                for Analysis of
                                Misoperations of
                                Transmission and
                                Generation Protection
                                Systems.
PRC-004-1....................  Analysis and            Approve.
                                Mitigation of
                                Transmission and
                                Generation Protection
                                System Misoperations.
PRC-005-1....................  Transmission and        Approve; direct
                                Generation Protection   modification.
                                System Maintenance
                                and Testing.
PRC-006-0....................  Development and         Pending.
                                Documentation of
                                Regional UFLS
                                Programs.
PRC-007-0....................  Assuring Consistency    Approve.
                                with Regional UFLS
                                Program.
PRC-008-0....................  Underfrequency Load     Approve; direct
                                Shedding Equipment      modification.
                                Maintenance Programs.
PRC-009-0....................  UFLS Performance        Approve.
                                Following an
                                Underfrequency Event.
PRC-010-0....................  Assessment of the       Approve; direct
                                Design and              modification.
                                Effectiveness of UVLS
                                Program.
PRC-011-0....................  UVLS System             Approve; direct
                                Maintenance and         modification.
                                Testing.
PRC-012-0....................  Special Protection      Pending.
                                System Review
                                Procedure.
PRC-013-0....................  Special Protection      Pending.
                                System Database.
PRC-014-0....................  Special Protection      Pending.
                                System Assessment.
PRC-015-0....................  Special Protection      Approve.
                                System Data and
                                Documentation.
PRC-016-0....................  Special Protection      Approve; direct
                                System Misoperations.   modification.
PRC-017-0....................  Special Protection      Approve; direct
                                System Maintenance      modification.
                                and Testing.
PRC-018-1....................  Disturbance Monitoring  Approve.
                                Equipment
                                Installation and Data
                                Reporting.
PRC-020-1....................  Under-Voltage Load      Pending.
                                Shedding Program
                                Database.
PRC-021-1....................  Under-Voltage Load      Approve.
                                Shedding Program Data.
PRC-022-1....................  Under-Voltage Load      Approve.
                                Shedding Program
                                Performance.
TOP-001-0....................  Reliability             Approve; direct
                                Responsibilities and    modification.
                                Authorities.
TOP-002-1....................  Normal Operations       Approve; direct
                                Planning.               modification.
TOP-003-0....................  Planned Outage          Approve; direct
                                Coordination.           modification.
TOP-004-0....................  Transmission            Approve; direct
                                Operations.             modification.
TOP-005-1....................  Operational             Approve; direct
                                Reliability             modification.
                                Information.
TOP-006-0....................  Monitoring System       Approve; direct
                                Conditions.             modification.
TOP-007-0....................  Reporting SOL and IROL  Approve.
                                Violations.
TOP-008-0....................  Response to             Approve; direct
                                Transmission Limit      modification.
                                Violations.
TPL-001-0....................  System Performance      Approve; direct
                                Under Normal            modification.
                                Conditions.
TPL-002-0....................  System Performance      Approve; direct
                                Following Loss of a     modification.
                                Single BES Element.

[[Page 64878]]

TPL-003-0....................  System Performance      Approve; direct
                                Following Loss of Two   modification.
                                or More BES Elements.
TPL-004-0....................  System Performance      Approve; direct
                                Following Extreme BES   modification.
                                Events.
TPL-005-0....................  Regional and            Pending.
                                Interregional Self-
                                Assessment
                                Reliability Reports.
TPL-006-0....................  Assessment Data from    Pending.
                                Regional Reliability
                                Organizations.
VAR-001-1....................  Voltage and Reactive    Approve; direct
                                Control.                modification.
VAR-002-1....................  Generator Operations    Approve
                                for Maintaining
                                Network Voltage
                                Schedules.
Glossary.....................  Glossary of Terms Used  Approve; direct
                                in Reliability          modification.
                                Standards.
Regional Difference..........  BAL-001: ERCOT: CPS2..  Approve.
Regional Difference..........  INT-001/4: WECC         Pending.
                                Tagging Dynamic
                                Schedules and
                                Inadvertent Payback.
Regional Difference..........  BAL-006: MISO RTO       Approve.
                                inadvertent
                                Interchange
                                Accounting.
Regional Difference..........  BAL-006: MISO/SPP       Approve.
                                Financial Inadvertent
                                Settlement.
Regional Difference..........  INT-003: MISO/SPP       Approve.
                                Scheduling Agent.
Regional Difference..........  INT-003: MISO Enhanced  Approve.
                                Scheduling Agent.
Regional Difference..........  INT-001/3: MISO Energy  Approve.
                                Flow Information.
Regional Difference..........  IRO-006: PJM/MISO/SPP   Pending.
                                Enhanced Congestion
                                Management.
------------------------------------------------------------------------

         Appendix B.--Commenters on Staff Preliminary Assessment
------------------------------------------------------------------------
           Abbreviation                           Commenter
------------------------------------------------------------------------
Alberta...........................  Alberta Department of Energy;
                                     Alberta Utilities and Energy Board;
                                     Alberta Electric System Operator.
Alcoa.............................  Alcoa, Inc. and Alcoa Power
                                     Generating Company.
Allegheny.........................  Allegheny Power and Allegheny Energy
                                     Supply Company, LLC.
Ameren Services Co................  Ameren.
American Transmission.............  American Transmission Company, LLC.
Professor Bose....................  Professor Anjan Bose.
APPA..............................  American Public Power Association.
BG&E..............................  Baltimore Gas & Electric Company.
BPA...............................  Bonneville Power Administration.
CPUC..............................  Public Utilities Commission of the
                                     State of California.
CEA...............................  Canadian Electricity Association.
Centerpoint.......................  CenterPoint Energy Houston Electric,
                                     LLC.
Redding...........................  City of Redding, California.
Duke..............................  Duke Energy Corporation.
E.ON U.S..........................  E.ON U.S. LLC.
EEI...............................  Edison Electric Institute.
FPL Energy........................  FPL Energy.
FRCC..............................  Florida Reliability Coordinating
                                     Council.
Georgia System....................  Georgia System Operations
                                     Corporation.
Hydro One.........................  Hydro One Networks Inc.
ISO/RTO Council...................  The ISO/RTO Council.
KeySpan...........................  KeySpan--Ravenswood, LLC.
LPPC..............................  Large Public Power Council.
MEAG..............................  MEAG Power.
MidAmerican.......................  MidAmerican Energy Company.
MISO..............................  Midwest Independent Transmission
                                     System Operator, Inc.
MRO...............................  Midwest Reliability Organization.
Multiple Intervenors..............  Multiple Intervenors, an
                                     unincorporated association of
                                     approximately 55 large industrial,
                                     commercial and institutional end-
                                     use energy consumers with
                                     facilities in New York.
National Grid.....................  National Grid USA.
NCPA..............................  Northern California Power Agency.
NEMA..............................  National Electrical Manufacturers
                                     Association.
NERC..............................  North American Electric Reliability
                                     Council.
New York Commission...............  New York State Public Service
                                     Commission.
NPCC..............................  Northeast Power Coordinating
                                     Council.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
NYSRC.............................  New York State Reliability Council
                                     LLC.
Ohio Consumers' Council...........  Ohio Consumers' Council.
Old Dominion......................  Old Dominion Electric Cooperative.
Ontario IESO......................  Ontario Independent Electricity
                                     System Operator.
PG&E..............................  Pacific Gas & Electric Company.
PSEG Companies....................  Public Service Electric & Gas
                                     Company, PSEG Energy Resources &
                                     Trade LLC, PSEG Power LLC.
ReliabilityFirst..................  ReliabilityFirst Corporation.
SDG&E.............................  San Diego Gas & Electric Company.
SoCal Edison......................  Southern California Edison Company.
Southern..........................  Southern Company Services, Inc.

[[Page 64879]]

Southwest TDU.....................  Southwest Transmission Dependent
                                     Utility Group.
TANC..............................  Transmission Agency of Northern
                                     California.
TAPS..............................  Transmission Access Policy Study
                                     Group.
TVA...............................  Tennessee Valley Authority.
USDA Forest Service...............  U.S. Department of Agriculture
                                     Forest Service.
Valley Group......................  The Valley Group, Inc.
WECC..............................  Western Electricity Coordinating
                                     Council.
WECC OIWG.........................  Operating Issues Work Group, a work
                                     group of WECC's Compliance
                                     Monitoring and Operating Practices
                                     Subcommittee.
WECC/OTS..........................  Operations and Training
                                     Subcommittee, a subcommittee of
                                     WECC's Operating Committee.
Wisconsin Electric................  Wisconsin Electric Power Company.
------------------------------------------------------------------------

               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.
ERO...............................  Electric Reliability Organization.
GWh...............................  Gigawatt Hour.
IEEE..............................  Institute of Electrical and
                                     Electronics Engineers.
IROL..............................  Interconnection Reliability
                                     Operating Limits.
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..............................  Under Frequency Load Shedding.
UVLS..............................  Under Voltage Load Shedding.
------------------------------------------------------------------------

                     Appendix D.--High Priority List
------------------------------------------------------------------------
       Reliability standard                         Title
------------------------------------------------------------------------
COM-001-0.........................  Telecommunications.
COM-002-1.........................  Communications and Coordination.
EOP-002-0.........................  Capacity and Energy Emergency.
EOP-003-0.........................  Load Shedding Plans.
EOP-008-0.........................  Plans for Loss of Control Center
                                     Functionality.
FAC-003-1.........................  Vegetation Management Program.
FAC-008-1.........................  Facility Ratings Methodology.
IRO-003-1.........................  Reliability Coordination--Wide Area
                                     View.
IRO-006-3.........................  Reliability Coordination--
                                     Transmission Loading Relief.
PER-002-0.........................  Operating Personnel Training.
PER-003-0.........................  Operating Personnel Credentials.
PER-004-0.........................  Reliability Coordination--Staffing.
PRC-006-0.........................  Development and Documentation of
                                     Regional UFLS Programs.
PRC-020-1.........................  Under-Voltage Load Shedding Program
                                     Database.
TOP-006-0.........................  Monitoring System Conditions.
VAR-001-1.........................  Voltage and Reactive Control.
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[FR Doc. 06-8927 Filed 11-2-06; 8:45 am]

BILLING CODE 6717-01-P