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Rule

Mandatory Reliability Standards for the Bulk-Power System

Action

Final Rule.

Summary

Pursuant to section 215 of the Federal Power Act (FPA), the Commission approves 83 of 107 proposed Reliability Standards, six of the eight proposed regional differences, and the Glossary of Terms Used in Reliability Standards developed by the North American Electric Reliability Corporation (NERC), which the Commission has certified as the Electric Reliability Organization (ERO) responsible for developing and enforcing mandatory Reliability Standards. Those Reliability Standards meet the requirements of section 215 of the FPA and Part 39 of the Commission's regulations. However, although we believe it is in the public interest to make these Reliability Standards mandatory and enforceable, we also find that much work remains to be done. Specifically, we believe that many of these Reliability Standards require significant improvement to address, among other things, the recommendations of the Blackout Report. Therefore, pursuant to section 215(d)(5), we require the ERO to submit significant improvements to 56 of the 83 Reliability Standards that are being approved as mandatory and enforceable. The remaining 24 Reliability Standards will remain pending at the Commission until further information is provided.

The Final Rule adds a new part to the Commission's regulations, which states that this part applies to all users, owners and operators of the Bulk-Power System within the United States (other than Alaska or Hawaii) and requires that each Reliability Standard identify the subset of users, owners and operators to which that particular Reliability Standard applies. The new regulations also require that each Reliability Standard that is approved by the Commission will be maintained on the ERO's Internet Web site for public inspection.

 

Table of Contents Back to Top

Tables Back to Top

EFFECTIVE DATE: Back to Top

This rule will become effective June 4, 2007.

FOR FURTHER INFORMATION CONTACT: Back to Top

Jonathan First (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8529.

Paul Silverman (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8683.

Robert Snow (Technical Information), Office of Energy Markets and Reliability, Division of Reliability, Federal Energy Regulatory Commission, 888 First Street, NE.,Washington, DC 20426, (202) 502-6716.

Kumar Agarwal (Technical Information), Office of Energy Markets and Reliability, Division of Policy Analysis and Rulemaking, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8923.

SUPPLEMENTARY INFORMATION: Back to Top

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

Table of Contents Back to Top
Paragraph
I. Introduction 1
A. Background 3
1. EPAct 2005 and Order No. 672 3
2. NERC Petition for Approval of Reliability Standards 12
3. Staff Preliminary Assessment and Commission NOPR 15
4. Notice of Proposed Rulemaking 17
II. Discussion 21
A. Overview 21
1. The Commission's Underlying Approach to Review and Disposition of the Proposed Standards 21
2. Mandates of Section 215 of the FPA 23
3. Balancing the Need for Practicality with the Mandates of Section 215 and Order No. 672 29
B. Discussion of the Commission's New Regulations 34
1. Applicability 34
2. Mandatory Reliability Standards 40
3. Availability of Reliability Standards 44
C. Applicability Issues 50
1. Bulk-Power System v. Bulk Electric System 50
2. Applicability to Small Entities 80
3. Definition of User of the Bulk-Power System 110
4. Use of the NERC Functional Model 117
5. Regional Reliability Organizations 146
D. Mandatory Reliability Standards 161
1. Legal Standard for Approval of Reliability Standards 161
2. Commission Options When Acting on a Reliability Standard 169
3. Prioritizing Modifications to Reliability Standards 193
4. Trial Period 208
5. International Coordination 226
E. Common Issues Pertaining to Reliability Standards 234
1. Blackout Report Recommendation on Liability Limitations 234
2. Measures and Levels of Non-Compliance 238
3. Ambiguities and Potential Multiple Interpretations 264
4. Technical Adequacy 282
5. Fill-in-the-Blank Standards 287
F. Discussion of Each Individual Reliability Standard 304
1. BAL: Resource and Demand Balancing 305
2. CIP: Critical Infrastructure Protection 446
3. COM: Communications 473
4. EOP: Emergency Preparedness and Operations 542
5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities 678
6. INT: Interchange Scheduling and Coordination 796
7. IRO: Interconnection Reliability Operations and Coordination 889
8. MOD: Modeling, Data, and Analysis 1007
9. PER: Personnel Performance, Training and Qualifications 1325
10. PRC: Protection and Control 1419
11. TOP: Transmission Operations 1568
12. TPL: Transmission Planning 1684
13. VAR: Voltage and Reactive Control 1847
14. Glossary of Terms Used in Reliability Standards 1887
III. Information Collection Statement 1900
IV. Environmental Analysis 1909
V. Regulatory Flexibility Act 1910
VI. Document Availability 1947
VII. Effective Date and Congressional Notification 1950
Appendix A: Disposition of Reliability Standards, Glossary and Regional Differences  
Appendix B: Commenters on the Notice of Proposed Rulemaking  
Appendix C: Abbreviations in this Document  

I. Introduction Back to Top

1. Pursuant to section 215 of the Federal Power Act (FPA), the Commission approves 83 of 107 proposed Reliability Standards, six of the eight proposed regional differences, and the Glossary of Terms Used in Reliability Standards (glossary) developed by the North American Electric Reliability Corporation (NERC), which the Commission has certified as the Electric Reliability Organization (ERO) responsible for developing and enforcing mandatory Reliability Standards. Those Reliability Standards meet the requirements of section 215 of the FPA and Part 39 of the Commission's regulations. However, although we believe it is in the public interest to make these Reliability Standards mandatory and enforceable, we also find that much work remains to be done. Specifically, we believe that many of these Reliability Standards require significant improvement to address, among other things, the recommendations of the Blackout Report. [1] Therefore, pursuant to section 215(d)(5), we require the ERO to submit significant improvements to 56 of the 83 Reliability Standards that are being approved as mandatory and enforceable. The remaining 24 Reliability Standards will remain pending at the Commission until further information is provided.

2. The Final Rule adds a new part to the Commission's regulations, which states that this part applies to all users, owners and operators of the Bulk-Power System within the United States (other than Alaska or Hawaii) and requires that each Reliability Standard identify the subset of users, owners and operators to which that particular Reliability Standard applies. The new regulations also require that each Reliability Standard that is approved by the Commission will be maintained on the ERO's Internet Web site for public inspection.

A. Background

1. EPAct 2005 and Order No. 672

3. On August 8, 2005, the Electricity Modernization Act of 2005, which is Title XII, Subtitle A, of the Energy Policy Act of 2005 (EPAct 2005), was enacted into law. [2] EPAct 2005 adds a new section 215 to the FPA, which requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards, which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO, subject to Commission oversight or the Commission can independently enforce Reliability Standards. [3]

4. On February 3, 2006, the Commission issued Order No. 672, implementing section 215 of the FPA. [4] Pursuant to Order No. 672, the Commission certified one organization, NERC, as the ERO. [5] The ERO is required to develop Reliability Standards, which are subject to Commission review and approval. [6] The Reliability Standards will apply to users, owners and operators of the Bulk-Power System, as set forth in each Reliability Standard.

5. Section 215(d)(2) of the FPA and the Commission's regulations provide that the Commission may approve a proposed Reliability Standard if it determines that the proposal is just, reasonable, not unduly discriminatory or preferential, and in the public interest. The Commission specified in Order No. 672 certain general factors it would consider when assessing whether a particular Reliability Standard is just and reasonable. [7] According to this guidance, a Reliability Standard must provide for the Reliable Operation of Bulk-Power System facilities and may impose a requirement on any user, owner or operator of such facilities. It must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal. The Reliability Standard should be clear and unambiguous regarding what is required and who is required to comply. The possible consequences for violating a Reliability Standard should be clear and understandable to those who must comply. There should be clear criteria for whether an entity is in compliance with a Reliability Standard. While a Reliability Standard does not necessarily need to reflect the optimal method for achieving its reliability goal, a Reliability Standard should achieve its reliability goal effectively and efficiently. A Reliability Standard must do more than simply reflect stakeholder agreement or consensus around the “lowest common denominator.” It is important that the Reliability Standards developed through any consensus process be sufficient to adequately protect Bulk-Power System reliability. [8]

6. A Reliability Standard may take into account the size of the entity that must comply and the costs of implementation. A Reliability Standard should be a single standard that applies across the North American Bulk-Power System to the maximum extent this is achievable taking into account physical differences in grid characteristics and regional Reliability Standards that result in more stringent practices. It can also account for regional variations in the organizational and corporate structures of transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations in market design if these affect the proposed Reliability Standard. Finally, a Reliability Standard should have no undue negative effect on competition. [9]

7. Order No. 672 directs the ERO to explain how the factors the Commission identified are satisfied and how the ERO balances any conflicting factors when seeking approval of a proposed Reliability Standard. [10]

8. Pursuant to section 215(d)(2) of the FPA and § 39.5(c) of the Commission's regulations, the Commission will give due weight to the technical expertise of the ERO with respect to the content of a Reliability Standard or to a Regional Entity organized on an Interconnection-wide basis with respect to a proposed Reliability Standard or a proposed modification to a Reliability Standard to be applicable within that Interconnection. However, the Commission will not defer to the ERO or to such a Regional Entity with respect to the effect of a proposed Reliability Standard or proposed modification to a Reliability Standard on competition. [11]

9. The Commission's regulations require the ERO to file with the Commission each new or modified Reliability Standard that it proposes to be made effective under section 215 of the FPA. The filing must include a concise statement of the basis and purpose of the proposed Reliability Standard, a summary of the Reliability Standard development proceedings conducted by either the ERO or Regional Entity, together with a summary of the ERO's Reliability Standard review proceedings, and a demonstration that the proposed Reliability Standard is just, reasonable, not unduly discriminatory or preferential and in the public interest. [12]

10. Where a Reliability Standard requires significant improvement, but is otherwise enforceable, the Commission approves the Reliability Standard. In addition, as a distinct action under the statute, the Commission directs the ERO to modify such a Reliability Standard, pursuant to section 215(d)(5) of the FPA, to address the identified issues or concerns. This approach will allow the proposed Reliability Standard to be enforceable while the ERO develops any required modifications.

11. The Commission will remand to the ERO for further consideration a proposed new or modified Reliability Standard that the Commission disapproves in whole or in part. [13] When remanding a Reliability Standard to the ERO, the Commission may order a deadline by which the ERO must submit a proposed or modified Reliability Standard.

2. NERC Petition for Approval of Reliability Standards

12. On April 4, 2006, as modified on August 28, 2006, NERC submitted to the Commission a petition seeking approval of the 107 proposed Reliability Standards that are the subject of this Final Rule. [14] According to NERC, the 107 proposed Reliability Standards collectively define overall acceptable performance with regard to operation, planning and design of the North American Bulk-Power System. Seven of these Reliability Standards specifically incorporate one or more “regional differences” (which can include an exemption from a Reliability Standard) for a particular region or subregion, resulting in eight regional differences. NERC stated that it simultaneously filed the proposed Reliability Standards with governmental authorities in Canada. The Commission addresses these proposed Reliability Standards in this rulemaking proceeding. [15]

13. On November 15, 2006, NERC filed 20 revised proposed Reliability Standards and three new proposed Reliability Standards for Commission approval. The 20 revised Reliability Standards primarily provided additional Measures and Levels of Non-Compliance, but did not add or revise any existing Requirements to these Reliability Standards. NERC requested that the 20 revised proposed Reliability Standards be included as part of the Final Rule issued by the Commission in this docket. The proposed new Reliability Standards, FAC-010-1, FAC-011-1, and FAC-014-1, will be addressed in a separate rulemaking proceeding in Docket No. RM07-3-000.

14. On December 1, 2006, NERC submitted in Docket No. RM06-16-000 an informational filing entitled “NERC's Reliability Standards Development Plan: 2007—2009” (Work Plan). NERC stated it was submitting the Work Plan to inform the Commission of NERC's program to improve the Reliability Standards that currently are the subject of the Commission's rulemaking proceeding.

3. Staff Preliminary Assessment and Commission NOPR

15. On May 11, 2006, Commission staff issued a “Staff Preliminary Assessment of the North American Electric Reliability Council's Proposed Mandatory Reliability Standards” (Staff Preliminary Assessment). The Staff Preliminary Assessment identifies staff's observations and concerns regarding NERC's then-current voluntary Reliability Standards. The Staff Preliminary Assessment describes issues common to a number of proposed Reliability Standards. It reviews and identifies issues regarding each individual Reliability Standard but did not make specific recommendations regarding the appropriate Commission action on a particular proposal.

16. Comments on the Staff Preliminary Assessment were due by June 26, 2006. Approximately 50 entities filed comments in response to the Staff Preliminary Assessment. In addition, on July 6, 2006, the Commission held a technical conference to discuss NERC's proposed Reliability Standards, the Staff Preliminary Assessment, the comments and other related issues.

4. Notice of Proposed Rulemaking

17. The Commission issued the NOPR on October 20, 2006, and required that comments be filed within 60 days after publication in the Federal Register, or January 2, 2007. [16] The Commission granted the request of several commenters to extend the comment date to January 3, 2007. Several late-filed comments were filed. The Commission will accept these late-filed comments. A list of commenters appears in Appendix A.

18. On November 27, 2006, the Commission issued a notice on the 20 revised Reliability Standards filed by NERC on November 15, 2006. In the notice, the Commission explained that, because of their close relationship with Reliability Standards dealt with in the October 20, 2006 NOPR, the Commission would address these 20 revised Reliability Standards in this proceeding. [17] The notice provided an opportunity to comment on the revised Reliability Standards, with a comment due date of January 3, 2007.

19. The Commission issued a notice on NERC's Work Plan on December 8, 2006. While the Commission sought public comment on NERC's filing because it was informative on the prioritization of modifying Reliability Standards raised in the NOPR, the notice emphasized that the Work Plan was filed for informational purposes and NERC stated that it is not requesting Commission action on the Work Plan.

20. On February 6, 2007, NERC submitted a request for leave to file supplemental information, and included a revised version of the NERC Statement of Compliance Registry Criteria (Revision 3). NERC noted that it had submitted with its NOPR comments an earlier version of the same document. [18]

II. Discussion Back to Top

A. Overview

1. The Commission's Underlying Approach To Review and Disposition of the Proposed Standards

21. In this Final Rule, the Commission takes the important step of approving the first set of mandatory and enforceable Reliability Standards within the United States in accordance with the provisions of new section 215 of the FPA. The Commission's action herein marks the official departure from reliance on the electric utility industry's voluntary compliance with Reliability Standards adopted by NERC and the regional reliability councils and the transition to the mandatory, enforceable Reliability Standards under the Commission's ultimate oversight through the ERO and, eventually, the Regional Entities, as directed by Congress. As we discuss more fully below, in deciding whether to approve, approve and direct modifications, or remand each of the proposed Reliability Standards in this Final Rule, our overall approach has been one of carefully balancing the need for practicality during the time of transition with the imperatives of section 215 of the FPA and Order No. 672, and other considerations.

22. In addition, our action today is informed by the August 14, 2003 blackout which affected significant portions of the Midwest and Northeast United States and Ontario, Canada and impacted an estimated 50 million people and 61,800 megawatts of electric load. As noted in the NOPR, a joint United States-Canada task force found that the blackout was caused by several entities violating NERC's then-effective policies and Reliability Standards. [19] Those violations directly contributed to the loss of a significant amount of electric load. The joint task force identified both the need for legislation to make Reliability Standards mandatory and enforceable with penalties for noncompliance, as well as particular Reliability Standards that needed corrections to make them more effective in preventing blackouts. Indeed, the August 2003 blackout and the recommendations of the joint task force helped foster enactment of EPAct 2005 and new section 215 of the FPA.

2. Mandates of Section 215 of the FPA

23. The imperatives of section 215 of the FPA address not only the protection of the reliability of the Bulk-Power System but also the reliability roles of the Commission, the ERO, the Regional Entities, and the owners, users and operators of the Bulk-Power System. [20] First, section 215 specifies that the ERO is to develop and enforce a comprehensive set of Reliability Standards subject to Commission review. Section 215 explains that a Reliability Standard is a requirement approved by the Commission that is intended to provide for the Reliable Operation of the Bulk-Power System. Such requirement may pertain to the operation of existing Bulk-Power System facilities, including cybersecurity protection, or it may pertain to the design of planned additions or modifications to such facilities to the extent necessary to provide for reliable operation of the Bulk-Power System. [21]

24. Second, the reliability mandate of section 215 of the FPA addresses not only the comprehensive maintenance of the reliable operation of each of the elements of the Bulk-Power System, it also contemplates the prevention of incidents, acts and events that would interfere with the reliable operation of the Bulk-Power System. Further, section 215 seeks to prevent an instability, an uncontrolled separation or a cascading failure, whether resulting from either a sudden disturbance, including a cybersecurity incident, or an unanticipated failure of the system elements. In order to avoid these outcomes, the various elements and components of the Bulk-Power System are to be operated within equipment and electric system thermal, voltage and stability limits. [22]

25. Third, section 215 of the FPA explains that the Bulk-Power System broadly encompasses both the facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) as well as the electric energy from generation facilities needed to maintain transmission system reliability. [23] Further, section 215 explains that the interconnected transmission network within an Interconnection is a geographic area in which the operation of Bulk-Power System components is synchronized such that the failure of one such component, or more than one such component, may adversely affect the ability of the operators of other components within the system to maintain reliable operation of the facilities within their control. [24] A Cybersecurity Incident is explained to be a malicious act that disrupts or attempts to disrupt the operation of programmable electronic devices and communication networks including hardware, software or data that are essential to the reliable operation of the Bulk-Power System. [25]

26. Next, as to the reliability roles of the Commission and others, section 215 of the FPA explains that the ERO must file each of its Reliability Standards and any modification thereto with the Commission. [26] The Commission will consider a number of factors before taking any action with respect thereto. We may approve the Reliability Standard or its modification only if we determine that it is just, reasonable, and not unduly discriminatory or preferential and in the public interest to do so. Also, in doing so, we are instructed to give due weight to the technical expertise of the ERO concerning the content of a proposed standard or a modification thereto. We must also give due weight to an Interconnection-wide Regional Entity with respect to a proposed Reliability Standard to be applicable within that Interconnection, except for matters concerning the effect on competition. [27]

27. Similarly, in considering whether to forward a proposed Reliability Standard to the Commission for approval, the ERO must rebuttably presume that a proposal from a Regional Entity organized on an Interconnection-wide basis for a Reliability Standard or modification to a Reliability Standard to be applicable on an Interconnection-wide basis is just, reasonable, and not unduly discriminatory or preferential, and in the public interest. [28] The Commission may also give deference to the advice of a Regional Advisory Body organized on an Interconnection-wide basis in regard to whether a proposed Reliability Standard is just, reasonable and not unduly discriminatory or preferential and in the public interest, as it may apply within the region. [29]

28. Finally, the Commission is further instructed to remand to the ERO for further consideration any standard or modification that it does not approve in whole or part. [30] We may also direct the ERO to submit a proposed Reliability Standard or modification that addresses a specific problem if we consider this course of action to be appropriate. [31] Further, if we find that a conflict exists between a Reliability Standard and any function, rule, order, tariff, rate schedule, or agreement accepted, approved, or ordered by the Commission applicable to a transmission organization, [32] and if we determine that the Reliability Standard needs to be changed as a result of such a conflict, we must order the ERO to develop and file with the Commission a modified Reliability Standard for this purpose. [33]

3. Balancing the Need for Practicality With the Mandates of Section 215 and Order No. 672

29. In enacting section 215, Congress chose to expand the Commission's jurisdiction beyond our historical role as primarily an economic regulator of the public utility industry under Part II of the FPA. Many entities not previously touched by our economic regulatory oversight are within our reliability purview and these entities will have to familiarize themselves not only with the new reliability obligations under section 215 of the FPA and the Reliability Standards that we are approving in this Final Rule, but also any proposed Reliability Standards or improvements that may implicate them that are under development by the ERO and the Regional Entities. [34] We have taken these and other considerations into account and have tried to reach an appropriate balance among them.

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

31. We emphasize that we are not, at this time, mandating a particular outcome by way of these directives, but we do expect the ERO to respond with an equivalent alternative and adequate support that fully explains how the alternative produces a result that is as effective as or more effective that the Commission's example or directive.

32. We have sought to provide enough specificity to focus the efforts of the ERO and others adequately. We are also sensitive to the concern of the Canadian Federal Provincial Territorial Working Group (FPT) about the status of an existing standard that is already being followed on a voluntary basis. The FPT suggests, for example, that instead of remanding an existing Reliability Standard, the Commission should conditionally approve the standard pending its modification. [36] We believe the action we take today is similar in many respects to this approach.

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

B. Discussion of the Commission's New Regulations

1. Applicability

34. In the NOPR, the Commission proposed to add § 40.1(a) to the regulations. The Commission proposed that § 40.1(a) would provide that this Part applies to all users, owners and operators of the Bulk-Power System within the United States (other than Alaska and Hawaii) including, but not limited to, the entities described in section 201(f) of the FPA. This statement is consistent with section 215(b) of the FPA and § 39.2 of the Commission's regulations.

35. The Commission further proposed to add § 40.1(b), which would require each Reliability Standard made effective under this Part to identify the subset of users, owners and operators to whom that particular Reliability Standard applies.

a. Comments

36. NERC agrees with the Commission's proposal to add the text of § 40.1(b) to its regulations to require that each Reliability Standard identify the subset of users, owners and operators to which that particular Reliability Standard applies and believes this requirement is currently established in NERC's Rules of Procedure.

37. TANC supports proposed § 40.1. It states that requiring each Reliability Standard to identify the subset of users, owners and operators to whom it applies, thereby limiting the scope of the broad phrase “users, owners and operators,” is a critical step to removing ambiguities from the Reliability Standards. According to TANC, the proposed text of § 40.1 would eliminate ambiguities with regard to the entity responsible for complying with each Reliability Standard. In this way, Regional Entities and other interested parties will be allowed to weigh in during the Reliability Standards development process on the breadth of each standard and may urge NERC to accept any necessary regional variations that are necessary to maintain adequate reliability within the region.

38. APPA believes that the Commission's proposal to add § 40.1 and 40.2 to its regulations is generally appropriate and acceptable, but the regulatory language should be amended to make clear the exact universe of users, owners and operators of the Bulk-Power System to which the mandatory Reliability Standards apply. It recommends that the regulations provide that determinations as to applicability of standards to particular entities shall be resolved by reference to the NERC compliance registry.

b. Commission Determination

39. The Commission adopts the NOPR's proposal to add § 40.1 to the Commission's regulations. The Commission disagrees with APPA's suggestion to define here the exact universe of users, owners and operators of the Bulk-Power System to which the mandatory Reliability Standards apply. Rather, consistent with NERC's existing approach, we believe that it is appropriate that each Reliability Standard clearly identify the subset of users, owners and operators to which it applies and the Commission determines applicability on that basis. As we discuss later, we approve NERC's current compliance registry to provide certainty and stability in identifying which entities must comply with particular Reliability Standards.

2. Mandatory Reliability Standards

40. The Commission proposed to add § 40.2(a) to the Commission's regulations. The proposed regulation text would require that each applicable user, owner and operator of the Bulk-Power System comply with Commission-approved Reliability Standards developed by the ERO, and would provide that the Commission-approved Reliability Standards can be obtained from the Commission's Public Reference Room at 888 First Street, NE., Room 2A, Washington, DC 20426.

41. The Commission further proposed to add § 40.2(b) to its regulations, providing that a modification to a Reliability Standard proposed to become effective pursuant to § 39.5 shall not be effective until approved by the Commission.

a. Comments

42. NERC concurs with the Commission's proposal to require NERC to provide to the Commission a copy of all approved Reliability Standards for posting in its Public Reference Room. NERC agrees with the Commission that neither the text nor the title of an approved Reliability Standard should be codified in the Commission's regulations.

b. Commission Determination

43. For the reasons discussed in the NOPR, the Commission generally adopts the NOPR's proposal to add § 40.2 to the Commission's regulations. [37] However, after consideration, the Commission has determined that it is not necessary to have the approved Reliability Standards on file in the Commission's public reference room and on the NERC Web site. Therefore, we will require that all Commission-approved Reliability Standards be available on the ERO's Web site, with an effective date, and revise § 40.2(b) to remove the following language: “Which can be obtained from the Commission's Public Reference Room at 888 First Street, NE., Room 2A, Washington, DC, 20426.” Further, to be consistent with Part 39 of our regulations, we remove the reference to NERC and replace it with “Electric Reliability Organization.”

3. Availability of Reliability Standards

44. The Commission proposed to add § 40.3 to the regulation text, which requires that the ERO maintain in electronic format that is accessible from the Internet the complete set of effective Reliability Standards that have been developed by the ERO and approved by the Commission. The Commission stated that it believes that ready access to an electronic version of the effective Reliability Standards will enhance transparency and help avoid confusion as to which Reliability Standards are mandatory and enforceable. We noted that NERC currently maintains the existing, voluntary Reliability Standards on the NERC Web site.

45. While the NOPR discusses each Reliability Standard and identifies the Commission's proposed disposition for each Reliability Standard, we did not propose to codify either the text or the title of an approved Reliability Standard in the Commission's regulations. Rather, we proposed that each user, owner or operator of the Bulk-Power System must comply with applicable Commission-approved Reliability Standards that are available in the Commission's Public Reference Room and on the Internet at the ERO's Web site. We stated that this approach is consistent with the statutory options of approving a proposed Reliability Standard or modification to a Reliability Standard “by rule or order.” [38]

a. Comments

46. NERC states that it can successfully implement the Commission's proposal to require NERC to maintain in electronic format that is accessible from the Internet the complete set of Reliability Standards that have been developed by the ERO and approved by the Commission. NERC currently maintains a public Web site displaying the existing, voluntary Reliability Standards for access by users, owners and operators of the Bulk-Power System. Once the proposed Reliability Standards are approved by the Commission, NERC will modify its Web site to distinguish which Reliability Standards have been approved by the Commission for enforcement in the United States.

47. EEI states that the approval of Reliability Standards should be through a rulemaking rather than an order, except in very rare circumstances, because of the open nature of the rulemaking process. Where the Commission decides to proceed by order, EEI states that the Commission should give notice and an opportunity to comment on any proposed Reliability Standards.

b. Commission Determination

48. For the reasons discussed in the NOPR, the Commission adopts the NOPR's proposal to add § 40.3 to the Commission's regulations; however the Commission has further clarified the proposed regulatory text. [39] We clarify that the ERO must post on its Web site the currently effective Reliability Standards as approved and enforceable by the Commission. Further, we require the effective date of the Reliability Standards must be included in the posting.

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

C. Applicability Issues

1. Bulk-Power System v. Bulk Electric System

50. The NOPR observed that, for purposes of section 215, “Bulk-Power System” means:

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

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

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

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

53. The Commission solicited comment on its interpretation and whether the Regional Entities should, in the future, play a role in either defining the facilities that are subject to a Reliability Standard or be allowed to determine an exception on a case-by-case basis.

54. Further, the NOPR explained that continued reliance on multiple regional interpretations of the NERC definition of bulk electric system, which omits significant portions of the transmission system component of the Bulk-Power System that serve critical load centers, is not appropriate. Thus, the NOPR proposed that, in the long run, NERC revise the current definition of bulk electric system to ensure that all facilities, control systems and electric energy from generation resources that impact system reliability are included within the scope of applicability of Reliability Standards, and that NERC's revision is consistent with the statutory term Bulk-Power System.

a. Comments

55. Most commenters, including NERC, NARUC, APPA, National Grid, EEI and Ontario IESO, believe that the Commission should only impose Reliability Standards on those entities that fall under NERC's definition of bulk electric system as it existed under the voluntary regime. They state that, by extending the definition of bulk electric system, the Commission goes beyond what is necessary to protect Bulk-Power System reliability, creates uncertainty and will divert resources from monitoring compliance of those entities that could have a material impact on Bulk-Power System reliability.

56. Entergy, however, agrees with the Commission that NERC's definition of bulk electric system is not adequate and agrees with the Commission's proposed interpretation. ISO-NE does not oppose the NOPR's approach on how to interpret the term “Bulk-Power System,” but it states that this broader scope justifies a delay in the date civil penalties take effect, to January 1, 2008, to provide the industry sufficient time to review the Commission's Final Rule and to adjust to the expanded reach of the Reliability Standards.

57. NERC, APPA and NRECA maintain that there was no intentional distinction made by Congress between “Bulk-Power System” (as defined in section 215) and the “bulk electric system” (as defined by the NERC glossary). NERC asserts that recent discussions with stakeholders confirm NERC's belief that there was no distinction intended. Moreover, NERC is not aware of any documentation that suggests a distinction was intended. NRECA argues that legislative intent and prior usage do not support the Commission's approach to defining the Bulk-Power System. NRECA concedes that no conference committee report accompanied EPAct 2005, but it notes that the Congressional Research Service specifies in its manual on statutory interpretation that “[W]here Congress borrows terms of art in which are accumulated the legal tradition and meaning of centuries of practice, it presumably knows and adopts the cluster of ideas that were attached to each borrowed word in the body of learning from which it was taken.” [44]

58. TAPS states that the Commission cannot lawfully “interpret” the bulk electric system definition contrary to its terms. According to TAPS, the Commission cannot include facilities below 100 kV “that could limit or supplement the operation of the higher voltage transmission systems,” in the bulk electric system, even if they are “necessary for operating” the bulk system, because these facilities are not included in NERC's definition of bulk electric system.

59. NERC states that the Commission's proposal that NERC's “bulk electric system” should apply to all of the equal to or greater than 100 kV transmission systems and any underlying transmission system (less than 100 kV) that could limit or supplement the operation of the higher voltage transmission systems is a significant expansion over what the industry has historically regarded as the bulk electric system, both in terms of the facilities covered and the entities involved. While NERC agrees with the Commission that Congress intended to give the Commission broad jurisdiction over the reliability of the Bulk-Power System, it does not believe this is the right time for the Commission to define the full extent of its jurisdiction or that the approach proposed in the NOPR is the right way to do so. In addition, NERC does not believe it is legally necessary for the Commission to extend its jurisdiction to the limits in a single step.

60. NERC states that the Commission should make clear in this Final Rule that its jurisdiction is at least as broad as the historic NERC definition of “bulk electric system” and that the Commission will use that definition for the near term. NERC asserts that the Commission should also make clear that it is not deciding in this docket the full scope of its jurisdiction and is reserving its right to consider a broader definition. Instead, NERC states that the Commission should focus on approving an initial set of Reliability Standards for the core set of users, owners and operators that have the most significant impact on the reliability of the Bulk-Power System. NERC maintains that this core set has been defined through its use of the terms “bulk electric system” and “responsible entities” provided in the NERC Glossary, the “Applicability” section of each Reliability Standard and substantive requirements of the standards themselves, and NERC's registration of specific entities that are responsible for compliance with the Reliability Standards.

61. NRECA argues that the definition of “Bulk-Power System” contained in section 215(a)(1) reflects Congressional intent to codify the established materiality component because Congress limited the definition of Bulk-Power System to facilities and control systems necessary for operating an interconnected electric energy transmission network and electric energy from generation facilities needed to maintain transmission system reliability. NRECA argues that these limiting terms mean that not all transmission facilities are included. In NRECA's view, the definition of the Bulk-Power System within the meaning of section 215 cannot extend to radial facilities to “significant local distribution systems,” “load centers,” or local transmission facilities unless otherwise “necessary for” (i.e., material to) the reliable operation of the interconnected grid. Further, NRECA states that the definition of “Reliable Operation” in section 215(a) focuses on the reliable operation of the Bulk-Power System and not the protection of local load per se.

62. Certain commenters assert that expanding the scope of the Commission's jurisdiction and the scope of the Reliability Standards in this proceeding would be an unanticipated expansion of the reach of the existing Reliability Standards implemented with insufficient due process and may cause jurisdictional concerns. [45] They state that the Reliability Standards under consideration were developed and approved through NERC's Reliability Standards development process with the intention that they would apply based on the industry's historical conception of the bulk electric system and that the outcome might have been different using the Commission's proposed definition. NERC therefore argues that it would be inappropriate to assume that the requirements of the existing Reliability Standards would be relevant to an expanded set of entities or an expanded scope of facilities under a broader definition of the Bulk-Power System. NERC also asserts that there is no reasonable justification for subjecting “thousands of small entities” to the costs of compliance with the Reliability Standards when there is no reasonable justification to do so in terms of incremental benefit to the reliability of the Bulk-Power System.

63. NRECA, APPA and others argue that the Commission's interpretation would undermine, rather than promote, reliability. According to these commenters, the Commission's interpretation would require new definitions, such as one for “load center,” and otherwise creates confusion. For example, Small Entities Forum states that it is concerned with the inclusion of “transmission connecting generation that supplies electric energy to the system” because that could include any transmission connected to any generation of any size.

64. APPA objects to the Commission's statement that “[t]he transmission system component of the Bulk-Power System is understood to provide for the movement of power in bulk to points of distribution for allocation to retail electricity customers.” APPA states that it does not believe there is an industry “understanding” that the bulk electric system or the Bulk-Power System necessarily encompass all transmission facilities that connect major generation stations to distribution systems or that there is a bright line between transmission and distribution facilities. APPA interprets these terms as describing the backbone facilities that integrate regional transmission networks.

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

66. AMP-Ohio supports NERC's proposal to include any additional entities or facilities that it believes could have a detrimental effect on the reliability of the bulk electric system on a case-by-case basis over time. Further, Ontario IESO suggests that if the Commission believes that NERC's definition of bulk electric system excludes facilities that should be subject to Reliability Standards for reasons other than preventing cascading outages, the Commission could submit a detailed request through the ERO Reliability Standards development process.

67. NERC and EEI believe that, in the long run, NERC should be directed to develop, through its Reliability Standards development process, a single process to identify the specific elements of the Bulk-Power System that must comply with Reliability Standards under section 215. According to NERC, the Commission, the states, and all other stakeholders would benefit tremendously from a deliberate dialogue on these matters. NERC asks that the Commission not directly define the outer limits of its jurisdiction under section 215, but requests that the Commission direct NERC to undertake certain activities to reconcile the definitions of bulk electric system and Bulk-Power System and report the results back to the Commission.

68. Similarly, TAPS, APPA, Duke and MidAmerican state that, if there is a problem with NERC's current definition of the bulk electric system, the Commission should require NERC to revisit it using the ANSI process to give “due weight” to NERC's technical expertise. AMP-Ohio, TANC, Georgia Operators and Entergy state that Regional Entities should play a primary role in defining the facilities that are subject to a Reliability Standard because the Regional Entities will have more detailed system knowledge in their regions than NERC or the Commission.

69. The Connecticut Attorney General, the Connecticut DPUC and the New England Conference of Public Utilities Commissioners maintain that NERC's definition of the “bulk electric system” exceeds the Commission's jurisdiction by including generation that is not needed to maintain transmission system reliability and therefore intrudes into state jurisdiction over generation resource adequacy matters and is unlawful. According to Connecticut DPUC, section 215(a)(1) of the FPA excludes from federal regulation (1) facilities that are used in local distribution, (2) facilities and control systems that are not necessary for operating an interconnected electric energy transmission network or part of a network and (3) electric energy from generating facilities not needed to maintain transmission system reliability. Connecticut DPUC maintains that, in contrast, NERC's definition replaces the FPA definition with criteria based on voltage thresholds for transmission facilities and electric energy from generating facilities. According to Connecticut DPUC, NERC's definition does not comply with section 215(a)(1) because it includes facilities and equipment that are neither “necessary” for operation of the transmission network nor “needed” to maintain transmission system reliability. The Connecticut Attorney General and Connecticut DPUC, therefore, urge the Commission to reject this definition.

70. Further, in Connecticut DPUC's view, because the Commission cannot adopt NERC's definition of bulk electric system, it cannot expand the boundaries of its jurisdiction farther than the bulk electric system. It maintains that Congress did not give the Commission jurisdiction to mandate and enforce all Reliability Standards, especially those related to the long-term adequacy of generation resources; therefore, the Commission may not delegate to an ERO authority that it does not have. APPA also states that the Commission expanded the definition of the bulk electric system so that it may affect facilities subject to state reliability jurisdiction, such as low-voltage transmission systems that affect only the local areas served by those facilities, which do not cause cascading outages, without explaining why it is necessary to federalize reliability responsibility for outages on these facilities.

71. NARUC and New York Commission maintain that the Commission's proposed interpretation of what facilities constitute the Bulk-Power System is inconsistent with section 215 of the FPA. They state that the ability of a facility to “limit or supplement” the transmission system does not automatically mean that a facility is necessary for operating an interconnected transmission system, as required by the FPA, or for maintaining system reliability. According to NARUC, Congress only authorized the Commission to approve Reliability Standards necessary for operating an interconnected electric energy transmission network. Although the NOPR interpretation includes these underlying facilities, it also covers others that are not required to operate an interconnected transmission network.

72. Moreover, NARUC and New York Commission state that the NOPR proposal to define Bulk-Power System as all facilities operating at or above 100 kV exceeds the Commission's jurisdiction. According to NARUC and New York Commission, there is generally a layer of “area” transmission facilities below the “Bulk-Power System” and above distribution facilities that move energy within a service territory and toward load centers. However, NARUC and New York Commission claim that only a small subset of these underlying facilities assists in maintaining the reliability of the Bulk-Power System.

73. Several commenters, including New York Commission, NYSRC, Massachusetts DTE, NPCC, TANC and Ontario IESO, support a functional, impact-based approach to applying Reliability Standards. According to NPCC, neither NERC nor section 215 of the FPA provide a rigorous approach to determining which elements play a role in maintaining reliability of the bulk electric system. These commenters generally state that an impact-based approach would define those elements necessary for Reliable Operation and ensure that compliance and enforcement efforts concentrate on those facilities that materially affect the Reliable Operation of the interconnected Bulk-Power System, while at the same time balancing the costs imposed by mandatory Reliability Standards with the reliability improvement realized on the interconnected Bulk-Power System.

74. Ontario IESO maintains that reliability impact is a process of assessing facilities to determine if, due to recognized contingencies and other test criteria, they represent a significant adverse impact beyond a local area. This assessment will be the basis of a consistent test methodology the ERO must develop to define the facilities included within the overall Bulk-Power System to which a Reliability Standard would apply. Ontario IESO states that the Commission should direct the ERO to take the lead in developing the impact assessment procedure to provide a consistent and uniform methodology that can be applied by any Regional Entity. Ontario IESO does not support the Commission's proposal to limit case-by-case determinations to underlying transmission systems operating at less than 100 kV.

b. Commission Determination

75. The Commission agrees with commenters that, at least initially, expanding the scope of facilities subject to the Reliability Standards could create uncertainty and might divert resources as the ERO and Regional Entities implement the newly created enforcement and compliance regime. Further, we agree with commenters that unilaterally modifying the definition of the term bulk electric system is not an effective means to achieve our goal. For these reasons, the Commission is not adopting the proposed interpretation contained in the NOPR. Rather, for at least an initial period, the Commission will rely on the NERC definition of bulk electric system [47] and NERC's registration process to provide as much certainty as possible regarding the applicability to and the responsibility of specific entities to comply with the Reliability Standards in the start-up phase of a mandatory Reliability Standard regime. [48]

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

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

78. The Commission believes that the above approach satisfies concerns raised by NARUC and New York Commission that the proposal to interpret Bulk-Power System exceeds the Commission's jurisdiction. When the Commission addresses this matter in a future proceeding, it will consider NARUC's and New York Commission's comments regarding the “layer of ‘area' transmission.”

79. We disagree with commenters claiming that the ERO's definition of bulk electric system is broader than the statutory definition of Bulk-Power System. Connecticut Attorney General, Connecticut DPUC and others argue that the ERO's definition of bulk electric system exceeds the Commission's jurisdiction by including generation that is not needed to maintain transmission system reliability and, therefore, intrudes into state jurisdiction over generation resource adequacy. First, none of the Reliability Standards submitted by the ERO set requirements for resource adequacy. Moreover, commenters have not adequately supported their claim that the “threshold” in the NERC definition of bulk electric system that includes facilities “generally operated at 100 kV or higher” is broader than the statutory phrase “electric energy from generation facilities needed to maintain transmission system reliability.” As stated explicitly in the NERC definition, this is a “general” threshold and allows leeway to address specific circumstances. On its face, the NERC definition is not overbroad; as applied, it must be interpreted and applied consistent with the statutory language in section 215. Finally, as stated above, we believe that the ERO definition of bulk electric system is narrower than the statutory definition of Bulk-Power System.

2. Applicability to Small Entities

80. The NOPR discussed NERC's plan to, in the future, identify in a particular Reliability Standard limitations on applicability based on electric facility characteristics. [52] The Commission agreed that it is important to examine the impact a particular entity may have on the Bulk-Power System in determining the applicability of a specific Reliability Standard. However, the Commission stated that a “blanket waiver” approach that would exempt entities below a threshold level from compliance with all Reliability Standards would not be appropriate because there may be instances where a small entity's compliance is critical to reliability. The Commission also proposed to direct NERC to develop procedures that permit a joint action agency or similar organization to accept compliance responsibility on behalf of their members.

81. In addition, the Commission solicited comment on whether, despite the existence of a threshold in a particular standard (e.g., generators with a nameplate rating of 20 MW or over), the ERO or a Regional Entity should be permitted to include an otherwise exempt facility, e.g., a 15 MW generator, on a facility-by-facility basis, if it determines that the facility is needed for Bulk-Power System reliability and, if so, what, if any, process the ERO or Regional Entity should provide when making such a determination.

a. Identifying Applicable Small Entities

i. Comments

82. While certain commenters, including EEI, FirstEnergy, SERC, Xcel and Entergy, agree with the Commission that a blanket waiver to exempt small entities from compliance is not appropriate because there may be instances where a small entity's compliance is critical to reliability, APPA, ELCON, Process Electricity Committee, MEAG and South Carolina EG advocate a blanket waiver.

83. APPA notes that none of the entities that contributed to the August 14, 2003 blackout were “small entities” within the meaning of the Regulatory Flexibility Act. APPA and MEAG believe that the Commission's refusal to provide for a blanket waiver to small entities is counterproductive to maintaining reliability, as it will distract compliance staff at NERC and the Regional Entities from identifying and monitoring those with a material impact on reliability, and gives insufficient deference to NERC as the ERO. APPA recommends that the methods and procedures used to identify critical facilities that impact the bulk electric system, regardless of size, should be the subject of a specific set of NERC Reliability Standards. Objective, transparent study criteria and assumptions and due process for affected entities are essential to implement such standards properly. Regional Entities should take advantage of industry expertise in developing and applying the methodology for determining critical facilities.

84. According to MEAG, because the Commission has already determined that it is not bound by the NERC compliance registry, [53] the NOPR's approach leaves small systems, which do not appear on the compliance registry, confused about whether the Reliability Standards apply to them. MEAG asks the Commission to either: (1) Grant a temporary, size-based exemption to those small entities that NERC omits from its preliminary compliance registry; or (2) direct NERC to develop and file with the Commission an appropriate size-based exemption for small entities.

85. Several commenters suggest thresholds for applying Reliability Standards. MEAG states that an appropriate threshold level for an exemption, on either an interim or more permanent basis, should at least provide that a LSE or distribution provider should generally be omitted from the compliance registry if it meets the following criteria: (1) Its peak load is less than 25 MW and it is not directly connected to the Bulk-Power System; (2) it is not designated as the responsible entity for facilities that are part of a required underfrequency load shedding (UFLS) program designed, installed, and operated for the protection of the Bulk-Power System; or (3) it is not designated as the responsible entity for facilities that are part of a required undervoltage load shedding (UVLS) program designed, installed, and operated for the protection of the Bulk-Power System. STI Capital states that there should be a rebuttable presumption that any generation facility below 50 MW does not pose a threat to reliability. Moreover, more data intensive standards are beyond the ability of small generators.

86. SERC states that exemptions should be granted through the Reliability Standards development process. The ERO and the Regional Entities can provide guidance in that process, and stakeholders have an opportunity to comment on that guidance.

87. A number of commenters, including APPA, NRECA, TANC and TAPS, ask the Commission to adopt NERC's registry guidelines and make clear that issues of applicability will be determined with reference to the NERC compliance registry. [54] TAPS asks the Commission to either approve NERC's registry criteria, or send them back to NERC for further consideration, with mandatory application of Reliability Standards deferred until NERC submits waiver criteria the Commission finds acceptable. According to TAPS, these criteria do not constitute a blanket waiver because they allow NERC and its Regional Entities to go below the general threshold requirements where they determine it is necessary.

88. California Cogeneration states that, while focusing on entities that have a material impact on the Bulk-Power System is a possible approach to applying the Reliability Standards, the proposed rule does not define how “material impact” may be demonstrated. According to California Cogeneration, material impact will vary among Interconnections and it may vary among individual transmission systems. Therefore, California Cogeneration states that the task of defining “material impact” should be remanded by the Commission to NERC for resolution through an inclusive stakeholder process. Until that process is completed, California Cogeneration maintains that the Reliability Standards should not be finally adopted as mandatory and enforceable.

89. Various Georgia cities, which are all member systems of MEAG, state that the Commission should place reasonable limits on the applicability of the proposed Reliability Standards. [55] Each maintains that the Final Rule should include a rebuttable presumption that their distribution system facilities have no material effect on Bulk-Power System reliability unless established otherwise. They suggest that such a rebuttable presumption approach would fairly establish the “reasonable limits on applicability” of the Reliability Standards based on their respective sizes. Similarly, Small Entities Forum supports a rebuttable presumption that any LSE or distribution provider with less than 25 MW of load would be excluded unless a Regional Entity decides that a reason exists to include it.

90. California Cogeneration states that qualifying facilities (QFs) are exempted from section 215 of the FPA. It claims that, after passage of EPAct 2005, the Commission modified its regulations to provide that QFs are exempt from all sections of the FPA except sections 205, 206, 220, 221 and 222. [56] Further, California Cogeneration states that the Commission should set limits on whether a Reliability Standard applicable to a generator owner or operator also applies to operators of cogeneration facilities. According to California Cogeneration, the Commission has clearly determined that the impact by a cogenerator on the reliability of the system is limited to its net load on the system. [57] Therefore, California Cogeneration maintains that the Reliability Standards should reflect this limitation.

91. Finally, Small Entities Forum and Entergy state that, despite the existence of a threshold in a particular Reliability Standard, the ERO or a Regional Entity should be permitted to include an otherwise exempt facility, on a facility-by-facility basis, if it determines that the facility is needed for Bulk-Power System reliability. South Carolina EG states that exceptions to an exemption threshold should sufficiently improve reliability so as to justify the administrative costs and other burdens. However, SMA and MidAmerican oppose allowing the ERO or its designee to include otherwise exempt facilities by making exceptions.

ii. Commission Determination

92. The Commission believes that, at the outset of this new program, it is important to have as much certainty and stability as possible regarding which users, owners and operators of the Bulk-Power System must comply with mandatory and enforceable Reliability Standards. NERC, as the ERO, has developed an approach to accomplish this through its compliance registry process. The Commission has previously found NERC's compliance registry process to be a reasonable means “to ensure that the proper entities are registered and that each knows which Commission-approved Reliability Standard(s) are applicable to it.” [58]

93. NERC has provided with its NOPR comments, and in a subsequent supplemental filing, a Statement of Compliance Registry Criteria that describes how NERC will identify organizations that may be candidates for registration and assign them to the compliance registry. For example, NERC plans to register only those distribution providers or LSEs that have a peak load of 25 MW or greater and are directly connected to the bulk electric system or are designated as a responsibility entity as part of a required underfrequency load shedding program or a required undervoltage load shedding program. For generators, NERC plans to register individual units of 20 MVA or greater that are directly connected to the bulk electric system, generating plants with an aggregate rating of 75 MVA or greater, any blackstart unit material to a restoration plan, or any generator “regardless of size, that is material to the reliability of the Bulk-Power System.”

94. The compliance registry identifies specific categories of users, owners and operators that correlate to the types of entities responsible for performing specific functions described in the NERC Functional Model. [59] These same functional types are also used by the ERO to identify the entities responsible for compliance with a particular Reliability Standard in the Applicability section of a given standard. Thus, each registered entity will be registered under one or more appropriate functional categories, and that registration by function will determine with which Reliability Standards—and Requirements of those Reliability Standards—the entity must comply. In other words, a user, owner or operator of the Bulk-Power System would be required to comply with each Reliability Standard that is applicable to any one of the functional types for which it is registered.

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

96. In sum, the ERO will identify those entities that must comply with Reliability Standards in three steps: (1) The ERO will identify and register those entities that fall under its definition of bulk electric system; (2) each registered entity will register in one or more appropriate functional categories and (3) each registered entity will comply with those Reliability Standards applicable to the functional categories in which it is registered.

97. In response to MEAG's concern that the Commission previously determined that it was not bound by the NERC compliance registry process and that there thus was uncertainty, the Commission is modifying the approach proposed in the NOPR and, as noted above, will use the NERC compliance registry to determine those users, owners and operators of the Bulk-Power System that must comply with the Reliability Standards. Each individual Reliability Standard will then identify the set of users, owners and operators of the Bulk-Power System that must comply with that standard. While the Commission may take prospective action against an entity that was not previously identified as a user, owner or operator through the NERC registration process once it has been added to the registry, the Commission will not assess penalties against an entity that has not previously been put on notice, through the NERC registration process, that it must comply with particular Reliability Standards. Under this process, if there is an entity that is not registered and NERC later discovers that the entity should have been subject to the Reliability Standards, NERC has the ability to add the entity, and possibly other entities of a similar class, to the registration list and to direct corrective action by that entity on a going-forward basis. [61] The Commission believes that this should prevent an entity from being subject to a penalty for violating a Reliability Standard without prior notice that it must comply with that Reliability Standard.

98. As stated in the NOPR, NERC has indicated that in the future it may add to a Reliability Standard limitations on applicability based on electric facility characteristics such as generator nameplate ratings. [62] While the NOPR explored this approach as a means of addressing concerns over applicability to smaller entities, the Commission believes that, until the ERO submits a Reliability Standard with such a limitation to the Commission, the NERC compliance registry process is the preferred method of determining the applicability of Reliability Standards on an entity-by-entity basis.

99. A number of municipalities and generation owners ask that the Commission review their particular circumstances and provide an individual waiver from compliance with the mandatory Reliability Standards. In light of our above discussion, the Commission declines to determine whether any individual municipality, generation owner or other entity is subject to a specific Reliability Standard. Rather, NERC and the Regional Entities should determine such applicability in the first instance through the registration process.

100. We agree with California Cogeneration that the Commission's regulations currently exempt most QFs from specific provisions of the FPA including section 215. [63] The Commission is concerned, however, whether it is appropriate to grant QFs a complete exemption from compliance with Reliability Standards that apply to other generator owners and operators. It is not clear to the Commission that for reliability purposes there is a meaningful distinction between QF and non-QF generators. While such an issue is beyond the scope of the current rulemaking, we note that, concurrent with the issuance of this Final Rule, the Commission is issuing a notice of proposed rulemaking that proposes to amend the Commission's regulation that exempts most QFs from section 215 of the FPA.

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

b. Ability To Accept Compliance on Behalf of Members

i. Comments

102. APPA, NERC, ELCON, APPA, TAPS and Small Entities Forum support the Commission's proposal to allow a joint action agency, generation and transmission (GT) cooperative, or other entities to accept responsibility for compliance with Reliability Standards on behalf of their members and also may divide the responsibilities for compliance with its members. APPA states that this should also be extended to RTOs, vertically integrated utilities, and other wholesale power suppliers that perform substantial reliability functions on behalf of their full requirements wholesale customers, including public power distribution systems and other entities that currently fulfill reliability functions for customers. APPA, TAPS and Small Entities Forum state that the procedure should allow for this responsibility to be assigned on a standard-by-standard basis.

103. In response to the Commission's proposal to direct NERC to develop procedures that permit a joint action agency or similar organization to accept compliance responsibility on behalf of its members, NERC proposes the following procedure, and has updated its entity registration criteria to reflect these changes. [66] NERC states that each “central” organization should be able to register as being responsible for compliance for itself and collectively on behalf of its members. Each member within a central organization may separately register to be accountable for a particular reliability function defined by the standards. Under NERC's proposal, if the central organization and a member organization cannot agree that one organization or the other is responsible, or if the parties agree that the responsibilities for a particular reliability function should be split, then NERC would register both entities concurrently. NERC and the Regional Entities will then have the authority to find either organization or both accountable for a violation of a Reliability Standard, based on the facts of the case and circumstances surrounding the violation.

104. AMP-Ohio states that the Commission should clarify that a joint action agency should not be required to assume compliance responsibility for its members for all reliability-related functions. It asks that the Commission allow flexibility in how joint action agencies and their members allocate responsibility. TAPS states that joint action agencies should be allowed to achieve compliance with a standard at the joint action agency level rather than to simply stand in the shoes of their individual members. TAPS states that this is necessary to ensure comparable treatment for small entities in relation to large utilities. Where a joint action agency accepts compliance responsibility and a standard is susceptible to joint action agency-level assessment of compliance, the Commission should ask NERC to adopt such assessment to avoid an adverse impact on competition.

105. MEAG finds the Commission's proposal with regard to joint action agencies problematic. MEAG asserts that the proxy approach is not a universal approach to small municipal systems. For example, this option would be fundamentally inconsistent with MEAG's role as a GT cooperative serving its member systems because MEAG has no authority to plan, physically operate, modify, maintain or test the local distribution system facilities of the member systems. Second, MEAG states that if it were to assume the role of the proxy compliance agent for the member systems and incur a fine for the failure of a few to comply with the requirements of the Reliability Standards, then the imposition of fines would lead to a rate increase to all systems, an improper and unjustifiable cost shifts among the member systems. Third, if MEAG were to err in its role as a proxy compliance agent for the member systems, MEAG could be sued and there is nothing that presently limits its liability or provides indemnification to MEAG in that circumstance. Moreover, MEAG states that the compliance-by-proxy option will not mitigate the economic impact on many small distribution-only entities because many are not members of joint action agencies.

106. Several commenters, including EEI, PJM and FirstEnergy do not oppose the Commission's proposal to allow organizations to accept compliance responsibility on behalf of members so long as compliance responsibility is clear and responsible entities are held accountable. FirstEnergy and PJM state that some Reliability Standards appear to have duplicate accountability in different organizational entities, which could create confusion and complicate operational authority and thus undermine the transmission operator chain of command required to respond quickly and decisively to system operational events. Further, FirstEnergy states that some Reliability Standards obligate an entity to perform reliability functions when that entity may not be able to perform its reliability function due to other legal constraints. FirstEnergy states that one effective approach to resolving this problem would be to establish a “priority” of control between entities. FirstEnergy adds that entities that are subject to legal control by ISOs and RTOs should be afforded a “safe harbor” under the Reliability Standards if, during an emergency, they perform as directed by the ISO or RTO, whether under the ISO/RTO's OATT or under the ISO/RTO's authority as reliability coordinator.

ii. Commission Determination

107. The Commission directs the ERO to file procedures which permit (but do not require) an organization, such as a joint action agency, GT cooperative or similar organization to accept compliance responsibility on behalf of its members. The Commission believes that NERC's proposed procedures described above are reasonable, and directs the ERO to submit a filing within 60 days. [67] In allowing a joint action agency, GT cooperative or similar organization to accept compliance responsibility on behalf of its members, our intent is not to change existing contracts, agreements or other understandings as to who is responsible for a particular function under a Reliability Standard. Further, we clarify that there should not be overlaps in responsibility nor should there be any gaps.

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

109. NERC, in developing its procedures relating to joint action agencies and similar organizations, should consider the concerns of EEI, PJM and FirstEnergy regarding the need for ensuring clear lines of responsibility. While we agree with FirstEnergy in the abstract that an entity implementing the legal directives of an ISO or RTO should not be penalized for following an ISO or RTO directive during an emergency, we will not mandate a safe harbor provision for such circumstances. Rather, these and other matters should be considered by the ERO or a Regional Entity when deciding the appropriate enforcement action in response to an event where a violation of a Reliability Standard may have occurred.

3. Definition of User of the Bulk-Power System

110. In the NOPR, the Commission did not propose a generic definition of the term “User of the Bulk-Power System.” Rather, the Commission stated that it would determine applicability on a standard-by-standard basis. [69] The NOPR explained that § 40.1(b) of the proposed regulations would require the ERO to identify in each proposed Reliability Standard the specific subset of users, owners and operators of the Bulk-Power System to which the proposed Reliability Standard would apply, which is NERC's current practice. The NOPR also stated that entities concerned that a particular proposed Reliability Standard would apply more broadly than the statute allows may raise their concerns in the context of the specific Reliability Standard.

a. Comments

111. APPA disagrees with a standard-by-standard approach to defining the term “user of the Bulk-Power System” because it would go beyond those facilities that are required to maintain the reliability of the high-voltage, bulk transmission system and intrude into state and local matters and trespass on state jurisdiction. According to APPA, the Reliability Standards themselves state their applicability in terms of the Functional Model, which does not include size limitations in the various functional categories included in it. Without some type of outer limit on the “user of the Bulk-Power System” definition, all such entities regardless of size or their impact on the Bulk-Power System, must review every proposed Reliability Standard and protest every time they have a “concern in the context of the specific Reliability Standard.” They must also retain permanent staff or consultants to evaluate new or revised standards. Rather, APPA, as does TANC, urges the Commission to support NERC's registry criteria to make the definition of “users of the Bulk-Power System” co-extensive with the users on NERC's compliance registry.

112. SMA is concerned that not specifically defining who is a “user of the Bulk-Power System” will not provide timely notice to entities that are not the parties historically responsible for implementing NERC's prior reliability standards. SMA states that NERC must identify the subset of users that must comply with any given Reliability Standard at a sufficiently early stage for all such affected parties to have an opportunity to raise objections to the sweep or content of the Reliability Standard while approval of that Reliability Standard is under consideration. SMA also argues that NERC's Rules of Procedure must require actual notice to an entity before it is placed on the compliance registry.

113. Southwest TDUs urges the Commission to clarify that “users” are entities that have more involvement with it than merely receiving power from it. Since these Reliability Standards will become mandatory and violation of any of them can be accompanied by economically significant penalties, Southwest TDUs urges the Commission to make every effort to be specific about what constitutes a “user.”

114. California Cogeneration states that the Commission has not provided any detail as to how a “user” will be identified. The NOPR and the NERC Reliability Standards it proposes to adopt rely on the broad entities identified in the NERC Functional Model. According to California Cogeneration, using only the NERC Functional Model provides no detail and no differentiation in the applicability of each Reliability Standard. While a single definition of “user” may not be appropriate, California Cogeneration maintains that using only the fixed designations within the NERC Functional Model does not provide sufficient specificity. The terms “Generator Owner” and “Generation Operator” also must be qualified so that they only apply to generation operations that utilize the grid and exclude generation output dedicated to on-site consumption.

b. Commission Determination

115. The Commission's determination above to rely on the ERO's compliance registry process to identify users, owners and operators of the Bulk-Power System that must comply with new mandatory and enforceable Reliability Standards should resolve the concerns expressed by APPA, SMA and others regarding the need to identify and provide timely notice to those users of the Bulk-Power System that are expected to comply with specific Reliability Standards.

116. While we recognize the desire of some commenters for a concise, generic definition of “user of the Bulk-Power System,” we are concerned that any attempt to define the term at this time will either be overly broad so as not to provide any helpful guidance or overly narrow so as to exclude entities that should be covered. The Commission believes that it has employed a reasonable approach by endorsing NERC's compliance registry process and requiring that each Reliability Standard identify the subset of users, owners and operators to whom that particular Reliability Standard applies.

4. Use of the NERC Functional Model

117. NERC has developed a “Functional Model” that defines the set of functions that must be performed to ensure the reliability of the Bulk-Power System. The Functional Model identifies 14 functions and the name of a corresponding entity responsible for fulfilling each function.

118. In the NOPR, the Commission proposed to use the NERC Functional Model to identify the applicable entities to which each Reliability Standard applies. [70] The Commission explained that focusing on the functions an entity performs to identify what entities are users, owners and operators of the Bulk-Power System, and thus what entities are subject to the Reliability Standards, provides a useful level of detail and appears to be more practical than simply identifying an applicable entity as a user, owner or operator. In addition, the NOPR recognized concerns that the Functional Model may contain ambiguities and proposed to require NERC to specifically address these concerns.

119. The Commission proposed that, because the Functional Model is linked to applicability of the Reliability Standards, the ERO should submit for Commission approval any future modifications to the Functional Model that may affect the applicability of the Reliability Standards.

a. Filing the Functional Model With the Commission

i. Comments

120. NERC states that, while it believes that the Functional Model should be filed for informational purposes only, it will submit any changes to the Functional Model to the Commission for approval as requested. While NERC states that the Functional Model will not function as a legally binding document like a Reliability Standard, the Commission's approval of this reference document and of any changes to the Functional Model will support the development of high quality, enforceable and technically sufficient standards.

121. Several commenters, including NERC, EEI, APPA, MidAmerican, National Grid and MRO state that the Functional Model is not part of the Reliability Standards and should be filed with the Commission for informational purposes only. They generally state that the Functional Model is not a definitive guide to the “users, owners and operators” of the Bulk-Power System and should not be used to establish obligations under section 215, which should be established within each individual Commission-approved Reliability Standard.

122. Northeast Utilities is concerned with the Commission's proposal to use the NERC Functional Model to identify applicable entities. It believes that the Functional Model can be useful in drafting standards, but it is not a substitute for having clear definitions of the entities responsible for compliance with the requirements for each Reliability Standard within a region. The entities responsible for meeting the standard may vary depending on how the Bulk-Power System is operated. FirstEnergy states that the Functional Model may not clearly or correctly identify the entities to which a Reliability Standard applies and maintains that the Functional Model should be applied only where all of the affected stakeholders agree on the final classifications of each Registered Entity's roles and responsibilities.

123. In contrast, TANC and ISO-NE state that the Commission should require that any future modification to the Functional Model that could affect the categories of entities that must comply with a particular Reliability Standard be approved by the Commission because the Functional Model is so closely interrelated with the applicability of each Reliability Standard.

124. APPA, TAPS and ReliabilityFirst maintain that any modification to the NERC Functional Model should be reviewed and approved through the Reliability Standards development process. According to ReliabilityFirst, any change to the Functional Model is essentially an amendment to the Reliability Standard made outside the ERO process. TANC asserts that a Reliability Standard will only be complete if the definitions of the Functional Model are developed through the Reliability Standards development process just like any Reliability Standard. APPA would allow NERC to issue interpretations of the Functional Model, but these interpretations should then be confirmed through NERC procedures.

125. TAPS cautions that, because the Functional Model includes no express size limitations, NERC and the Commission can rely on the Functional Model to define applicability of standards only if such limits are imposed by NERC's compliance registry criteria and its bulk electric system definition. The Small Entities Forum is concerned because smaller entities have historically performed only a subset of functions. For example, it states that some joint action agencies invest in transmission facilities that are operated by others, but that these joint action agencies, under the Functional Model, would have to verify that these facilities, operated by others, are being operated and maintained according to applicable Reliability Standards.

126. Several commenters argue that the Functional Model contains a number of ambiguities. MISO argues that the definition of the term planning coordinator is circular and may lead to one subset of the transmission system having multiple Planning Coordinators. MISO recommends that the Commission direct NERC to survey the industry to identify the planning roles that actually exist in the industry and clarify the role of the wide-area Planning Coordinator. MISO and Wisconsin Electric note that the proposed Reliability Standards do not specify who fulfills the Interchange Authority or Planning Authority roles, and there is no common industry understanding of those roles. Finally, California Cogeneration states that the definition of LSE is too inclusive and should be modified to exclude entities providing service only to loads on-site or pursuant to private contract.

ii. Commission Determination

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

128. With regard to the comments of TAPS, APPA, TANC and others on whether revisions to the Functional Model should be made through the ERO's Reliability Standards development process, we do not believe that it is necessary under the statute, since applicability will be determined at this time by the specifications of the Reliability Standards and the compliance registry process. Thus, we leave to the discretion of the ERO the appropriate means of allowing stakeholder input when revising the Functional Model. To the extent that changes in the Functional Model require revised specification in the Reliability Standards, the latter will be addressed in the Reliability Standards development process.

129. While TAPS and Small Entities Forum raise concerns regarding the absence of size limitations in the Functional Model and potential negative impacts on small entities, we believe that these concerns are addressed above in our decision regarding use of the NERC compliance registry process. MISO, Wisconsin Electric and others comment on the need to clarify certain ambiguities in the Functional Model. Given that the Functional Model is an evolving guidance document, the ERO can address such concerns as it updates and revises the Functional Model.

b. Responsibility for Functions Within the Functional Model

130. In the NOPR, the Commission explained that, in the context of an ISO or RTO or any organization that pools resources, decision-making and implementation are performed by separate groups. [72] The ISO or RTO typically makes decisions for the transmission operator and, to a lesser extent, the generation operator, while actual implementation is performed by either local transmission control centers or independent generation control centers. The NOPR proposed that “all control centers and organizations that are necessary for the actual implementation of the decisions or are needed for operation and maintenance made by the ISO or RTO or the pooled resource organizations are part of the transmission or generation operator function in the Functional Model.” [73]

i. Comments

131. A number of commenters raise concerns or seek clarification regarding the relationship between the Functional Model and existing agreements that set forth the responsibility of various entities, particularly in the context of ISO and RTO operations. MISO requests the Commission to clarify that nothing in the Functional Model requires one entity to be responsible for all of the tasks within a function, regardless of who actually performs the task. In those ISOs and RTOs where balancing authorities have retained and have never delegated to the RTO certain tasks that fall within the balancing authority function, NERC's Functional Model should only require one responsible entity per task rather than one responsible entity for all of the tasks within that function. MISO submits that the NERC Functional Model should not play a prescriptive role by assigning responsibility for a given task where such an assignment would be inconsistent with a Commission-approved regional transmission agreement, RTO tariff, or reliability plan filed with NERC, all of which specify the entity performing each task.

132. PJM states that, while the Commission proposed to assign responsibility for reliable operations to multiple entities within an ISO or RTO to address its concern that decision making and implementation are performed by separate organizations, it does not believe that increasing the number of organizations responsible for a given function for the same facilities within the bulk electric system has been shown to be an effective or appropriate solution to the concerns cited. PJM states that NERC employs processes that successfully manage the delegation of operational tasks while maintaining single entity accountability for the reliable performance of those operational tasks.

133. ATC states that Regional Entities should be given the flexibility to allow some “tasks” within a “function” to be performed by one entity, with the remaining tasks to be performed by another entity. According to ATC, this would provide entities—particularly smaller ones—with the flexibility to transfer their responsibility for a reliability task or function to another registered entity that can perform the work more effectively. Further, ATC maintains, Regional Entities should ensure that entities be given accountability only for systems, facilities and functions over which they actually have control.

134. NPCC states that requirements applicable to local control centers should be distinct from requirements applicable to transmission and generation operators under the NERC Functional Model. NPCC submits that there is a difference between being assigned to do a task and being responsible for the completion of that task. An organization that registers with NERC as performing a function is considered a responsible entity and must ensure that all tasks are performed. While an organization may delegate a task to another organization, it may not delegate its responsibility for ensuring that the task is accomplished.

135. According to Ontario IESO, the Commission's proposal is inconsistent with the NERC Functional Model, which envisions one responsible entity for each reliability function. In contrast, the Commission's proposal would split the same function between different organizations such as an ISO and a local control center. PJM claims that, under the Functional Model, single entity registration is a foundational cornerstone for ensuring clear responsibility and accountability for compliance with Reliability Standards.

136. Ontario IESO asserts that the Commission's proposal is also problematic because in the event of a violation it will be difficult to determine who violated the Reliability Standard—the entity making the decision or the entity implementing the decision. Ontario IESO argues that, although the NERC Functional Model is not foolproof, it avoids complications by distinguishing between responsibility and performance. The ISO is the responsible entity and it delegates some of its tasks to local control centers, but retains the overall responsibility.

137. According to Ontario IESO, NERC has recognized that, although organizations such as local control centers play an important role in reliability, they are not responsible entities. Therefore, NERC has made such organizations subject to compliance audits and placed other requirements on them. In addition, NERC intends that the regional reliability plans will document the relationships between the local control centers and the entity that delegates its responsibility to such centers. The current framework has a mechanism for accommodating reliability considerations for organizations such as local control centers. In this regard, NERC's ongoing formal certification of reliability coordinator, balancing authority and transmission provider will be useful in determining any delegation of tasks to local control centers that must take place for a clear demarcation of responsibilities. Ontario IESO advises that, since NERC has not finished this task, the Commission should defer its decision in this regard.

138. ISO/RTO Council states that the Commission should not use the term “local control center” because it will cause confusion. The NERC Functional Model does not define the term and it means different things in different regions. For example, in MISO, which consists of 25 balancing areas, “local control center” is an equivalent term for balancing area although this was probably not the Commission's intent in the NOPR. Therefore, ISO/RTO Council argues that the Reliability Standards should be limited to defining the tasks in the context of users, owners and operators of the Bulk-Power System; any delegation of responsibilities to a local control center or any other organization should take place in the context of ISO/RTO governing documents, operating agreements, tariffs and other arrangements with transmission owners and related stakeholders. This approach, according to ISO/RTO Council will address the Commission's concerns with respect to local control centers without preempting possible regional solutions.

139. FirstEnergy believes that, while independent authority to operate the transmission system should be self-evident, in RTO environments with local control centers, the tasks performed by each entity do not encompass the entirety of tasks performed by the transmission operator under the Functional Model. It suggests that NERC should revise the Functional Model to create certification and registration requirements for local control authorities within RTOs that perform real-time operations of the transmission system. FirstEnergy states that a revised NERC Functional Model should recognize local control centers that take some direction from RTOs yet maintain authority to act independently to carry-out functional tasks that require real-time operation of the system. According to FirstEnergy, the required registration and certification of such entities would clearly indicate the need for operational personnel in these control rooms to be NERC-certified. It concludes that at a minimum, a NERC certification for the tasks performed by such local control center individuals would be an enhancement over the current situation.

140. ISO-NE argues that the Commission should not mandate that the tasks performed by local control centers be included in the definition of transmission operator because to do so would be to suggest that a local control center has independent autonomy in operating the Bulk Power System which would conflict with the “one set of hands on the wheel” philosophy. It explains that local control center personnel in New England implement tasks delegated to them by ISO-NE for operation of designated transmission facilities. Therefore, ISO-NE submits, the scope of the Reliability Standard need not be expanded.

ii. Commission Determination

141. In response to the many concerns of commenters, the Commission clarifies that it did not intend to change existing contracts, impose new organizational structures or otherwise affect existing agreements that set forth the responsibilities of various entities. Rather, its intent was to allow enough granularity in the definitions so that the appropriate user, owner or operator of the Bulk-Power System would be identified for each Reliability Standard. We agree also with MISO's statement that nothing in the Functional Model requires one entity to be responsible for all of the tasks within a function, regardless of who actually performs the task.

142. The Commission's concern is that, particularly in the ISO, RTO and pooled resource context, there should be neither unintended redundancy nor gaps for responsibilities within a function. In particular, the Commission is concerned that such “gaps” could occur in the context of several Reliability Standards addressing matters related to activities other than directing or implementing real-time operations. [74] For example, the involvement of a transmission operator at an ISO or RTO with respect to the requirements related to telecommunications facilities (COM-001-1) from the local control room and blackstart restoration plans (EOP-005-0) may be minimal. Because the operators at local control centers actually perform all or most of the tasks contemplated under various Reliability Standards, we are concerned that there may be unintended gaps in such responsibilities if the existing contracts between the ISO or RTO and owners of the facilities do not address such responsibilities.

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

144. Consistent with our above explanation, we agree with NPCC that there is a difference between being assigned to perform a task and being responsible for completing the task. The organization that registers with NERC to perform a function will be the responsible entity and, while it may delegate the performance of that task to another, it may not delegate its responsibility for ensuring the task is completed.

145. Accordingly, the Commission directs that the ERO, in registering RTOs, ISOs and pooled resource organizations (or, indeed in registering any entity), assure that there is clarity in the assigning responsibility and that there are no gaps or unnecessary redundancies with regard to the entity or entities responsible for compliance with the Requirements of each relevant Reliability Standard. Accordingly, although the Commission is not requiring NERC to amend the Functional Model, we believe our concerns can be addressed by having the ERO, through its compliance registry process, ensure that each user, owner and operator of the Bulk-Power System is registered for each Requirement in the Reliability Standards that relate to transmission owners to assure there are no gaps in coverage of the type discussed here.

5. Regional Reliability Organizations

146. The NOPR stated that 28 proposed Reliability Standards would apply, in whole or in part, to a regional reliability organization. [75] Further, many of the proposed Reliability Standards that have compliance measures refer to the regional reliability organization as a compliance monitor. The Commission stated in the NOPR that it was not persuaded that a regional reliability organization's compliance with a Reliability Standard can be enforced as proposed by NERC because it does not appear that a regional reliability organization is a user, owner or operator of the Bulk-Power System.

147. The Commission proposed to approve and direct modification of five Reliability Standards that apply partially to regional reliability organizations. For the other Reliability Standards that apply to regional reliability organizations, the Commission proposed, as an interim measure, to direct the ERO to use its authority pursuant to § 39.2(d) of our regulations to require users, owners and operators to provide to the regional reliability organizations information related to data gathering, data maintenance, reliability assessments and other process-type functions. The NOPR explained that this approach is necessary to ensure that there will be no gap during the transition from the current voluntary system to a mandatory system in which Reliability Standards are enforced by the ERO and Regional Entities. The NOPR proposed that, in the long run, Regional Entities should be made responsible, through delegation from the ERO, for the functions currently performed by the regional reliability organizations. To implement this, the Commission proposed the modification of delegation agreements to require the Regional Entities to assume responsibility for noncompliance. In addition, the Commission proposed that the Reliability Standards should be modified to apply to the users, owners and operators of the Bulk-Power System that are responsible for providing information. The Commission proposed to require that any Reliability Standard that references a regional reliability organization as a compliance monitor be modified to refer to the ERO as the compliance monitor.

148. The Commission stated that, while it is important that the existing regional reliability organizations continue to fulfill their current roles during the transition to a regime where Reliability Standards are mandatory and enforceable, the Commission does not understand why, once the transition is complete, a regional reliability organization should play a role separate from a Regional Entity whose function and responsibility is explicitly recognized by section 215 of the FPA. The Commission sought comment on whether there is any need to maintain separate roles for regional reliability organizations with regard to establishing and enforcing Reliability Standards under section 215.

a. Comments

149. NERC believes it can remove references to regional reliability organizations and Regional Entities from the Reliability Standards, with the exception of retaining the Regional Entities as the compliance enforcement authorities. However, NERC and California PUC request that the Commission reconsider its proposal to direct that the ERO be listed as the compliance monitor in each Reliability Standard. California PUC states that naming NERC as the compliance monitor deprives the Regional Entities of their enforcement role under section 215. NERC believes it will be clearer, and consistent with the delegation agreements, to designate the Regional Entity as the compliance monitor in almost all Reliability Standards. According to NERC, this would also be helpful to distinguish those few Reliability Standards that are monitored directly by NERC.

150. ReliabilityFirst, TANC and SoCal Edison agree with the Commission that regional reliability organizations and Regional Entities cannot be users, owners or operators of the Bulk-Power System and should not be subject to compliance with Reliability Standards. TANC states that Reliability Standards that reference a regional reliability organization need to be revised to reference a user, owner or operator of the Bulk-Power System in order to comply with the statute.

151. EEI agrees with the Commission's proposal to direct the ERO to require users, owners and operators to provide the information related to data gathering, data maintenance, reliability assessments and other process-type functions that previously have applied to regional reliability organizations. EEI also agrees that, in the long run, it is appropriate to make the Regional Entities responsible through delegation from the ERO for various functions now performed by regional reliability organizations. In doing so, and during the transition in particular, EEI maintains that it is important that functions now performed by the regional councils, such as planning, be continued.

152. A number of commenters discuss the possible ongoing role for a regional reliability organization. For example, Ontario IESO, NPCC and National Grid state that the Commission should recognize that the regional reliability organizations will continue to play a role in areas including developing regional reliability plans and adequacy requirements that are outside the jurisdiction of the ERO. NPCC states that enforcement of adequacy requirements should continue to reside with the regional reliability organization. National Grid states that the role of regional reliability organizations can be preserved in a variety of ways, including requiring obligations currently imposed upon regional reliability organizations to be included in the regional delegation agreements.

153. NPCC further maintains that regional reliability organizations should continue to function as regional sites for technical expertise for enhanced reliability requirements through adopting regionally-specific criteria. According to NPCC, eliminating the ability for regions to develop and propose new criteria that enhance system reliability would edge the system closer towards the lowest common denominator rather than striving towards operational excellence. Further, Ontario IESO and NPCC state that regional reliability organizations should be allowed to perform certain functions for their members, such as system operator workshops, forums for coordination of operations and planning and operational readiness conference calls.

154. Massachusetts DTE comments that a regional reliability organization should be allowed to propose a Reliability Standard that may exceed or enhance the proposed mandatory Reliability Standards to ensure regional reliability. It further states that any regional reliability criteria proposed by a regional reliability organization should be vetted through a regional stakeholder process and then specifically adopted by the appropriate state regulatory authorities.

155. Although MRO does not oppose regional reliability organizations, with regard to establishing and enforcing mandatory Reliability Standards, MRO, Constellation and Xcel state that there is no need to maintain a separate role for regional reliability organizations. Because Regional Entities may perform non-reliability functions, Constellation states that maintaining regional reliability organizations will result in unnecessary cost. While Constellation has no objection to the Regional Entities performing non-statutory functions, it states that the Commission should not allow Regional Entities to impose Reliability Standards developed by the regional reliability organizations as mandatory Reliability Standards.

156. MidAmerican believes that it will be important to separate the compliance functions of the Regional Entities from non-compliance functions currently assigned to the regional reliability organizations. It states that this can be done by: (1) Separating these functions internally in the Regional Entities; (2) separating these functions in different organizations; or (3) separating these functions by assigning non-compliance related functions currently assigned to the regional reliability organizations to other users, owners and operators. This will minimize conflicts between the Regional Entity core compliance function and the non-compliance regional reliability organization requirements.

b. Commission Determination

157. The Commission adopts the NOPR proposal to eliminate references to the regional reliability organization as a responsible entity in the Reliability Standards. We conclude that this approach is appropriate because, as explained in the NOPR, such entities are not users, owners or operators of the Bulk-Power System. NERC indicates that it can remove such references, except that the Regional Entity should be identified as the compliance monitor where appropriate. While the Commission originally proposed that the ERO should be designated as the compliance monitor, we agree with NERC's approach and believe that identifying the Regional Entity as the compliance monitor will provide useful specificity as to which entity will be immediately tasked with monitoring compliance with a particular Reliability Standard. However, as we stated in Order No. 672, the ERO retains responsibility to ensure that a Regional Entity implements its enforcement program in a consistent manner, and to periodically review the Regional Entity's enforcement activities. [76]

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

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

159. We continue to believe that this is a reasonable interim measure, and note that EEI and others support this approach. To ensure that the ERO properly and timely addresses this matter, we direct the ERO to submit an informational filing within 90 days of the Final Rule that describes its plan and schedule for developing both an interim and long-term resolution based upon the above direction.

160. In response to the Commission's inquiry in the NOPR, commenters identify a number of possible continuing roles for regional reliability organizations. Such activities are beyond the scope of this proceeding. Clearly, any such role must be limited to non-statutory functions. Some commenters suggest that regional reliability organizations may have a role in developing voluntary criteria. Regional reliability organizations should not develop voluntary criteria that address the same or similar matters as mandatory and enforceable Reliability Standards, because that is the responsibility of the Regional Entities. [79]

D. Mandatory Reliability Standards

1. Legal Standard for Approval of Reliability Standards

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

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

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

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

a. Comments

164. NERC states that 83 of the Reliability Standards are “just, reasonable, not unduly discriminatory or preferential, and in the public interest,” and should therefore be approved and made effective as mandatory Reliability Standards. NERC believes that, by following NERC's Reliability Standards development process, a Reliability Standard should meet the requirement that a standard be “just, reasonable, not unduly discriminatory or preferential.” Further, NERC asserts that, by filing with the Commission the written record of development for each Reliability Standard, NERC has given the Commission strong evidence that those 83 Reliability Standards are just, reasonable, and not unduly discriminatory or preferential.

165. NERC states that the requirement that a Reliability Standard be “in the public interest” provides the Commission with broad discretion to review and approve a Reliability Standard. According to NERC, implicit in the “public interest” test is that a Reliability Standard is technically sound and ensures an adequate level of reliability, and that the Reliability Standards provides a comprehensive and complete set of technically sound requirements that establish an acceptable threshold of performance necessary to ensure reliability of the Bulk-Power System. NERC states that it believes that approving those 83 Reliability Standards as enforceable as NERC begins operating as the ERO meets this objective and will achieve an adequate level of reliability as required by law. NERC asserts that adopting fewer of the Reliability Standards would both create potential reliability risks and communicate that some aspects of reliability are not viewed as important enough to be the subject of mandatory and enforceable Reliability Standards under the FPA.

166. FirstEnergy states that each proposed standard should be reviewed against the following criteria: (1) Clarity; (2) technical means to comply; (3) practicability; (4) consistency and (5) costs.

b. Commission Determination

167. The Commission agrees with NERC that an open and transparent process is important in implementing section 215 of the FPA and developing proposed mandatory Reliability Standards. However, in Order No. 672, the Commission rejected the presumption that a proposed Reliability Standard developed through an ANSI-certified process automatically satisfies the statutory standard of review. [83] The Commission reiterates that simply because a proposed Reliability Standard has been developed through an adequate process does not mean that it is adequate as a substantive matter in protecting reliability. We will, therefore, review each Reliability Standard to ensure that the Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest, giving due weight to the ERO.

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

2. Commission Options When Acting on a Reliability Standard

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

170. With regard to the second category, the Commission explained that it would take two separate and distinct actions under the statute. First, pursuant to section 215(d)(2) of the FPA, the Commission would approve a proposed Reliability Standard, which would be mandatory and enforceable upon the effective date of the Final Rule. Second, the Commission would direct NERC to submit a modification of the Reliability Standard to address specific issues or concerns identified by the Commission pursuant to section 215(d)(5) of the FPA.

171. With regard to the third category, “request additional information,” the NOPR explained that some Reliability Standards do not contain sufficient information to enable the Commission to propose a disposition. For those Reliability Standards, the Commission identified the needed information, and proposed not to approve or remand these Reliability Standards until all the relevant information is received. As an example, the NOPR explained that many of the fill-in-the-blank standards would not be approved or remanded until the Commission had received all the necessary information.

a. Comments

172. Most commenters generally support the Commission's proposal to have four courses of action it may take on a Reliability Standard. However, Xcel has concerns about the legality of approving many of the proposed Reliability Standards as mandatory but, at the same time, ordering the ERO to make specific modifications to them. According to Xcel, section 215(d) does not expressly create this “approve but modify” option. To the contrary, section 215(d)(4) suggests that the Commission should remand to the ERO a standard that it disapproves “in whole or in part.”

173. While many commenters support the Commission proposal to approve certain Reliability Standards as mandatory and enforceable; and direct NERC to modify them pursuant to section 215(d)(5), they are concerned that the Commission's directives to modify certain Reliability Standards are too prescriptive. [86] They contend that, in prescribing particular requirements, metrics, or specific language to be used, the Commission is setting the Reliability Standard outside the open Reliability Standards development process and not giving due weight to the ERO under section 215 of the FPA. NRECA, for example, argues there is a major distinction between (a) requiring a Reliability Standard to address a specific matter and (b) requiring (as opposed to suggesting) a specific Reliability Standard or requiring a reliability matter to be addressed in a specific way. These commenters ask that the Final Rule state that a directive to improve a Reliability Standards be in the form of an objective to be achieved or concern or deficiency to be resolved within the Reliability Standard, rather than a particular requirement, metric, or specific language to be used.

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

175. According to EEI, NERC should be permitted to provide, if the Commission's guidance for modification of a proposed Reliability Standard is not adopted in the Reliability Standard development procedure, an explanation for that outcome when it submits the modified standard to the Commission for approval. Constellation asks the Commission to clarify that, if the ERO Reliability Standards development process does not result in a Reliability Standard that includes the Commission's proposed modifications, the existing Reliability Standard would remain in effect until such time as NERC proposes and the Commission approves a different Reliability Standard (approved through the Reliability Standards development process).

176. Manitoba and Northwest Requirements Utilities disagree with the Commission's proposal to approve certain Reliability Standards and, separately, direct NERC to make modifications. Some commenters, such as California PUC, Northwest Requirements Utilities and SMA state that the users, owners and operators of the Bulk-Power System should not be expected to comply with Reliability Standards that are not finalized or need modification. Northwest Requirements Utilities contends that complete and clear Reliability Standards and requirements are necessary to fair enforcement, particularly if monetary sanctions may apply. Manitoba and California PUC state that approving Reliability Standards that still require modification would lead to differing interpretations of the Reliability Standards and confusion.

177. CEA asserts that the proposed directives to modify certain Reliability Standards, while not remands, reflect engagement in the standards-setting process that may interfere with the ERO's ability to effectively function as an international body. For example, Manitoba states that the Commission's proposed modifications without industry input may unintentionally place Manitoba in a position where it must recommend that the Government of Manitoba disallow the Commission's prescribed modifications to several NERC Reliability Standards, thus creating discrepancies between Reliability Standards across North America.

178. FirstEnergy agrees with the Commission's rejection of the concept of “conditional approval” in favor of approve but modify to ensure that enforceable standards are in place. However, it asks that the Commission consider waiving, or at least substantially reducing, penalties for violations of some enforceable, but yet-to-be-completed or modified Reliability Standards because compliance with such Reliability Standards may prove difficult to determine. FirstEnergy therefore suggests that the Commission exercise due discretion in enforcing affected Reliability Standards, especially where the Commission itself has found that a standard is incomplete or ambiguous. International Transmission agrees that in instances where the Commission has proposed material changes to a Reliability Standard and its associated measurements, risk factors and Levels of Non-Compliance, it may be appropriate for the ERO to exercise enforcement discretion on a case-by-case basis.

179. SoCal Edison is concerned that entities may not have an opportunity to (1) review the Reliability Standards that are adopted in the Final Rule and (2) make any necessary changes in their operating or planning practices in order to incorporate differences between the NOPR and the Final Rule. SoCal Edison recommends the Commission specifically state the “effective date” for compliance with each Reliability Standard in its Final Rule. SoCal Edison is concerned because some standards have a proposed NERC “effective” date after the Final Rule.

180. Northern Indiana states it is concerned how a June 2007 effective date will impact electric system reliability during the critical summer peak demand period, particularly given the many problems with the standards that have been identified. Northern Indiana believes the Commission's current actions may, in the near term, create a lower probability of success in achieving the Commission's stated objectives. Northern Indiana suggests that the traditional summer peak season is not a good time to implement broad changes in electric system operations, procedures and protocols.

181. NRECA states it is concerned by the NOPR's efforts to establish specific one and three year time frames for resolution of various matters. It states that the Commission is authorized to comment on priorities and suggest timing, it must allow NERC to follow its ANSI-certified Reliability Standards development process.

182. NERC requests that the Commission provide a directive in the Final Rule requiring NERC to address both the Commission's concerns with the existing Reliability Standards and all comments filed in this rulemaking proceeding suggesting specific improvements to the Reliability Standards. NERC states that if the Commission acts on the views expressed on a specific Reliability Standard by an individual commenter in this rulemaking, it may encourage others to avoid participating in the NERC process and instead wait until a proposed new or modified Reliability Standard reaches the Commission approval stage to express their views on the standards. NERC states that no commenter should be entitled to have its comments on a specific Reliability Standard resolved by the Commission in this rulemaking proceeding.

183. NERC maintains that referring all comments to the NERC Reliability Standards development process for resolution is consistent with NERC's obligation to facilitate an open stakeholder process for the development of Reliability Standards. NERC asserts that it gives fair consideration to all comments and objections on a proposed new or revised Reliability Standard and such comments are either resolved to the satisfaction of the commenter, or reasons are stated as to why the commenter's recommendation should not be adopted.

b. Commission Determination

184. The Commission affirms the four possible courses of action that it will take with regard to each proposed Reliability Standard: (1) Approve; (2) approve as mandatory and enforceable; and direct modification pursuant to section 215(d)(5); (3) request additional information; or (4) remand. Each course of action is justified and has a sound basis in the statute. Xcel questions the legality of the second option above, which it incorrectly equates to “conditional acceptance.” Rather, as explained in the NOPR, [88] the Commission is taking two independent actions, both authorized by the statute. First, we are exercising our authority, contained in section 215(d)(2) of the FPA, to approve a proposed Reliability Standard. Second, we are directing the ERO to submit a modification of the Reliability Standard to address specific issues or concerns identified by the Commission, pursuant to section 215(d)(5) of the FPA. [89] Accordingly, we reject Xcel's contention and adopt the NOPR proposal on this matter.

185. With regard to the many commenters that raise concerns about the prescriptive nature of the Commission's proposed modifications, the Commission agrees that a direction for modification should not be so overly prescriptive as to preclude the consideration of viable alternatives in the ERO's Reliability Standards development process. However, in identifying a specific matter to be addressed in a modification to a Reliability Standard, it is important that the Commission provide sufficient guidance so that the ERO has an understanding of the Commission's concerns and an appropriate, but not necessarily exclusive, outcome to address those concerns. Without such direction and guidance, a Commission proposal to modify a Reliability Standard might be so vague that the ERO would not know how to adequately respond.

186. Thus, in some instances, while we provide specific details regarding the Commission's expectations, we intend by doing so to provide useful guidance to assist in the Reliability Standards development process, not to impede it. [90] We find that this is consistent with statutory language that authorizes the Commission to order the ERO to submit a modification “that addresses a specific matter” if the Commission considers it appropriate to carry out section 215 of the FPA. [91] In the Final Rule, we have considered commenters' concerns and, where a directive for modification appears to be determinative of the outcome, the Commission provides flexibility by directing the ERO to address the underlying issue through the Reliability Standards development process without mandating a specific change to the Reliability Standard. Further, the Commission clarifies that, where the Final Rule identifies a concern and offers a specific approach to address the concern, we will consider an equivalent alternative approach provided that the ERO demonstrates that the alternative will address the Commission's underlying concern or goal as efficiently and effectively as the Commission's proposal.

187. Consistent with section 215 of the FPA and our regulations, any modification to a Reliability Standard, including a modification that addresses a Commission directive, must be developed and fully vetted through NERC's Reliability Standard development process. The Commission's directives are not intended to usurp or supplant the Reliability Standard development procedure. Further, this allows the ERO to take into consideration the international nature of Reliability Standards and incorporate any modifications requested by our counterparts in Canada and Mexico. Until the Commission approves NERC's proposed modification to a Reliability Standard, the preexisting Reliability Standard will remain in effect.

188. We agree with NERC's suggestion that the Commission should direct NERC to address NOPR comments suggesting specific new improvements to the Reliability Standards, and we do so here. We believe that this approach will allow for a full vetting of new suggestions raised by commenters for the first time in the comments on the NOPR and will encourage interested entities to participate in the ERO Reliability Standards development process and not wait to express their views until a proposed new or modified Reliability Standard is filed with the Commission. As noted throughout the standard-by-standard analysis that follows, various commenters provide specific suggestions to improve or otherwise modify a Reliability Standard that address issues not raised in the NOPR. In such circumstances, the Commission directs the ERO to consider such comments as it modifies the Reliability Standards during the three-year review cycle contemplated by NERC's Work Plan through the ERO Reliability Standards development process. The Commission, however, does not direct any outcome other than that the comments receive consideration.

189. We disagree with commenters, such as Xcel, suggesting that the Commission should not approve Reliability Standards that we require NERC to modify. The Commission is only approving those Reliability Standards that it has determined to be just, reasonable, not unduly discriminatory or preferential, and in the public interest. As discussed more fully in the discussion of the individual Reliability Standards, we have determined that each approved Reliability Standard is sufficiently clear and independently enforceable. Because we believe that these Reliability Standards are enforceable as written, the Commission will not exempt them from enforcement.

190. The Commission disagrees with Northern Indiana that the Reliability Standards should not be implemented in summer of 2007. [92] Most or all users, owners and operators of the Bulk-Power System have participated in NERC's voluntary reliability regime for years and are familiar with the proposed Reliability Standards. Others have had notice of the Reliability Standards since they were filed by NERC in April 2006. We are not persuaded that making Reliability Standards enforceable, most of which were being complied with on a voluntary basis, will require broad changes in electric system operations, procedures and protocols. Therefore, we do not see any reason to further delay implementation of the mandatory Reliability Standards.

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

192. NRECA's assertion that the Commission should not establish timelines to resolve matters is a collateral attack on Order No. 672. In that order, the Commission adopted its regulations to provide that the Commission, when ordering the ERO to submit to the Commission a proposed Reliability Standard or proposed modification to a Reliability Standard that addresses a specific matter, may order a deadline by which the ERO must submit a proposed or modified Reliability Standard. [93]

3. Prioritizing Modifications to Reliability Standards

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

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

195. In addition, the NOPR proposed that the ERO promptly address certain proposed modifications that are not necessarily identified as “high priority” but may be addressed in a relatively short time frame because the proposed modifications are relatively minor or “administrative” in nature. The NOPR further proposed that the ERO develop a detailed, comprehensive Work Plan to address all of the modifications that are directed pursuant to a Final Rule. The Work Plan would take a staggered approach and complete all the proposed modifications within either two or three years from the effective date of the Final Rule.

196. As noted above, on December 1, 2006, NERC submitted its Work Plan as an informational filing. According to the Work Plan, NERC will revise the existing Reliability Standards to incorporate improvements. A total of 31 different projects will be completed over a three-year period. [96] Some of the projects address revising a single Reliability Standard. The largest project includes revising 19 Reliability Standards focusing on related topics. NERC asserts that grouping the Reliability Standards in this manner will be the most efficient use of the resources and will allow consistency in requirements on related standards. NERC states that the Work Plan incorporates modifications that were proposed in the NOPR, but it will modify its Work Plan to align it with the modifications the Commission orders in the Final Rule. In addition, the Work Plan will remain dynamic as new Reliability Standards are proposed and priorities evolve. The Work Plan will be updated on an annual basis, and more frequently if needed.

197. According to the Work Plan, NERC will periodically report progress and revisions to the Work Plan and timetable to the Commission. NERC's intent is to provide accountability for the revision and development of Reliability Standards, while recognizing it is impossible to have a fixed schedule when working in a consensus-driven process addressing complex technical matters.

a. Comments

198. NERC states that it is pleased that the Commission did not propose specific deadlines in the NOPR for completing the directives to improve the Reliability Standards. NERC requests that the Commission not state specific delivery dates, because developing consensus Reliability Standards on complex technical matters within fixed time frames may not be realistic in all cases. NERC states that it will report the reasons for any delays in the schedule and will work to ensure that no unnecessary delays occur due to lack of attention or effort.

199. NERC expresses concern that the Commission suggests in the NOPR that it may direct some early modifications to the Reliability Standards that appear to provide quick results. [97] According to NERC, because of the procedural requirements of the Reliability Standards development process, this would delay work that is more important. NERC states that it can make such changes quickly for a particular Reliability Standard if there are no other changes to that standard. However, NERC's Work Plan contemplates that almost every Reliability Standard is to be upgraded; modifying each standard in multiple steps would add significant delay.

200. APPA similarly cautions the Commission that the industry does not have unlimited ability to simultaneously reevaluate the Reliability Standards, prepare for NERC's and the Regional Entities' compliance monitoring and enforcement programs, and actually plan and operate their utility systems on a reliable basis. According to APPA, NERC should promptly address the administrative elements of those Reliability Standards that are now at best incomplete, with missing Compliance Measures, Levels of Non-Compliance and Violation Risk Factors. NERC must also deal with the regional fill-in-the-blank standards and criteria that have not yet been submitted to either NERC or to the Commission for review and approval.

201. International Transmission states that the Commission should not direct NERC to make changes to the Reliability Standards within a specific time frame because this would circumvent the Reliability Standard development process. It asks the Commission to instruct the ERO to initiate the Reliability Standards development process in a time frame that would likely result in their presentation to the Commission by a desired date, acknowledging that a revised Reliability Standard may not reach industry consensus and thus not meet the Commission's desired time frame. Further, International Transmission believes that the priority of a Reliability Standard for subsequent modification should be based on the standard's “Violation Risk Factor.” Reliability Standards that have the greatest impact on bulk electric system reliability should be addressed first. All high risk requirements should be addressed in the 2007 Work Plan. International Transmission states the addition of Measures and Levels of Non- Compliance is neither minor nor administrative in nature, although designated by the Commission as such and called for an accelerated time period for their addition.

202. MRO recommends that the Commission place a greater emphasis on directing NERC to develop clear and measurable Requirements. If the Requirements are not clear and measurable, the Measures and Levels of Non-Compliance will be fundamentally flawed. MRO also states that there are numerous Requirements that are now part of the Reliability Standards that came from elements of the former NERC Operating Manual that were never intended as Requirements. It believes that this, in part, has created certain difficulties that have resulted in a lack of Measures or Levels of Non-Compliance in the Reliability Standards. MRO provides examples of such difficulties in its comments regarding specific Reliability Standards. MRO suggests grouping each Requirement with its associated Measure and Level of Non-Compliance thus making it clear to the user, owner or operator as to which Requirements, Measures and Levels of Non-Compliance are related thereby reducing confusion.

203. APPA and Alcoa state that the Commission did not give sufficient time for comments on NERC's submitted Work Plan. APPA notes that the Work Plan will have to be revised following issuance of the Final Rule.

b. Commission Determination

204. Given the concerns raised by commenters, the Commission will not adopt the NOPR's proposal to direct some early modifications to the Reliability Standards. We agree with NERC that modifying each Reliability Standard first to address administrative concerns, then sending it back to the Reliability Standards development process to address any modifications directed by the Commission or requested by stakeholders, might lead to an unacceptable delay.

205. While the Commission agrees with International Transmission that a good starting point for prioritizing modifications to a Reliability Standard could be based on the Reliability Standard's “Violation Risk Factor,” the Commission will not mandate that the ERO do so. The ERO should take into account the views of its stakeholders, including the concerns raised in this proceeding by APPA, International Transmission and MRO, in revising its Work Plan following issuance of this Final Rule.

206. In Order No. 890, the Commission directed public utilities, working through NERC, to modify the ATC-related Reliability Standards within 270 days of publication of Order No. 890 in the Federal Register. [98] Our action there affects approximately nine MOD Reliability Standards and one FAC Reliability Standard that are before us in this proceeding. The ERO must submit its revised Work Plan within 90 days of the effective date of the Reliability Standards approved in this order as an informational filing to: (1) Reflect modification directives contained in the Final Rule; (2) include the timeline for completion of ATC-related Reliability Standards as ordered in Order No. 890 and (3) account for the views of its stakeholders, including those raised in this proceeding.

207. The Commission disagrees with NERC that we should not set specific delivery dates. A Work Plan with specific target dates will provide a valuable tool and incentive to timely address the modifications directed in this Final Rule. We note that the ERO previously prepared and submitted to the Commission for informational purposes one iteration of such a Work Plan that identifies target dates for the modification of Reliability Standards. Accordingly, we direct the ERO to submit as an informational filing, within 90 days of the effective date of this Final Rule, a Work Plan that identifies a plan for addressing the modifications to the Reliability Standards directed by the Commission in this Final Rule and a schedule with delivery dates for completing such modifications. The ERO should make every effort to meet such delivery dates. However, we understand that there may be certain cases in which the ERO is not able to meet a Commission's deadline. In those instances, the ERO must inform the Commission of its inability to meet the specified delivery date and explain why it will not meet the deadline and when it expects to complete its work.

4. Trial Period

208. NERC and some commenters to the Staff Preliminary Assessment recommended that the Commission establish a “trial period” during which time the ERO would determine, but not collect, monetary penalties. In the NOPR, the Commission expressed concern that a trial period that commences with the effective date of mandatory and enforceable Reliability Standards may interfere with their being made effective by summer 2007. Thus, the NOPR did not propose a trial period. [99]

209. However, the Commission recognized that there are entities that have not historically participated in the pre-existing voluntary reliability system (including some relatively small entities) that may not be familiar with what is required for compliance with the proposed mandatory Reliability Standards. For such entities, the NOPR proposed that the ERO and Regional Entities use their discretion in imposing penalties on such entities for the first six months the Reliability Standards are in effect. However, the Commission, the ERO and the Regional Entities would still retain the authority to impose penalties on such entities if warranted by the circumstances.

a. Comments

210. Most commenters request that the Commission reconsider the proposal to reject a trial period during which the Reliability Standards are mandatory and enforceable but during which penalties would not be assessed for violating a Reliability Standard. [100] EEI, for example, notes that the compliance enforcement program and the delegation agreements have not yet been approved by the Commission and there may be a short time between their approval and the projected start date for enforcing the Reliability Standards. Therefore, commenters generally state that a trial period is appropriate to ensure that the compliance monitoring and enforcement processes work as intended and that entities have time to implement new processes, such as required data systems; after June 2007, commenters generally state that NERC and the Regional Entities would be able to require remedial actions where there is an immediate actual or potential risk to reliable interconnected operations. Further, some state that a trial period would allow NERC to resolve issues with unfinished standards or ambiguous standards for which the Commission has directed improvements. If the Commission rejects a six-month trial period, several entities, such as EEI, PGE, Xcel and NYSRC, request that the Commission extend NERC's discretionary enforcement to all entities, not just those new to the Reliability Standards.

211. NPCC essentially agrees with the Commission that there should be no trial period, but if the definition of Bulk-Power System is substantially altered to draw in a broad range of entities that have not traditionally been subject to pre-existing reliability standards, a transition period is appropriate to bring them into compliance. Where a Reliability Standard has missing or incomplete compliance measures, ATC states that the Commission should make these standards mandatory to avoid gaps, but not assess monetary penalties for non-compliance. ATC agrees with the Commission that the new mandatory reliability regime should be operational by June 2007, noting that it has been over three years since the August 2003 Blackout and over a year since EPAct 2005 was enacted.

212. Several entities state that the Commission's proposal to allow the ERO and Regional Entities discretion in setting penalties does not go far enough, even if it is applied to all users, owners and operators of the Bulk-Power System. For example, SERC maintains that its proposed delegation agreement and the NERC Compliance Monitoring and Enforcement Program may not allow discretion in imposing penalties.

213. NERC states that it understands and supports the importance the Commission places on the ERO having the ability to impose a financial penalty if a Bulk-Power System user, owner or operator violates a mandatory Reliability Standard that is in effect, especially for egregious behavior. However, NERC continues to maintain that a validation period for the compliance process and the calculation of penalties is important and proposes a modified approach to that taken by the Commission. NERC asks the Commission to authorize NERC and the Regional Entities to exercise discretion to calculate financial penalties, but not collect them in the case of most violations through December 31, 2007. At the same time it asks the Commission to specify that in a situation in which an entity violates a clear and well-understood Reliability Standard that causes a significant disturbance on the Bulk-Power System, or in the face of other aggravating circumstances such as repeated or intentional violations, the ERO and the Regional Entities would have the authority and responsibility to hold the offending entity fully accountable for the violation, by the assessment of financial penalties.

214. NERC states that this alternative approach is supported by the newness of the compliance enforcement program, the Sanctions Guidelines and the penalty matrix, and the Violation Risk Factors, which have not been approved by the Commission. Further, NERC claims that initiating operations under mandatory Reliability Standards with the collection of penalties as the rule rather than the exception may increase the risk of numerous legal challenges occurring in the early stages of implementing mandatory Reliability Standards, whereas NERC would expect a rapid decline in such challenges after its proposed validation period. In a reply comment, Xcel supports NERC's proposed approach.

215. If the Commission rejects NERC's proposed modified approach, NERC asks that it and the Regional Entities be given broad discretion in setting penalties during this time period and that this discretion not be limited to small entities or those who are new to Reliability Standards. Avista/Puget also urges the Commission, the ERO and the Regional Entities to exercise enforcement discretion more broadly than proposed in the NOPR. Penalties should be waived for an initial period in several situations, including where a Reliability Standard is applied based on new or different interpretations.

216. Some commenters request that the Commission grant a longer trial period in certain cases. For instance, TANC believes that for smaller entities the Commission should, at a minimum, adopt a trial period of at least one year to provide adequate time to evaluate and comply with the new mandatory Reliability Standards. Bonneville and NPCC suggest that, for Reliability Standards that have an annual reporting requirement, the compliance cycle should start on June 2007 so that a Reliability Standard that relies on data reporting back into the prior year should have an initial compliance measurement date of June 2008. AMP-Ohio states that the Commission's proposal does not go far enough and suggests a “ramp-up” period for entities that are new to standards, through and including the entity's first compliance audit or, if the Commission rejects this proposal, the Commission should extend the trial period from six to twelve months. Reliant also advocates a phase-in of penalties over six to twelve months, with an increasing scale of penalties over time.

217. Portland General and Tacoma request that the Commission institute a one-year trial period to allow the industry time to finalize the language of the mandatory Reliability Standards and to allow users, owners and operators time to adapt to the final language. For any Reliability Standard that requires modification, Tacoma requests that the Commission provide a six-month trial period beyond the date when the Reliability Standard is completed. Bonneville asks that the Commission extend the trial period for Reliability Standards that have missing or ambiguous measures or severity levels until those issues are resolved. National Grid states that enforcement discretion should not be limited in scope or duration and should be extended to any situation in which a Reliability Standard is applied in a novel manner, including when a Reliability Standard is interpreted for the first time.

218. PGE asserts that NERC and the Regional Entities should have discretion in imposing fines for violations of Reliability Standards during a transition period. Where an entity shows a good faith effort to comply with a new or changed Reliability Standard promptly and thoroughly, NERC and/or the Regional Entity should be permitted to consider those efforts in assessing fines. PGE suggests a transition period of three to six months. Without such discretion, entities may be pressured to implement Reliability Standards hastily and inadequately. PGE also notes that some entities in WECC have voluntarily participated in WECC's enforcement program. The new regime entails procedural and substantive changes. Entities that have complied voluntarily should not be penalized by denying them an opportunity to adjust.

219. WECC states that it continues to believe that a trial period of more than six months is appropriate, but it is not requesting that the Commission revisit its decision on this issue. WECC asks that Regional Entities have somewhat greater flexibility in monitoring and enforcing compliance during the initial period of implementation. According to WECC, the Commission should recognize that, in the early stages of implementation, penalties should be reserved for clear situations where Registered Entities are refusing to comply. Unreasonably harsh enforcement in the early stages of implementation may damage the current level of reliability by diverting resources away from developing solutions in order to avoid fines and support litigation. This flexibility should continue beyond six months after the effective date, if necessary, for those Reliability Standards requiring modification, until such modifications have become effective.

220. According to WECC, it is extremely important that United States, Canadian and Mexican authorities enforce their respective standards within WECC in a way that avoids conflicting obligations. WECC thus suggests that the Commission grant WECC substantial discretion to focus on education and facilitation of compliance with NERC Reliability Standards while it seeks to promote consistent enforcement internationally.

b. Commission Determination

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

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

223. By directing the ERO and Regional Entities to focus their resources on the most serious violations through the end of 2007, the ERO and Regional Entities will have the discretion necessary to assess penalties for such violations, while also having discretion to calculate a penalty without collecting the penalty if circumstances warrant. Further, even if the ERO or a Regional Entity declines to assess a monetary penalty during the initial period, they are authorized to require remedial actions where a Reliability Standard has been violated. Furthermore, where the ERO uses its discretion and does not assess a penalty for a Reliability Standard violation, we encourage the ERO to establish a process to inform the user, owner or operator of the Bulk-Power System of the violation and the potential penalty that could have been assessed to such entity and how that penalty was calculated. We leave to the ERO's discretion the parameters of the notification process and the amount of resources to dedicate to this effort. Moreover, the Commission retains its power under section 215(e)(3) of the FPA to bring an enforcement action against a user, owner or operator of the Bulk-Power System.

224. The Commission believes that the goal should be to ensure that, at the outset, the ERO and Regional Entities can assess a monetary penalty in a situation where, for example, an entity's non-compliance puts Bulk-Power System reliability at risk. Requiring the ERO and Regional Entities to focus on the most serious violations will allow the industry time to adapt to the new regime while also protecting Bulk-Power System reliability by allowing the ERO or a Regional Entity to take an enforcement action against an entity whose violation causes a significant disturbance. Our approach strikes a reasonable balance in ensuring that the ERO and Regional Entities will be able to enforce mandatory Reliability Standards in a timely manner, while still allowing users, owners and operators of the Bulk-Power System time to acquaint themselves with the new requirements and enforcement program. In addition, our approach ensures that all users, owners and operators of the Bulk-Power System take seriously mandatory, enforceable reliability standards at the earliest opportunity and before the 2007 summer peak season.

225. National Grid, among others, states that the Commission should allow enforcement discretion on an ongoing basis, for example, when the ERO or a Regional Entity interprets a Reliability Standard for the first time. The Commission agrees that, separate from our specific directive that all concerned focus their resources on the most serious violations during an initial period, the ERO and Regional Entities retain enforcement discretion as would any enforcement entity. Such discretion, in fact, already exists in the guidelines; as we stated in the ERO Certification Order, the Sanction Guidelines provide flexibility as to establishing the appropriate penalty within the range of applicable penalties. [103]

5. International Coordination

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

a. Comments

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

228. EEI and National Grid state that it is not sufficient to coordinate remands through NERC alone because both the Commission and Canadian provincial authorities have the ultimate say in approving applicable Reliability Standards. They advocate that the various regulators commit to coordinate through a formal mechanism, such as a memorandum of understanding. According to EEI, the Commission should coordinate with its international counterparts when directing modifications to Reliability Standards to ensure that the resulting Reliability Standards are uniform to the greatest extent possible. NPCC adds that the Commission should coordinate with its international counterparts when proposing to hold, remand or reject a proposed Reliability Standard to avoid inconsistencies in Reliability Standards application.

229. National Grid states that, where similar interpretations and modifications to Reliability Standards are not adopted by the provincial authorities in Canada, there is potential for conflicting requirements for interconnected facilities. The Alberta ESO is also concerned that, due to regulatory/legislative requirements and industry structures in Canada, some of the Reliability Standards may not be implemented as they are written. Therefore it requests that the Commission require that the international coordination process include a provision where variances are identified by these international governmental authorities to minimize the possibility of a governmental authority remanding a Reliability Standard. According to Alberta ESO, while the goal should be consistent, North America-wide Reliability Standards, there will be instances where this is not achievable.

230. WIRAB advises that some Canadian provinces or Mexican authorities may approve NERC-proposed Reliability Standards with changes or modifications. It is important to allow minor variations across such jurisdictions to minimize the possibility of a governmental authority remanding a Reliability Standard. According to WIRAB, the goal should be a consistent system throughout North America with enough flexibility for some jurisdictional variation when uniformity is not immediately possible.

b. Commission Determination

231. In the January 2007 Compliance Order, the Commission stated that, to minimize the possibility of a governmental authority directing a remand, it seemed appropriate for such governmental authorities to have an opportunity to provide NERC with input prior to its filing for governmental approval of a proposed Reliability Standard. [107] In that order, the Commission agreed with NERC's proposal to facilitate informal conferences to provide an opportunity for governmental authorities to consult with NERC and stakeholder representatives regarding Reliability Standard development work-plans, objectives and priorities, and emerging Reliability Standards. [108] While we did not initiate a formal mechanism for coordination as EEI and National Grid now suggest, we did state that we anticipate that the Commission and counterpart governmental authorities in Canada and Mexico will convene regular meetings to coordinate on issues relating to reliability. We reaffirm that approach as an appropriate framework for addressing matters of international coordination in the context of continent-wide Reliability Standards.

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

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

E. Common Issues Pertaining to Reliability Standards

1. Blackout Report Recommendation on Liability Limitations

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

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

a. Comments

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

b. Commission Determination

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

2. Measures and Levels of Non-Compliance

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

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

240. The NOPR explained that the common format of NERC's proposed Reliability Standards calls for a “data retention” metric. Yet, some proposed Reliability Standards either do not contain a data retention requirement or state that no record retention period applies. In the NOPR, the Commission requested comment on: (1) Whether the retention time periods specified in various Reliability Standards proposed by NERC are sufficient to foster effective enforcement and (2) what, if any, additional records retention requirements should be established for the proposed Reliability Standards.

a. Improving Measures and Levels of Non-Compliance

i. Comments

241. A number of commenters raise concerns regarding the adequacy of current Measures and Levels of Non-Compliance. Some commenters, such as Nevada Companies, state that some Reliability Standards do not need multiple Measures and multiple Levels of Non-Compliance when such items do not fit the context of the specific Reliability Standard. According to Nevada Companies, some proposed Reliability Standards are more like business practices that are susceptible to a pass/fail test, and are not necessarily amenable to multiple Measures and Levels of Non-Compliance. Progress and Xcel maintain that Measures and Levels of Non-Compliance do not necessarily need to be added to every Reliability Standard.

242. Constellation is concerned that the Levels of Non-Compliance do not appear to be based on objective criteria, but rather appear to be based on arbitrary criteria and assumptions regarding the impact on reliability, which could lead to penalties that are excessive compared to the violation. MISO states that the original intent of the Levels of Non-Compliance was to assign a scale based on the impact on the Interconnection. MISO asserts that many Requirements are rated at too high a level and that many events that would be rated “level 4” are really just administrative requirements. It asserts that there are more “level 4” events than other categories, when logic would imply a pyramid structure with only a few items at the highest “level 4.” MISO states there should be a simplified process that measures the true impact on reliability. MISO and Dynegy state that there should also be an “administrative infraction” category created in addition to the current “low,” “medium” and “high,” so that the enforcement of supporting tasks can be handled expeditiously.

243. NYSRC states that, in NERC's rush to file with the Commission the 20 revised Reliability Standards with new Measures and Levels of Non-Compliance, the revised Reliability Standards were submitted to the NERC ballot body as a group, rather than individually. It maintains that the group treatment prevented stakeholders from providing the careful attention that each revised Reliability Standard deserves. NYSRC believes that, as a result, Requirements for a number of these Reliability Standards are flawed. While their prompt approval may be justified to have them in place for the upcoming summer, there is not a sufficient basis for the Commission to conclude that the weaknesses identified in these 20 Reliability Standards have been adequately addressed. NYSRC recommends that the Commission approve the 20 revised Reliability Standards and direct the ERO to more carefully address the weaknesses identified in those standards and to individually submit each revised standard to a ballot for separate consideration.

244. MISO, International Transmission and Constellation also raise concerns with NERC's Violation Risk Factors. They are concerned that risk is, in some cases, being confused with importance. For example, MISO states that NERC appears to be assigning risk to every sentence in each proposed Reliability Standard, including explanatory information and administrative requirements, thereby confusing risk with importance. MISO states that, while there may be many things that a transmission operator does that are important, failure to do an important thing one time would not necessarily jeopardize the Interconnection or cause a cascading failure.

245. MISO believes the definition of risk should reflect the likelihood that something serious is likely to happen if an event occurs. International Transmission, Constellation and MISO believe that a high risk event should, in and of itself, pose a significant threat to reliability and should not assume that multiple events occur simultaneously. According to MISO, only a small number of Requirements in the Reliability Standards fit the true definition of high risk. Constellation maintains that rating too many Requirements as high risk will water down the Requirements, and could shift the focus of attention away from the truly high risk Requirements, leading to a less effective, less efficient reliability program.

ii. Commission Determination

246. With regard to the comments of Nevada Companies, Progress and others, we believe that the ERO should have flexibility in initially developing appropriate Measures and Levels of Non-Compliance. For example, the ERO in the first instance should determine whether a Measure is necessary for every Requirement of a particular Reliability Standard, or whether every Reliability Standard must have the same number of Levels of Non-Compliance. Entities interested in developing meaningful Measures and Levels of Non-Compliance should, we find, participate in the ERO's Reliability Standards development process to ensure that their opinions are considered.

247. With regard to the concerns of MISO and Constellation, we agree as a general principle that Levels of Non-Compliance should be based on objective criteria and that a “level 4” violation should reflect a commensurate level of severity in its impact on Bulk-Power System reliability. However, we will allow the ERO in the first instance to determine whether specific revisions to particular Reliability Standards are needed to address these concerns. While we consider the appropriateness of Measures and Levels of Non-Compliance in our standard-by-standard review, we believe in the first instance it is the responsibility of the ERO to develop meaningful Measures and Levels of Non-Compliance, and those seeking to influence the process, as we have already found, should participate in the ERO's Reliability Standards development process. Likewise, we leave it to the ERO to determine initially whether there is any merit in developing a category of “administrative infraction” as suggested by some commenters.

248. The Commission agrees with NYSRC that, as a general matter, each Reliability Standard should be independently balloted in the Reliability Standards development process. However, the Commission will not require the ERO to resubmit each of the 20 revised Reliability Standards to the Reliability Standards development process for separate consideration. We do not believe such an action is required by the statute and would otherwise unnecessarily delay implementation of the proposed Reliability Standards. However, we expect that the ERO's Reliability Standards development process will provide adequate opportunity for independent consideration by stakeholders of each standard under consideration in the future.

249. MISO, International Transmission and Constellation raise concerns with NERC's Violation Risk Factors. The NERC board approved the Violation Risk Factors for Version 0 Reliability Standards and submitted them to the Commission on February 23, 2007. The Commission is reviewing the Violation Risk Factors in a seprate proceeding in Docket No. RR07-9-000. Thus, these issues are not ripe for consideration in this Final Rule. MISO, International Transmission and Constellation may raise concerns they have with the Violation Risk Factors in that separate proceeding.

b. Enforcement Implications

i. Comments

250. Certain commenters, such as EEI, Northeast Utilities, APPA and TAPS, state that Reliability Standards that lack clear Measures or Levels of Non-Compliance should not be fully enforced because they are not just and reasonable and raise potential due process concerns. APPA states that this is equally true of Reliability Standards that lack Violation Risk Factors or Violation Severity Levels because there is not proper notice as to the amount or range of monetary penalties to be assessed for a particular violation. APPA recommends that the Commission approve Reliability Standards that lack Measures and Violation Severity Levels, but that, until the deficiencies are corrected, require NERC and Regional Entities to waive imposition of monetary penalties. APPA would, however, reserve the Commission's right to impose monetary sanctions where warranted and also require compliance with NERC and Regional Entity remedial action directives for these Reliability Standards.

251. WIRAB disagrees that Reliability Standards can be consistently enforced based solely on sufficiently clear and enforceable Requirements. According to WIRAB, Levels of Non-Compliance are needed to inform parties of the consequences of non-compliance. WIRAB is concerned that a complex penalty structure that requires Regional Entities to consider multiple subjective mitigating and aggravating factors will compound the problems of missing and ambiguous Measures and Levels of Non-Compliance. A simple penalty structure would reduce enforcement ambiguities, increase uniformity and promote greater clarity. FirstEnergy states that, without Measures and Levels of Non-Compliance, a Reliability Standard cannot meet the Commission's requirement that a Reliability Standard must have a “clear criterion or measure of whether an entity is in compliance with a proposed Reliability Standard.” [121]

252. Progress and Xcel state that the Commission should clarify that the Measures and Levels of Non-Compliance are included solely for guidance and that only violations of the Requirements are subject to penalties. Portland General maintains that the Measures are an integral part of each Reliability Standard because entities will need to know the Measures so that they can build them into their compliance efforts from the beginning. In a similar vein, National Grid states that the lack of clear Measures or Levels of Non-Compliance also makes it difficult for users, owners and operators to tailor their businesses and practices toward compliance or to track ongoing compliance.

ii. Commission Determination

253. The Commission disagrees with commenters that a Reliability Standard cannot reasonably be enforced, or is otherwise not just and reasonable, solely because it does not include Measures and Levels of Non-Compliance. The Commission adopts the position it took in the NOPR that, while Measures and Levels of Non-Compliance provide useful guidance to the industry, compliance will in all cases be measured by determining whether a party met or failed to meet the Requirement given the specific facts and circumstances of its use, ownership or operation of the Bulk-Power System. As we explained in the NOPR, and reiterate here:

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

254. APPA, WIRAB and others contend that, without Measures and Levels of Non-Compliance, a Reliability Standard should not be enforced. We disagree. Where a Reliability Standard has Requirements that are sufficiently clear so that an entity is aware of what it must do to comply, sufficient notice has been provided. While it can be helpful to provide additional guidance regarding the amount or range of monetary penalties that may be assessed for a particular violation, the absence of such information is not a defect that renders a Reliability Standard unenforceable. Where the Requirement in a Reliability Standard is sufficiently clear, an entity will know what it should be doing to comply and will know that there are consequences for failure to comply. Therefore, where a Requirement in a Reliability Standard is sufficiently clear, we approve the Reliability Standard even though it may lack Measures or Levels of Non-Compliance. Where a Reliability Standard can be improved by providing missing Measures or Levels of Non-Compliance or by clarifying ambiguities with respect to Measures or Levels of Non-Compliance, we approve the Reliability Standard and concurrently direct NERC to modify it accordingly. [123]

255. In response to FirstEnergy, where the Requirement in a Reliability Standard is sufficiently clear, that Reliability Standard meets the requirement that it must have a “clear criterion or measure of whether an entity is in compliance with a proposed Reliability Standard.” The fact that NERC, in certain circumstances, did not include Measures and Levels of Non-Compliance does not make an otherwise clear Requirement unenforceable. Neither section 215 nor the Commission's regulations require the level of specificity sought by FirstEnergy in order for a Reliability Standard to be enforceable.

256. Progress and Xcel seek clarification that Measures and Levels of Non-Compliance are included solely for guidance and that only violations of the Requirements are subject to penalties. While the Commission generally agrees that it is a violation of the Requirements that is subject to a penalty, we recognize that because Measures are intended to gauge or document compliance, failure to meet a Measure is almost always going to result in a violation of a Requirement.

257. While we applaud NERC for adding additional levels of detail to its compliance enforcement program, we note that NERC and the Regional Entities should have further guidance as to how to use their enforcement discretion from the Commission's Policy Statement on Enforcement. [124] Further, if NERC does not submit Violation Risk Factors and Violation Severity Levels before NERC's enforcement program becomes effective, the Commission has reserved the ability to take appropriate action to ensure that the penalty-setting process described in the Sanction Guidelines is operative. [125]

c. Data Retention

i. Comments

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

259. SoCal Edison supports the data retention requirements in the Reliability Standards. APPA and SERC recommend that data retention requirements should be stated in each Reliability Standard and determined on a case-by-case basis through the Reliability Standards development process.

260. SERC agrees with NERC that an appropriate retention period is five years unless otherwise specified in a Reliability Standard. ISO-NE submits that any data retention policy established by the ERO should be in line with the five year civil penalty statute of limitations for violations of NERC Standards, while APPA cautions that detailed operational data may be so voluminous that a five-year retention requirement would be burdensome and of questionable value. MRO believes that the Reliability Standards retention period should be commensurate with operating and planning horizons, documentation related to a planning standard should be retained longer and that there should be a retention period of at least three years.

261. FirstEnergy states that individual record retention requirements on a standard-by-standard basis will create confusion and will be difficult to track. It therefore suggests that the Commission establish a uniform records retention standard of “current calendar year plus three years” for all proposed Reliability Standards that include a data retention requirement. Similarly, Entergy states that data retention requirements established for the Reliability Standards should be uniform and asks the Commission to direct the ERO to implement records retention requirements of no longer than three years.

262. International Transmission and Entergy comment that only the relevant core reliability requirements of the Reliability Standards should be subject to data retention requirements. International Transmission states that, in instances where retaining evidence of compliance is impractical or where no evidence exists of compliance, it is appropriate that no documentation be retained. Otherwise the record retention period should be no less than the prevailing audit frequency. Progress and Xcel agree that inclusion of data retention metrics in the Reliability Standards would be useful, but the Commission should make clear that violations of the data retention metrics are not subject to separate penalties under section 215 of the FPA.

ii. Commission Determination

263. The Commission agrees that it is appropriate for each Reliability Standard to have a data retention requirement. We are not persuaded that a one-size fits all approach to data retention is appropriate, however, because different Reliability Standards may require data to be retained for shorter or longer periods. Nor are we persuaded that the Commission should set a data retention requirement for any Reliability Standard for which one is currently lacking. Therefore, the Commission will not prescribe a set data retention period to apply to all Reliability Standards. Instead, the Commission directs the ERO to review and update the data retention requirements in each Reliability Standard as it is reevaluated through its Reliability Standards development process and submit the result for Commission approval. In doing so, NERC should take into account the comments raised in this proceeding and should seek input from other industry stakeholders.

3. Ambiguities and Potential Multiple Interpretations

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

a. Comments

265. NERC maintains that, even if the Commission believes that there is some degree of ambiguity in some of the Reliability Standards, making the Reliability Standards mandatory enables NERC and Regional Entities to respond to questionable performance by clarifying to the responsible entity, and others, on a going-forward basis what behavior would constitute compliance with the Reliability Standards. Thereafter, participants would know how NERC and the Regional Entities were interpreting the Reliability Standards. According to NERC, this information would become part of the public record and help to eliminate any ambiguity as to what constitutes compliant and noncompliant behavior under a Reliability Standard. In contrast, if the Reliability Standards remain voluntary or temporarily unapproved, NERC contends that it and the Regional Entities will lack a legal basis to compel corrective behavior.

266. In contrast, Reliant urges the Commission to either not approve ambiguous Reliability Standards or approve them without subjecting entities to penalties. The level of ambiguity in many cases appears to violate the “just and reasonable” criteria for approval. It states that entities should not be found in violation based on retroactive interpretation of a Reliability Standard.

267. EEI expresses concern that approval and enforcement of a Reliability Standard that includes ambiguous requirements or lacks certain technical features or specificity may raise due process concerns if the required performance or performance measurements are not “clear and unambiguous.” Both in this docket and on a going forward basis, EEI questions whether proposed Reliability Standards with various shortcomings or deficiencies are sufficiently clear to meet the legal standard of review.

268. EEI and Wisconsin Electric state that it is not clear what “common interpretations” the Commission refers to in the NOPR or whether they are accepted or known across the industry. Wisconsin Electric states that common interpretations and best practices must be clearly spelled out and made available for review. These interpretations should be incorporated into the audit guidelines. Further, EEI states that common interpretations should not supersede provisions that are clearly stated in a Reliability Standard. According to EEI, if part of a proposed Reliability Standard is not clear, the NERC Reliability Standards development process should be used to clarify it. Further, EEI maintains that the Commission should require the ERO to review all existing industry sources, such as the NERC glossary or Institute of Electrical and Electronics Engineers (IEEE) standards, to supplement the interpretation of Reliability Standards. Undocumented “common interpretations” should be relied on only as a last resort. Moreover, EEI contends that, if such interpretations are to be used as a basis for assessing compliance and enforcement, they must be clearly spelled out and made available in advance.

269. MISO notes that some Reliability Standards may have portions applicable to five or more entities and that there are situations where a particular functional entity is not mentioned in the “Applicability” section of the Reliability Standard, but they show up in the Requirements. It believes that the industry needs a database-style tool that is a companion to the Reliability Standards that permits any functional entity to sort and find all requirements and supporting compliance information applicable to it. Such a tool would help entities prevent oversights and also help NERC eliminate redundancy in the Reliability Standards.

270. MISO also states that, in developing the Version 0 Reliability Standards, there was a conscious decision to include supporting information in the Reliability Standards themselves. As a result, there is now explanatory material in the Reliability Standards that is presented in context as Requirements. According to MISO, users now are trying to figure out how to measure Requirements that are really supporting text. MISO believes that the process should be simplified by separating each Reliability Standard into its core requirements and supporting information.

271. Similarly, Constellation, International Transmission and Dynegy comment that the Commission should distinguish between those Requirements in each Reliability Standard that are core requirements as opposed to supporting information, an explanatory statement, or an administrative process. International Transmission and Dynegy state that Measures should only apply to these core reliability requirements. Reliant is also concerned that each Reliability Standard contains a great deal of explanatory text, formatted to appear as enforceable obligations.

272. International Transmission, Reliant and MISO note that the proposed Reliability Standards contain many inherently ambiguous phrases or terms that can be misapplied, including “adequate” or “adequately,” “sufficient,” “immediate,” “where technically feasible,” “as soon as possible” and “where practical.” Reliant states that all ambiguous language must be eliminated before penalties can be assessed. MISO and Wisconsin Electric state that, while use of such terms may be acceptable in explanatory information, if a term cannot be definitively and objectively defined, it should not appear in the core Requirements of a Reliability Standard.

273. Alcoa reiterates its concern that the Commission has not defined the target level of reliability of the Bulk-Power System that the Reliability Standards are intended to achieve. Further, Alcoa is concerned that the proposed Reliability Standards are fragmented and overlap and in some cases may result in inconsistent treatment of the same issue. Alcoa states that the ERO should move towards a more encompassing approach for developing Reliability Standards in which a reliability goal is addressed from all aspects in a more consistent manner. Therefore, Alcoa maintains that the Commission should require NERC to engage in advance planning, mapping out what kind of reliability is adequate for the Bulk-Power System and then developing a plan to get there.

b. Commission Determination

274. The Commission finds that it is essential that the Requirements for each Reliability Standard, in particular, are sufficiently clear and not subject to multiple interpretations. Where the Requirements portion of a Reliability Standard is sufficiently clear (and no other issues have been identified), we approve the Reliability Standard. Upon review of the Reliability Standards and the comments submitted in response to the NOPR, the Commission finds that none of the Reliability Standards that we approve today contain an ambiguity that renders it unenforceable or otherwise unjust and unreasonable. As discussed in our standard-by-standard review, each Reliability Standard that we approve contains Requirements that are sufficiently clear as to be enforceable and do not create due process concerns.

275. The underlying assumption of many of the commenters seems to be that the Reliability Standards must spell out in minute detail all factual scenarios that might violate a Requirement and the precise consequences of that violation. But due process requirements do not go so far. Indeed, many government regulatory schemes provide far less specificity in terms of what is required or proscribed, and yet those regulations are routinely enforced. [128] Indeed, many tariffs on file with the Commission do not specify every compliance detail, but rather provide some level of discretion as necessary to carry out a particular act. This does not mean the tariffs are unenforceable; rather, it means that, if a dispute arises over compliance and there is a legitimate ambiguity regarding a particular fact or circumstance, that ambiguity can be taken into account in the exercise of the Commission's enforcement discretion. Therefore, we find that the Reliability Standards must strike a balance between a level of specificity that places users, owners and operators on notice of what is required, and a level of generality that encompasses unanticipated but serious actions or omissions that could affect Bulk-Power System reliability. We are satisfied that the Requirements portions of each Reliability Standard that we approve in this Final Rule appropriately strike this balance.

276. Some commenters argue that certain Reliability Standards require additional specificity or else users, owners and operators will not understand the consequences of a violation. This notion is similarly misplaced because the potential (if not actual) consequences for any violation are clearly spelled out—the statute permits the ERO to assess civil penalties of up to “$1 million per violation, per day” in addition to other remedies. The Commission has explained how it will approach civil penalties in its Enforcement Policy Statement. The ERO has provided guidance in its compliance filings, and will continue to do so, as to how it will administer compliance and enforcement functions. Clarity should not be confused with certainty. The former is provided by the statute, the Final Rule and the aforementioned authorities. The latter is simply unavailable in this context. Indeed, guaranteeing in advance specific enforcement outcomes hampers necessary and appropriate enforcement flexibility and poses the danger of users, owners and operators of the Bulk-Power System simply calculating the cost of a violation into the cost of doing business—a dynamic that would frustrate the very purpose of a mandatory Reliability Standards system, which is to promote reliability.

277. The Commission agrees with NERC that, even if some clarification of a particular Reliability Standard would be desirable at the outset, making it mandatory allows the ERO and the Regional Entities to provide that clarification on a going-forward basis while still requiring compliance with Reliability Standards that have an important reliability goal. Further, we support the ERO's efforts to review each of the current Reliability Standards to improve them and provide yet further clarity. We encourage all interested entities, especially those that have identified specific suggestions for improvement, to participate in the ERO's Reliability Standards development process.

278. The Commission finds that these Reliability Standards, with the interpretations provided by the Commission in the standard-by-standard discussion, meet the statutory criteria for approval as written and should be approved. In any event, penalties are warranted under section 215 only when an entity knew or reasonably should have known that its acts or omissions were contrary to the Reliability Standards. Wisconsin Electric seems to interpret the Commission as requiring that users, owners and operators of the Bulk-Power System comply with best practices under the Reliability Standards. We disagree. While we appreciate that many entities may perform at a higher level than that required by the Reliability Standards, and commend them for doing so, the Commission is focused on what is required under the Reliability Standards; we do not require that they exceed the Reliability Standards. We agree with EEI that a common interpretation cannot supplant a provision that is clearly stated in a Reliability Standard. We also agree, however, that, over time, these interpretations could be incorporated either into the Reliability Standard itself through the Reliability Standards development process or the ERO and Regional Entity audit guidelines.

279. The Commission disagrees with MISO that some Reliability Standards as proposed are unclear with respect to applicability. In certain situations, Bulk-Power System reliability depends on more than one entity complying with a Reliability Standard. Further, in certain situations, the Requirement of a Reliability Standard may reference an entity that is not itself responsible for compliance with the Reliability Standard, for example, where an entity responsible for compliance must report information to or communicate with another entity, without that other entity being required to comply with the Reliability Standard. However, in its review of Reliability Standards, the ERO should ensure that, if a functional entity must comply with the Reliability Standards, it must be mentioned in the Applicability section. In this regard, we encourage the ERO to consider development of a database-style tool that is a companion to the Reliability Standards that permits any user, owner or operator to sort and find all Requirements applicable to it.

280. In response to MISO, Constellation, International Transmission and Dynegy, the Commission believes that the Requirements in each Reliability Standard are core obligations and that the Measures and Levels of Non-Compliance provide useful guidance to the industry and can be supporting information, an explanatory statement or an administrative process. As discussed above, NERC is to enforce the Requirements in a Reliability Standard. The Measures are part of the Reliability Standards and, if not met, are almost always going to result in a violation of a Requirement.

281. The Commission has previously addressed Alcoa's concerns about defining the target level of reliability of the Bulk-Power System that the Reliability Standards are intended to achieve. In the January 2007 Compliance Order, the Commission directed the ERO to establish a stakeholder process to define adequate level of reliability. [129] While the Commission agrees that this is a worthwhile effort, we disagree with Alcoa that Reliability Standards cannot be approved until this analysis is done. Such analysis is not required by the statute, and Alcoa has not identified any compelling reason why the proposed Reliability Standards are defective without the benefit of such analysis.

4. Technical Adequacy

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

a. Comments

283. NYSRC shares the Commission's concerns regarding the use of a “lowest common denominator” approach in the development of Reliability Standards and agrees that this concern can be addressed only on a standard-by-standard basis. NYSRC maintains that, in commenting on pending ERO Reliability Standards, the NYSRC believed could weaken existing Reliability Standards, the NERC drafting team responded that a region is free to develop more stringent Reliability Standards. NYSRC maintains that the ability of a Regional Entity to propose more stringent Reliability Standards to meet the reliability needs of that region does not justify the weakening of continent-wide Reliability Standards by use of a “lowest common denominator” approach to achieve greater support for a proposed Reliability Standard. NYSRC recommends that the Commission reaffirm that it will carefully review subsequent proposed ERO Reliability Standards to ensure that they are technically adequate and do not weaken the current level of reliability.

284. ATC agrees with the Commission that the industry, organized in Regional Entities under the ERO, must continue to be wholly accountable for the technical adequacy of the Reliability Standards. ATC thus suggests that the Commission's efforts to “independently assess the technical adequacy of any proposed Reliability Standard” focus on Commission participation in and support of the Reliability Standards development processes at NERC and at the regions.

b. Commission Determination

285. The Commission fully intends to address technical adequacy on a standard-by-standard basis and the Commission agrees that the ability of a Regional Entity to propose more stringent Reliability Standards to meet the reliability needs of that region does not justify the weakening of continent-wide Reliability Standards. In this regard, we note that, in the January 2007 Compliance Order, we directed the ERO to closely monitor the voting results for Reliability Standards and to report to us quarterly for the next three years its analysis of the voting results, including trends and patterns that may signal a need for improvement in the voting process, such as the rejection of a Reliability Standard and subsequent ballot approval of a less stringent version of the Reliability Standard. [131] The Commission will use this information to evaluate whether it needs to re-examine the Reliability Standard development procedure. In doing so, the Commission will also be sensitive to concerns that “lowest common denominator” Reliability Standards are being developed.

286. The Commission agrees that its staff should participate in and support the Reliability Standards development processes, to the extent consistent with its regulatory role. The Commission's participation in those processes will not constitute its entire assessment of the technical adequacy of a proposed Reliability Standard. The Commission will also conduct an assessment during its rulemaking or order process after the Reliability Standard is submitted by the ERO to the Commission for approval.

5. Fill-in-the-Blank Standards

287. The NOPR explained that certain Reliability Standards, referred to as fill-in-the-blank standards, require the regional reliability organizations to develop criteria for use by users, owners or operators within each region. [132] In the NOPR, the Commission expressed concern regarding the potential for the fill-in-the-blank standards to undermine uniformity. With regard to NERC's stated intention to submit an action plan and schedule for completing the fill-in-the-blank standards, the NOPR explained that NERC's plan must be consistent with the discussion in Order No. 672 regarding uniformity and the limited circumstances in which a regional difference would be permitted. [133]

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

a. Comments

289. NERC, APPA and TAPS support the Commission's proposal to defer consideration of fill-in-the-blank standards. APPA believes that the Commission's proposal balances the need for greater uniformity against the need for regional flexibility.

290. NERC agrees with the Commission's proposal to hold 24 Reliability Standards (mainly fill-in-the-blank standards) as pending at the Commission until further information is provided, and to require that Bulk-Power System users, owners and operators follow these pending standards as “good utility practice” pending their approval by the Commission. NERC also agrees that it and the Regional Entities can monitor compliance with these pending standards using the ERO's authority pursuant to § 39.2(d) of the Commission's regulations. NERC believes this approach is necessary to ensure that there will be no gap during the transition from the current voluntary reliability regime to mandatory and enforceable Reliability Standards.

291. While TAPS supports deferring consideration of fill-in-the-blank standards, it urges the Commission to view with skepticism regional differences within an Interconnection that are not justified by physical differences. It states that such regional Reliability Standards, even if more stringent, can wreak havoc on competitive markets, especially where entities within the same transmission system or RTO footprint are subject to different regional Reliability Standards. For example, TAPS maintains that inconsistent regional underfrequency load shedding (UFLS) Reliability Standards not justified by physical differences impose unjust burdens on joint action agencies whose integrated load is split between NERC regions. Further, according to TAPS, a region's choice may reflect the historical lack of a balanced process for developing Reliability Standards at the regional level, allowing certain classes of market participants to determine the region's choice.

292. According to ISO-NE, if the Commission withholds approval of these 24 Reliability Standards, the Commission should also withhold approval of Reliability Standards that rely, by reference, on such fill-in-the-blank Reliability Standards. [135] ISO-NE submits that, until the missing information has been provided in the cross-referenced fill-in-the-blank Reliability Standard, it will be impossible for the applicable entities to determine exactly what criteria they are expected to satisfy. APPA raises similar concerns, and suggests that the Commission approve such Reliability Standards but not enforce them until the cross-referenced fill-in-the-blank Reliability Standards are approved.

293. MISO and Wisconsin Electric believe that the fill-in-the-blank standards may be acceptable in certain situations. They give regions some flexibility in implementation, and allow the deployment of a Reliability Standard where it would be difficult to get consensus across several regions. They also move the reliability agenda forward on issues that are historically under state jurisdiction, and some are an accommodation to those regions that want to have a higher Reliability Standard.

294. EEI agrees with the NOPR that, regarding Reliability Standards for which the Commission needs additional information, compliance in the interim would be expected as a matter of good utility practice. While EEI agrees with this approach, it also cautions that the good utility practice provision of an OATT should not be used as an alternative means of enforcement outside of section 215 of the FPA. Similarly, FirstEnergy posits that good utility practice is subject to interpretation and by itself does not provide the level of guidance needed for a mandatory and enforceable Reliability Standard. It asserts that the Commission should not impose compliance burdens indirectly where it has not imposed them directly. Xcel asserts that the Commission should rescind the Reliability Policy Statement that defines good utility practice under the pro forma OATT, effective when the Reliability Standards become mandatory in June 2007, because a reliability-related violation should not be subject to two separate enforcement schemes.

295. NPCC recommends that any of the 24 fill-in-the-blank standards that are required to be Reliability Standards should be developed as regional Reliability Standards by the Regional Entity for compliance monitoring and enforcement, backed by the Commission and Canadian provincial regulatory and/or governmental authorities.

296. California PUC states that the NOPR seeks national uniformity notwithstanding regional differences. It states that, in the Western Interconnection, there are 15 existing, enforceable WECC standards pursuant to the WECC Reliability Management System (RMS) that overlap the proposed mandatory Reliability Standards. Five of these WECC standards fall into the fill-in-the-blank standards category. However, there are three additional WECC RMS standards already in effect in the Western Interconnection that do not have a corresponding proposed Reliability Standard. California PUC asks that the Commission consider approving these additional three standards for enforcement in the Western Interconnection. California PUC states that there is no reason for the Commission to exclude any WECC standard already in effect, and that ignoring these established standards when the Reliability Standards are scheduled to go into effect can threaten reliability already being achieved in the Western Interconnection.

b. Commission Determination

297. The Commission requires supplemental information for any Reliability Standard that currently requires a regional reliability organization to fill in missing criteria or procedures. Where important information has not yet been provided to us to enable us to complete our review, we are not in a position to approve or remand those Reliability Standards. [136] Accordingly, we will not approve or remand such Reliability Standards until the ERO submits further information. Until such information is provided, compliance with fill-in-the-blank standards should continue on a voluntary basis, and the Commission considers compliance with such Reliability Standards to be a matter of good utility practice.

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

299. The ERO should develop the needed information for the Commission to act on the fill-in-the-blank standards consistent with these criteria. If a regional difference is warranted, a regional fill-in-the-blank proposal must be developed through an approved regional Reliability Standards development process, and submitted to the ERO. If approved by the ERO, the ERO will then submit it to the Commission for approval.

300. The Commission disagrees with ISO-NE, ISO/RTO Council and APPA that 16 additional Reliability Standards should not be acted on or enforced at this time. The fact that a Reliability Standard simply references another, pending Reliability Standard, one that is not being approved or remanded here, does not alone justify not approving the former Reliability Standard. Rather, such a reference may be considered in an enforcement action, if relevant, but is not a reason to delay approval of enforcement of the Reliability Standard. We find that the Reliability Standards that reference a pending Reliability Standard contain the appropriate level of specificity necessary to provide notice to users, owners and operators of the Bulk-Power System as to what is required.

301. The Commission has reviewed the 16 Reliability Standards identified by commenters as referencing a Reliability Standard that the Commission proposed not to approve or remand. It appears that many of these Reliability Standards either refer to the process of collecting data or reference Requirements that entities are generally aware of because they have already been following these Reliability Standards on a voluntary basis. For example, MOD-012-0 requires transmission and generator owners to provide data to the regional reliability organization to support system modeling required by MOD-013-0. The NOPR proposed not to approve or remand MOD-013-0 partly because MOD-013-0 requires development of dynamics data requirements and reporting procedures that have not been submitted for our review. In addition, we proposed not to act on MOD-013-0 partly because it applies to a regional reliability organization and the Commission was not persuaded that a regional reliability organization's compliance with a Reliability Standard can be enforced by NERC. That is not the case with MOD-012-0, which applies to entities that are clearly users, owners and operators of the Bulk-Power System. Although MOD-012-0 references MOD-013-0, its applicability to a subset of users, owners and operators is not at issue. Accordingly, the Commission denies the requests to leave pending this and similar data-related Reliability Standards and reaffirms the NOPR approach described above.

302. While EEI and others agree with the proposal that, in the interim, compliance with Reliability Standards for which the Commission needs additional information should continue as a matter of good utility practice, they caution that this should not lead to an alternative means of enforcement outside of section 215 of the FPA. In our Reliability Policy Statement, we explained that compliance with NERC Reliability Standards (or more stringent regional standards) is expected as a matter of good utility practice as that term is used in the pro forma OATT. [138] The Commission continues to expect compliance with such Reliability Standards as a matter of good utility practice. That being said, the Commission agrees that retaining a dual mechanism to enforce Reliability Standards both as good utility practice and under section 215 of the FPA is inappropriate; the OATT only applies to entities subject to our jurisdiction as public utilities under the FPA, while section 215 defines more broadly our jurisdiction with respect to mandatory Reliability Standards. We therefore do not intend to enforce, as an OATT violation, compliance with any Reliability Standard that has not been approved by the Commission under section 215.

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

F. Discussion of Each Individual Reliability Standard

304. The NOPR reviewed each proposed Reliability Standard and provided an analysis by chapter according to the categories of Reliability Standards defined in NERC's petition. Each chapter began with an introduction to the category, followed by a discussion of each proposed Reliability Standard. The Final Rule takes a similar approach.

1. BAL: Resource and Demand Balancing

305. The six Balancing (BAL) Reliability Standards address balancing resources and demand to maintain interconnection frequency within prescribed limits.

a. Real Power Balancing Control Performance (BAL-001-0)

306. The purpose of this Reliability Standard is to maintain Interconnection steady-state frequency within defined limits by balancing real power demand and supply in real-time. The proposed Reliability Standard would apply to balancing authorities. In the NOPR, the Commission proposed to approve BAL-001-0 as mandatory and enforceable. [139]

i. Comments

307. APPA agrees with the Commission that BAL-001-0 is sufficient for approval as a mandatory Reliability Standard.

ii. Commission Determination

308. For the reasons stated in the NOPR, the Commission approves BAL-001-0 as mandatory and enforceable.

b. Regional Difference to BAL-001-0: ERCOT Control Performance Standard 2

309. NERC approved a regional difference for ERCOT by allowing it to be exempt from Requirement R2 in BAL-001-0, which requires that the average area control error (ACE) for each of the six ten-minute periods during the hour must be within specific limits, and that a balancing authority achieve 90 percent compliance. This Requirement is referred to as Control Performance Standard 2 (CPS2).

310. NERC explains that ERCOT requested a waiver of CPS2 because: (1) ERCOT, as a single control area [140] asynchronously connected to the Eastern Interconnection, cannot create inadvertent flows or time errors in other control areas and (2) CPS2 may not be feasible under ERCOT's competitive balancing energy market. In support of this argument, ERCOT cites to a study that it performed showing that under the new market structure, the ten control areas in its region individually were able to meet CPS2 standards while the aggregate performance of the ten control areas was not in compliance. Since requesting the waiver from CPS2, ERCOT has adopted section 5 of the ERCOT protocols which identify the necessary frequency controls needed for reliable operation in ERCOT.

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

i. Comments

312. No comments were filed on this regional difference.

ii. Commission Determination

313. The Commission approves the ERCOT regional difference as mandatory and enforceable. Order No. 672 explains that “uniformity of Reliability Standards should be the goal and the practice, the rule rather than the exception.” [142] However, the Commission has stated that, as a general matter, regional differences are permissible if they are either more stringent than the continent-wide Reliability Standard, or if they are necessitated by a physical difference in the Bulk-Power System. [143] Regional differences must still be just, reasonable, not unduly discriminatory or preferential and in the public interest. [144]

314. The Commission finds that ERCOT's approach under section 5 of the ERCOT protocols appears to be a more stringent practice than Requirement R2 in BAL-001-0 and therefore approves the regional difference.

315. As proposed in the NOPR, the Commission directs the ERO to file a modification of the ERCOT regional difference to include the requirements concerning frequency response contained in section 5 of the ERCOT protocols. As with other new regional differences, the Commission expects that the ERCOT regional difference will include Requirements, Measures and Levels of Non-Compliance sections.

c. Disturbance Control Performance (BAL-002-0)

316. The stated purpose of this Reliability Standard is to use contingency reserves to balance resources and demand to return Interconnection frequency to within defined limits following a reportable disturbance. The proposed Reliability Standard would apply to balancing authorities, reserve sharing groups [145] and regional reliability organizations.

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

i. General Comments

318. Constellation supports the Commission's proposals with respect to BAL-002-0.

319. Xcel notes that this Reliability Standard would apply to a reserve sharing group, which is not defined in the NERC Functional Model but generally consists of a group of separate entities. Xcel states it is not clear how compliance and penalties would be applied to a reserve sharing group and seeks clarification from the Commission. As a second concern, Xcel states it is not clear who calculates ACE between a balancing authority and a reserve sharing group and states that the Commission should require the ERO to clarify this issue when modifying the Reliability Standard.

ii. Commission Determination

320. The Commission approves BAL-002-0. With regard to Xcel's concern, the NERC glossary defines a reserve sharing group as “two or more balancing authorities that collectively maintain, allocate, and supply operating reserves required for each balancing authority's use in recovering from contingencies within the group.” [149] The Commission notes that the Reliability Standard's Requirements and Levels of Non-Compliance are applicable to both balancing authorities and reserve sharing groups and are clear as to the roles and responsibilities of these entities. The ERO will be responsible for ensuring compliance with this Reliability Standard for all applicable entities. A reserve sharing group, however, as an independent organization, is able to determine on its own as a commercial matter whether any penalties related to non-compliance should be re-apportioned among the members of the group. With regard to Xcel's concern about which entity calculates ACE, it is not clear from Xcel's comments what it believes needs clarification. In general, we understand that all balancing authorities are required to calculate ACE with the exception of balancing authorities that use dynamic schedules to provide all regulating reserves from another balancing authority. As such, reserve sharing groups will not calculate ACE; they will rely on balancing authorities to do so.

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

iii. Including Demand-Side Management as a Resource

(a) Comments

322. SMA supports the Commission's proposed requirement explicitly allowing demand-side response as a resource and agrees with the Commission that DSM and direct load control should be considered on the same basis as conventional generation or any other technology with respect to contingency reserves. SMA states that nationwide its members provide over 1,300 MW of demand that is curtailable on 10 minutes notice or less and indicates that most of this curtailable capacity is committed to utilities pursuant to retail tariffs or contracts for operating reserves.

323. FirstEnergy states that demand-side resources should be included as another tool for the balancing authority to use in meeting the control performance and disturbance control standards. According to FirstEnergy, demand-side resources should mimic the requirements of generation resources but with a decrease in load rather than an increase in generation response.

324. Process Electricity Committee generally supports the proposal to treat demand response resources in a manner similar to conventional generation so long as such demand resources participate in such DSM programs voluntarily and comply with all applicable Reliability Standards and requirements. Process Electricity Committee recommends that the Commission modify its proposal to clarify that any such demand response resources may be used only with the end-user's express written agreement pursuant to clear contractual rights and obligations.

325. NY Major Consumers states that many large end use customers currently have the ability to provide all ancillary services, or are capable of providing these services in the near future and that this capability has been recognized by Commission staff in Docket No. AD06-2-000, Assessment of Demand Response Resources. NY Major Consumers further states that there remains some ambiguity in the proposed Reliability Standards as to the eligibility of technically-qualified loads to provide these services and requests that the Commission eliminate any such uncertainty and amend the proposed Reliability Standards as further described in its comments.

326. Some commenters [151] disagree with the Commission's proposal to add a requirement explicitly allowing DSM as a resource for contingency reserves. NERC, APPA and ISO-NE state that this requirement is too prescriptive. NERC maintains that explicitly allowing DSM goes well beyond the bounds of current utility practice and suggests an improved directive would simply place DSM on the same basis as other resources. APPA states that DSM resources should be included as an option for a balancing authority to use in meeting its reserve obligations, but that the Commission should not require NERC to modify the Reliability Standard to explicitly identify DSM or any other type of capacity as a resource for meeting reserve contingencies.

327. In addition, ISO-NE states that DSM, to which it has access, responds to capacity requirements and may not provide relief on a contingency basis, but states that it has a limited number of resources that could meet this requirement. SDGE argues that DSM participation in real-time is often unknown in comparison to conventional generation and further states that the NOPR does not explain how DSM could be used in real-time dispatch. Further, SDGE maintains that the Commission has not established a clear and workable definition of DSM.

328. MISO states that it is not clear about the meaning and questions the value of the Commission's proposed requirement to include DSM as a contingency reserve resource. [152]

329. While EEI and MRO do not disagree with the Commission's proposed requirement to include DSM, EEI states that both generation and controllable load should comply with the same requirements to the maximum extent possible, while MRO suggests that this requirement should also include study and testing requirements.

(b) Commission Determination

330. We direct the ERO to submit a modification to BAL-002-0 that includes a Requirement that explicitly provides that DSM may be used as a resource for contingency reserves, subject to the clarifications provided below.

331. The Commission disagrees with APPA that we should not explicitly identify any type of capacity as a resource for meeting reserve contingencies. The Commission believes that listing the types of resources that can be used to meet contingency reserves makes the Reliability Standard clearer, provides users, owners and operators of the Bulk-Power System a set of options to meet contingency reserves, and treats DSM on a comparable basis with other resources.

332. Many commenters argue that the Commission's proposed directive that would explicitly allow DSM as a resource for contingency reserves is too prescriptive. Concerns in this area generally fall into three categories: (1) that DSM should be treated on a comparable basis as other resources; (2) that the Reliability Standard should be based on meeting an objective as opposed to stating how that objective is met and (3) that DSM may not be technically capable of providing this service.

333. With regard to the first concern, the Commission clarifies that the purpose of the proposed directive is to ensure comparable treatment of DSM with conventional generation or any other technology and to allow DSM to be considered as a resource for contingency reserves on this basis without requiring the use of any particular contingency reserve option. [153] The proposed directive as written achieves that goal. With regard to the second concern, we believe that this Reliability Standard is objective-based and we reiterate that we are simply attempting to make it inclusive of other technologies that may be able to provide contingency reserves, and are not directing the use of any particular type of resource. By specifying DSM as a potential resource for contingency reserves, the Commission is clarifying the substance of the Reliability Standard. [154]

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

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

iv. Continent-Wide Contingency Reserve Policy

(a) Comments

336. The Commission proposed in the NOPR to direct the ERO to develop one uniform continent-wide contingency reserves policy. Specifically, the Commission noted that the appropriate mix of operating reserves, spinning reserves and non-spinning reserves should be addressed on a consistent basis and consideration should be given to the amount of frequency response from generation or load needed to assure reliability. The Commission proposed that this policy be neutral as to the source of the contingency reserves in terms of ownership or technology.

337. SMA supports the Commission's proposal to develop a continent-wide contingency reserve policy and agrees with the Commission that the policy should be neutral as to the source of the contingency reserves in terms of ownership or technology. EEI and FirstEnergy both support development of a continent-wide contingency reserve policy but suggest the need for regional variations across the Bulk-Power System. For instance, FirstEnergy suggests that a one percent peak load spinning requirement in the Eastern Interconnection could be the equivalent of a two percent spinning requirement in the Western Interconnection.

338. Other commenters [158] disagree with the Commission's proposal to have NERC develop a continent-wide contingency reserve policy and instead support an Interconnection-wide or regional approach. APPA, LPPC and MISO state that a continent-wide policy would not work because of regional differences such as size, topology, mix of resources and likely contingencies. While APPA supports the Commission's proposal that contingency reserves should be based on the reliability risk of a balancing authority not meeting load, it favors an Interconnection-wide approach. MISO suggests that defining certain terms such as “spinning,” “non-spinning,” “contingency” and “replacement” and having common calculations would be of value. It contends, however, that EPAct does not apply to resource adequacy requirements, implying that the Commission therefore is prevented from directing the development of a continent-wide contingency reserve policy. International Transmission shares this view.

339. California PUC states that some customers can tolerate a limited number of outages and suggests that it may be more cost-effective to provide back-up power to customers with high reliability needs rather than designing the entire system to a very high and expensive level. California PUC disagrees with the Commission that contingency reserves should be based only on the reliability risk of a balancing authority not meeting load. It suggests that certain other relevant factors should be considered, such as the number of customers or MW lost, the value that customers in a certain area place on reliability and the costs of avoiding outages (the cost of reserves).

(b) Commission Determination

340. We direct the ERO to submit a modification to BAL-002-0 to include a continent-wide contingency reserve policy. We are not prescribing the details of that policy. As the Commission stated in the NOPR, “[w]hile the Commission believes it is appropriate for balancing authorities to have different amounts of contingency reserves, these amounts should be based on one uniform continent-wide contingency reserves policy. The policy should be based on the reliability risk of not meeting load associated with a particular balancing authority's generation mix and topology.” [159] In addition, the contingency reserves should include sufficient frequency responsive resources such that the net frequency response of the balancing authority is sufficient for either interconnected or isolated operation. [160]

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

342. We believe a continent-wide contingency reserves policy would assure that there are adequate magnitude and frequency responsive contingency reserves in each balancing authority. This will improve performance so that no balancing authority will be doing less than its fair share.

343. With regard to California PUC's concerns regarding the cost of providing reserves, and the suggestion that loss of firm load may be an acceptable alternative to enhanced reliability of the system, the Commission disagrees. Loss of firm load should not be permitted in planning the system for a single contingency. However, the Commission recognizes the appropriate concern of California PUC regarding costs. The California PUC can have a strong role in this area by encouraging or requiring DSM programs that can reduce the demand on the transmission system.

344. With regard to statements that EPAct does not apply to resource adequacy, we note that this Reliability Standard does not concern resource adequacy, but addresses contingency reserves, which are operating and not planning reserves. Operating reserves are not the same as resource adequacy, a planning element. Section 215 authorizes the Commission to approve Reliability Standards for contingency reserves because they are necessary for real-time Reliable Operation of the Bulk-Power System.

345. Accordingly, the Commission requires the ERO to develop a continent-wide contingency reserve policy through the Reliability Standards development process, which should include uniform elements such as certain definitions and requirements as discussed in this section. The Commission clarifies that the continent-wide policy can allow for regional differences pursuant to Order No. 672, but that the policy should include procedures to determine the appropriate mix of operating reserves, spinning and non-spinning, as well as requirements pertaining to the specific amounts of operating reserves based on the load characteristics and magnitude, topology, and mix of resources available in the region.

v. Disturbance Control Standard and the Associated Reserve Requirement

(a) Comments

346. The Commission identified two items in the Disturbance Control Standard section of the NOPR. In the first item, the Commission agreed with the interpretation that the 15 minute limit on a reportable disturbance was “absolute, objective, and measurable” and therefore enforceable in the present Reliability Standard. The second item resulted in a proposal to modify Requirement R3.1, which currently requires that a balancing authority to carry at least enough contingency reserves to cover “the most severe single contingency.” The Commission proposed to change the Requirement to include enough contingency reserves to cover any event or single contingency, including a transmission outage, which results in a significant deviation in frequency from the loss or mismatch of supply either from local generation or imports. The Commission noted that this approach would address staff's concern with Requirement R3.1—specifically, addressing the ambiguity over whether the Requirement meant the loss of generation or the loss of supply resulting from a transmission or generation contingency. [161]

347. Most commenters [162] express concern over the Commission's proposal to add a Requirement that measures response for any event or contingency that causes a frequency deviation. NERC states that this proposed directive is overly prescriptive and suggests that an improved modification would be to direct the ERO to resolve the ambiguity in Requirement R3.1 as pointed out in the Staff Preliminary Assessment. APPA suggests that the Commission should not require NERC to modify the Reliability Standard, but should allow NERC to address the Commission's concerns in its Reliability Standards development process and, while doing so, NERC should consider defining “Most Severe Single Contingency” contained in the WECC Frequency Response Standard White Paper. [163] Xcel has concerns about the compliance aspects of this proposed modification stating that there is no equitable method to assess an individual entity's performance for an occurrence that is potentially Interconnection-wide.

348. NRC notes the NERC and Commission observations regarding the declining trend in frequency response and states that this Reliability Standard provides the opportunity to establish a frequency response performance standard. NRC staff suggests that a Measure be added to establish a frequency response.

349. MRO suggests that, if this requirement is adopted, a clear definition of the event that causes a frequency deviation will be required. ISO-NE comments that Requirement R3.1 is already clear and the suggested modification is not clear because: (1) It is not possible to plan for all such events and (2) it is not clear what is a “significant deviation.” EEI states that a requirement to measure frequency response for any event or contingency could provide beneficial information for system operators but states that there is presently no requirement for generators to report all outages so measurements cannot be made. EEI further states that the compliance costs of this requirement may outweigh the benefits. The Nevada Companies disagree with the proposed modification and state that the Reliability Standard must instead focus strictly on the loss of supply. The Nevada Companies further state that, for purposes of this Reliability Standard, WECC's present contingency reserve criterion, which requires consideration of loss of generation that would result from the most severe single contingency, is most applicable.

350. Georgia Operators comment that the Commission's intent in this proposed modification should not be interpreted to require a balancing authority to carry enough reserves to cover any event resulting in a significant deviation in frequency and should not be read to suggest that frequency rather than ACE should be used to measure a balancing authority's deployment of reserves for contingencies.

351. MISO and ERCOT comment on the Commission's suggestion that NERC should consider defining a frequency deviation of 20 milli Hertz lasting longer than the 15 minute recovery period as a significant deviation. MISO argues that the value could vary in different Interconnections and believes the current method is acceptable. ERCOT states that it is not feasible to apply a single frequency-deviation number to ERCOT and the other Interconnections and asks the Commission to instead consider a Reliability Standard that is proportional to the size of each Interconnection. ERCOT notes that 20 milli Hertz would be far more strict than ERCOT's historic frequency performance.

(b) Commission Determination

352. On this issue, the Commission will not direct the ERO to modify BAL-002-0 in the manner proposed in the NOPR. Rather, the Commission directs the ERO to address the concerns expressed by the Commission about having enough contingency reserves to respond to an event on the system in Requirement R3.1 and how such reserves are measured. The ERO should address this through adoption or modification of Requirements and metrics in the Reliability Standards development process.

353. NERC correctly points out that the Commission's proposal on this point stemmed from the ambiguity in Requirement R3.1 that Commission staff highlighted in the Staff Preliminary Assessment. Requirement R3.1 currently requires that a balancing authority carry at least enough contingency reserves to cover “the most severe single contingency.” The Commission emphasizes that the goal of this Reliability Standard is to insure against the reliability risk of not serving load by matching generation and load following any disturbance or event that results in a significant deviation in frequency. Consistent with this goal, the Commission believes that this Reliability Standard should be inclusive of all events, i.e., loss of supply, loss of load or significant scheduling problems, which can cause frequency disturbances and should address how balancing authorities should respond. The Commission notes that PJM recently issued a paper addressing frequency excursion related to scheduling problems. [164]

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

355. First, the Commission directs the ERO to develop a modification to the Reliability Standard requiring that any single reportable disturbance that has a recovery time of 15 minutes or longer be reported as a violation of the Disturbance Control Standard. This is consistent with our position in the NOPR and NERC's position in response to the Staff Preliminary Assessment of the Requirements in BAL-002-0, and was not disputed or commented upon by any NOPR commenters.

356. Taking into account commenters' concerns about defining a significant deviation as a frequency deviation of 20 milli Hertz lasting longer than the 15 minute recovery period, the Commission will not direct a specific change. Instead, we direct the ERO, through the Reliability Standards development process, to modify this Reliability Standard to define a significant deviation and a reportable event, taking into account all events that have an impact on frequency, e.g., loss of supply, loss of load and significant scheduling problems, which can cause frequency disturbances and to address how balancing authorities should respond. As suggested by NRC, this or a related Reliability Standard should also include a frequency response requirement. The present Control Performance Standards represent the monthly and yearly averages which are appropriate for measuring long-term trends but may not be appropriate for measuring short-term events. In addition, the measures should be available to the balancing authorities to assist in real-time operations. [167]

vi. Summary of Commission Determination

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

d. Frequency Response and Bias (BAL-003-0)

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

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

i. Comments

360. Several commenters address the Commission's proposal to direct the ERO to modify Measurement M1 to include yearly surveys.

361. LPPC agrees with the Commission's proposed directive. EEI states that NERC currently conducts an annual frequency response characteristic survey that appears to address the Commission's proposed directive. If the yearly survey would replace the frequency response characteristic survey, EEI states that the survey should include questions regarding the scope of potential new requirements. ISO/RTO Council believes that yearly surveys are unnecessary and would prefer that NERC focus on surveying balancing authority responses to large frequency disturbances.

362. APPA agrees that the Commission has correctly identified shortcomings in this Reliability Standard and states that, while the Commission may have identified appropriate modifications, the determination should be left to NERC to address in the first instance. APPA supports the development of a consistent Interconnection-wide policy and suggests that NERC should consider procedures similar to those used in ERCOT and WECC.

363. FirstEnergy suggests that Requirements R5 and R5.1 of this Reliability Standard should be required in lieu of Requirement R2 if a balancing authority has load but no generation (R5) or if a balancing authority has generation but no load (R5.1). FirstEnergy states that without this change the Reliability Standard is not clear because it implies that a balancing authority could choose between two options. Most commenters responded to the Commission's request for comments in the NOPR by stating that additional requirements do not need to be added for balancing authorities to calculate the frequency response necessary for reliability in each of the Interconnections. NERC states that frequency bias is currently over-compensated across the Interconnections and that requiring frequency bias to be actual frequency response may reduce control performance. Additionally, NERC states that some studies have shown a decline in frequency (e.g., governor) response over several decades and that it is addressing this issue through the request for a new Reliability Standard on frequency response. NERC also notes that BAL-003-0 will be replaced soon by the new balancing Reliability Standards that are approaching ballot.

364. In general, EEI believes that systemic over-biasing does not present a reliability problem and the Commission should exercise caution in requesting changes to this Reliability Standard. EEI states that the frequency bias varies continuously in terms of the type and magnitude of load changes, and the types and loading of generation resources. Therefore, EEI suggests that the accuracy of any estimate of frequency bias is highly questionable. Further, EEI states that the one percent default value was deliberately set to over-bias the system to ensure adequate frequency response. EEI is unaware of any evidence of undamped oscillations due to this over-biasing and states that the one percent floor should be recognized by the Commission as just and reasonable until an optimum frequency bias value can be studied. EEI sees the potential need for developing requirements for modifying frequency bias during emergency conditions, citing evidence from the August 2003 blackout suggesting that oscillations following the ISO New England separation from the Eastern Interconnection may have been caused by over-biasing.

365. ISO/RTO Council comments that the details of the procedures that are used to ensure frequency bias are appropriate and no additional requirements for balancing authorities are needed. It disagrees with the Commission's proposal to develop uniform requirements for frequency bias. [173] ISO/RTO Council states that there is no single right way to develop and apply a frequency bias setting and no universally accepted norm. ISO/RTO Council believes the key point is that the frequency bias setting be greater than the natural frequency response of the system and believes that the percent minimum currently in place is sufficient. ISO/RTO Council recommends that NERC investigate (1) reliability issues associated with low natural response; (2) causes of decreasing natural response and (3) possible opportunities for creating markets for load and generator response to frequency changes.

366. Xcel responds that there is no need for this Reliability Standard to address frequency bias during black start, restoration and islanding due to the transitional nature of those events. Northern Indiana opposes imposing greater restrictions on frequency bias and frequency response calculations, stating that they could be counter-productive by making procedural errors more likely, which could harm reliability. Northern Indiana suggests that the approach suggested in the NOPR would require frequency response to be calculated based on various contingencies in a way that, if a particular contingency does not occur, the balancing authority might contribute to an incorrect frequency response. Northern Indiana maintains that the existing Reliability Standard is appropriate because it reflects the unique characteristics of each utility's operating characteristics and allows experienced, certified operators to act to avoid adverse effects on the electric system.

367. MidAmerican believes that a requirement for balancing authorities to calculate the necessary frequency response is not necessary for reliability, nor should balancing authorities be required to identify the method to obtain that frequency response. MidAmerican states that the bias settings addressed in BAL-003-0 are appropriate for normal and emergency conditions. It further explains that large disturbances resulting in large frequency shifts can only be corrected by bringing load and generation into balance. MidAmerican further states that the annual review of bias settings uses tie line and frequency deviations during large disturbances to provide bias settings representative of relatively large frequency excursions and adds that these settings, along with automatic generation control and governor response, provide an over-biased response to steady-state frequency deviations. MidAmerican states that as long as system disturbances are continually tracked to ensure frequency decay is sufficiently mitigated, enough frequency bias will be on the system and the current Reliability Standard can be considered sufficient.

368. MISO states that it expects the Commission's concerns with the frequency response and bias standard to be addressed in NERC's frequency response Reliability Standard Authorization Request.

ii. Commission Determination

369. The Commission approves Reliability Standard BAL-003-0 as mandatory and enforceable. In addition, the Commission directs the ERO to develop a modification to BAL-003-0 as discussed below.

370. With respect to the frequency of frequency response surveys, EEI states that NERC currently conducts an annual frequency response characteristic survey that appears to address the Commission's concern. The Commission disagrees. The surveys that were performed on a yearly basis are not available on NERC's Web site and the ISO/RTO Council believes that more frequent analysis after large frequency disturbances is appropriate. The Commission understands that the last analysis was performed in 2002. Currently, Measure M1 only requires balancing authorities to perform surveys when requested by the NERC operating committee. As identified in Order No. 672, the Reliability Standards should be based on actual data. [174] Therefore, on further consideration, instead of requiring yearly surveys as proposed in the NOPR, the Commission believes that the frequency of these surveys should be based on the data requirements that will assist the ERO to determine if the balancing authorities are providing adequate and equitable frequency response to disturbances on the Bulk-Power System. Accordingly, we direct the ERO to determine the optimal periodicity of frequency response surveys necessary to ensure that Requirement R2 and other Requirements of the Reliability Standard are being met and to modify Measure M1 based on this determination. [175]

371. With respect to FirstEnergy's comment, Requirement R2 states that the frequency bias setting should be as close as practical to, or greater than, the balancing authority's frequency response. That is the Requirement concerning the relationship between frequency response and frequency bias, with Requirement R5 and R5.1 providing minimum frequency bias values for specific types of balancing authorities. The three Requirements do not conflict. A balancing authority must use a frequency bias of at least one percent and they must have a frequency bias that is as close as practical to, or greater than, the balancing authority's actual frequency response. As will be discussed more fully below, the Commission expects each balancing authority to meet these Requirements to be in compliance with the existing BAL-003-0.

372. With respect to the Commission's request for comments, most commenters are opposed to additional requirements for balancing authorities to calculate the frequency response necessary for reliability in each of the Interconnections. NERC states that frequency bias is currently over-compensated across the Interconnections, while EEI states that the one percent default value was deliberately set to over-bias the system to ensure adequate Frequency Response. The ISO/RTO Council comments that frequency bias settings are appropriate and all agree that no additional requirements are needed. However, NERC acknowledges that the frequency response of the Eastern and Western Interconnection is decreasing and states it will address the issue with a new frequency response Reliability Standard. There is no similar need in ERCOT because ERCOT has adopted an approach to calculate the necessary frequency response needed for Reliable Operation and has identified a method of obtaining the necessary frequency response as discussed in BAL-001-0 regional difference. The Commission understands that this approach was based on lessons learned from the May 15, 2003 event [176] that resulted in larger than anticipated amounts of firm load shedding by underfrequency relays operation due to less than desirable amounts of frequency response.

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

374. As the Commission noted in the NOPR and in our response to FirstEnergy, Requirement R2 of this Reliability Standard states that “[e]ach Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authority's Frequency Response.” The Commission believes that the achievement of this Requirement is fundamental to the tie line bias control schemes that have been in use to assist in balancing generation and load in the Interconnections for many years. [178] We understand that the present Reliability Standard sets the required frequency response of the balancing authorities to be approximately one percent or greater by requiring that the frequency bias shall not be less than one percent and that the frequency bias be as close as practical to, or greater than, the actual frequency response.

375. While EEI supports additional requirements related to frequency bias during emergency conditions, Xcel states that frequency response during black start, restoration and islanding situations need not be addressed in a Reliability Standard due to the transient nature of these events. The Commission disagrees with Xcel and agrees with EEI. The Bulk-Power System should be operated in a reliable manner at all times.

376. Accordingly, the Commission approves Reliability Standard BAL-003-0 as mandatory and enforceable. In addition, the Commission directs the ERO to develop a modification to BAL-003-0 through the Reliability Standards development process that: (1) Includes Levels of Non-Compliance; (2) determines the appropriate periodicity of frequency response surveys necessary to ensure that Requirement R2 and other requirements of the Reliability Standard are being met, and to modify Measure M1 based on that determination and (3) defines the necessary amount of Frequency Response needed for Reliable Operation for each balancing authority with methods of obtaining and measuring that the frequency response is achieved.

e. Time Error Correction (BAL-004-0)

377. The purpose of BAL-004-0 is to ensure that time error corrections are conducted in a manner that does not adversely affect the reliability of the Interconnection. [179] In the NOPR, the Commission proposed to approve Reliability Standard BAL-004-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to BAL-004-0 that includes Levels of Non-Compliance and additional Measures. [180]

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

i. Comments

379. MISO states that it is unclear what the Commission had in mind with its proposed directive to include Levels of Non-Compliance and additional Measures and that the reliability benefit of such Levels of Non-Compliance and additional Measures is also unclear.

380. While APPA and EEI favor adopting the WECC approach to time error correction, NERC and the majority of other commenters [183] are either opposed to adopting the WECC automatic time error correction procedure in other regions or think time error correction is more appropriately addressed as a business practice. NERC notes that the WECC procedure is in lieu of an equivalent procedure contained within the business practices of the North American Energy Standards Board (NAESB) and suggests that instructions for implementing a time error correction are more appropriately addressed as a business practice. Northern Indiana maintains that WECC-type procedures are unnecessary, and could result in unintended process errors or operational problems. It urges the Commission to allow time error issues to remain within the jurisdiction of NAESB and suggests that time error correction is not essential to reliability and is more appropriately treated as a non-essential guide. ISO-NE agrees that time error correction is not a reliability issue.

381. Xcel states that its operating company located in WECC has experienced problems with WECC's automatic time error correction procedure and therefore does not support adoption of this procedure by other regions. In addition, Xcel states that time error correction is not necessary for utilities in regional markets where imbalances are settled financially and the regional market operator manages the scheduled interchange offsets. LPPC suggests that there is not enough evidence to show that WECC's time error correction procedure is appropriate for the Eastern Interconnection. LPPC adds that the choice of switching to the WECC procedure should be left up to the NERC Reliability Standards development process.

382. MISO states that, while the WECC procedure has advantages with regard to reducing inadvertent interchange values, it does not reduce the number of time error corrections because WECC monitors and performs time error correction on a shorter time frame than the Eastern Interconnection. MISO argues that this is more of a technical requirement and not a Reliability Standard and suggests there are simpler ways to control time error and manage inadvertent balances. MISO states that NERC previously allowed unilateral payback of inadvertent balance of up to 20 percent of bias when the payback is in a direction to reduce time error and states that this reduced the number of time error corrections while giving balancing authorities a tool to balance their accounts. In its comments addressing BAL-006-1, MISO suggests that the number of time error corrections could be reduced by following the European methodology which has a wider window of allowable time and implements full clock-day, but with a smaller offset.

ii. Commission Determination

383. The Commission approves Reliability Standard BAL-004-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to BAL-004-0 through the Reliability Standards development process that includes Levels of Non-Compliance and additional Measures for Requirement R3. Further, based on commenters' concerns that there is no engineering basis for changing the time error correction to the WECC approach or any other approach, when reviewing the Reliability Standard during the ERO's scheduled five-year cycle of review, we direct the ERO to perform research that would provide a technical basis for the present approach or for any alternative approach.

384. Many commenters aver that the time error correction procedure belongs within the realm of NAESB and is not a reliability issue. The Commission disagrees, as BAL-004-0 is intended to ensure that time error corrections are performed in a manner that does not adversely affect the reliability of the Interconnection. The financial aspects of time error correction such as MISO's concern about the unilateral payback of interchange imbalances remain with NAESB. However, the technical details, including the means to carry out the procedure, are a reliability issue.

385. We believe that the efficiency of the time error correction can be viewed as a measure of whether all balancing authorities are participating in time error correction. Requirement R3 states that each balancing authority, when requested, shall participate in a time error correction. The Commission believes that this is a critical requirement, but the data on the NERC Web site indicates that efficiency is decreasing, indicating that fewer balancing authorities are employing time error correction. [184] Therefore, the Commission affirms its preliminary finding that the efficiency of time error corrections has decreased over the last ten years and that participation in time error corrections may be lacking. [185] Accordingly, we direct the ERO to develop additional Measures and add Levels of Non-Compliance to assure that the requirements in Requirement R3 are achieved. One approach to achieving this would be to use the existing measurement of efficiency as a metric of participation of all balancing authorities. If the efficiency is significantly less than 100 percent, the Measures should provide a process to identify which balancing authorities are not meeting the requirements of the Reliability Standard.

386. Although the Commission noted in the NOPR that WECC's time error correction procedure appears to serve as a more effective means of accomplishing time error correction, based on concerns that there is no engineering basis for changing the time error correction to the WECC approach, the Commission will not direct the ERO to adopt requirements similar to WECC's procedure. With the exception of comments from APPA and EEI, most commenters do not believe or are uncertain about whether the WECC procedure is appropriate for the Eastern Interconnection. However, when this Reliability Standard is scheduled for its regular five-year cycle of review, the Commission directs the ERO to perform whatever research it and the industry believe is necessary to provide a sound technical basis for either continuing with the present practice or identifying an alternative practice that is more effective and helps reduce inadvertent interchange.

387. The Commission agrees with MISO regarding the number of time error corrections using WECC's procedure. However, the magnitude of the frequency change in the WECC automatic time error correction is smaller than the manual correction and timing of the corrections are better correlated to when the error was created. These two characteristics of the WECC procedure avoid placing the system in less secure conditions and tie the payback to the initiating action, both of which appear to better serve both reliability and equity.

f. Automatic Generation Control (BAL-005-0)

388. The goal of this Reliability Standard is to maintain Interconnection frequency by requiring that all generation, transmission, and customer load be within the metered boundaries of a balancing authority area, and establishing the functional requirements for the balancing authority's regulation service, including its calculation of ACE.

389. In the NOPR, the Commission proposed to approve Reliability Standard BAL-005-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification to BAL-005-0 that: (1) Includes Requirements that identify the minimum amount of automatic generation control or regulating reserves a balancing authority must have at any given time; (2) changes the title of the Reliability Standard to be neutral as to source of the reserves; (3) includes DSM and direct control load management as part of contingency reserves and (4) includes additional Levels of Non-Compliance and Measures, including a Measure that provides for a verification process over the minimum required automatic generation control or regulating reserves a balancing authority maintains. [186]

390. Further, the NOPR stated that the Commission is interested in knowing whether any balancing authority is experiencing or is predicting any difficulty in obtaining sufficient automatic generation control.

i. Minimum Amount of Regulating Reserves

(a) Comments

391. South Carolina EG and SMA support the Commission's proposal to include a requirement that addresses minimum regulating reserves. It states that the control performance standard metric is a lagging indicator of necessary reserves and other standards such as frequency response may eventually provide a more dynamic real-time indicator. South Carolina EG believes the Commission's proposal provides a good interim solution.

392. Alcoa comments that, in establishing a minimum amount of reserves, NERC should be required to consider the quality of each source of reserves. Alcoa suggests that digitally controlled DC loads, such as an aluminum smelter, could respond much more rapidly and accurately than thermal generators and that using such resources could reduce the response time for recovery, allowing thermal units to carry fewer spinning reserves and increasing operating efficiencies of the grid.

393. NERC and other commenters [187] suggest that the Commission's proposed directive to have NERC include “Requirements that identify the minimum amount of automatic generation control or regulating reserves a balancing authority must have at any given time” is too prescriptive. They also object to this proposed requirement since a balancing authority's failure to maintain sufficient regulating reserves will result in violations of control performance standard criteria already found in BAL-001-0.

394. NERC further states that a requirement to have a minimum amount of regulating reserves would result in an arbitrary constraint that would not add to reliability and suggests that the Commission instead direct NERC to consider the issue of a minimum requirement in its Reliability Standards process in order to determine the reliability benefit.

395. EEI states that the industry currently has no consensus-based, sound engineering methodology for determining a minimum regulating reserve requirement given widely varying needs throughout the country. Nonetheless, EEI offers several guidelines that it says could be used to provide estimates for minimum regulating reserves. Similarly, MidAmerican states that normal regulating margins can vary from one balancing authority to another, and even within one balancing authority, due to frequently changing load characteristics making it extremely difficult to quantify an hourly required level of reserves. MidAmerican suggests that instead of prescriptively quantifying reserve levels, the ERO should continue to allow the industry to find efficient ways to comply with the control performance standards of BAL-001-0.

396. FirstEnergy suggests that a single entity should have the responsibility to establish, through an annual review process, the level of regulating reserves that a balancing authority must maintain pursuant to the control performance standard requirements. FirstEnergy suggests that all generators and technically qualified DSM that participate in energy markets should install automatic generation control as a condition of market participation. In non-market areas, FirstEnergy suggests that balancing authorities could meet requirements through bilateral contracts or the normal scheduling process and suggests that the Commission might have to assert its jurisdiction and order technically qualified DSM providers to install automatic generation control at their facilities. FirstEnergy states that further work would need to be conducted on the technical qualifications and capacity thresholds that would control whether installation of automatic generation control would be required.

(b) Commission Determination

397. On this issue, the Commission directs the ERO to modify BAL-005-0 through the Reliability Standards development process to develop a process to calculate the minimum regulating reserve for a balancing authority, taking into account expected load and generation variation and transactions being ramped into or out of the balancing authority.

398. As a general matter, the Commission believes that a single entity should establish the level of regulating reserve required based on the generation mix and ramping rates in the region. We disagree with commenters that minimum regulating reserve requirements are not necessary. As South Carolina EG correctly points out, the control performance standard metric is a lagging indicator and, as such, does not provide a good indication that the necessary amounts of regulating reserve are being carried at all times. The Commission notes that Requirement R2 requires maintenance of a level of regulating reserves in order to prospectively meet the control performance standard but does not provide a calculation for the exact level which would be required. In particular, the Commission believes that, while the control performance standard metric is useful in identifying trends relating to poor regulating practices, specification of minimum reserve requirements to be maintained at all times would complement the control performance standard metrics by providing real-time requirements necessary for proper control.

399. With regard to Alcoa's comment, the Commission agrees that the quality of reserves is relevant in determining if the resource is able to technically qualify as regulation.

400. Nevertheless, the Commission recognizes commenters' concerns related to the calculation of minimum regulation. EEI has offered several possible methods to calculate the minimum amount of regulation needed for reliability, which may or may not be consistent with others in the industry. The fundamental reason for regulating reserves is to balance load and generation in the short term due to the random variations in the balancing authorities' loads and to accommodate ramping of transactions. The Commission therefore directs the ERO to develop a process to calculate the minimum regulating reserve for a balancing authority, taking into account expected load and generation variation and transactions being ramped into or out of the balancing authority.

ii. Title Change and Inclusion of DSM.

(a) Comments

401. As an initial matter, many commenters express confusion about the Commission's proposal to require NERC to change the title of the Reliability Standard to be neutral as to the source of the reserves, and include DSM and direct control load management as part of contingency reserves. [188] In particular, these commenters argue that this Reliability Standard pertains to regulating reserve and not contingency reserves.

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

403. APPA and International Transmission both disagree with the Commission's proposals to change the title of this Reliability Standard and to include DSM and direct control load management. APPA suggests that DSM and direct control load management are not operationally equivalent to dispatchable generation resources and does not believe these programs are an effective source of regulating reserve given the current state of technology. International Transmission simply states that regulating reserves required by BAL-005-0 are specifically responsive to automatic generation control.

404. ISO-NE disagrees with the Commission's proposal to include DSM and direct control load management as part of this service, stating that responsive load has not demonstrated the load following capability necessary to provide regulation and that it is not aware of any load-based resources that can closely follow automatic generation control signals sent every four seconds. As an alternative to the Commission's approach, ISO-NE suggests that the Reliability Standard should define the reliability purpose or objective and then be resource-neutral.

(b) Commission Determination

405. At the outset, the Commission agrees with commenters that this Reliability Standard applies to regulating reserves and not contingency reserves. The references to contingency reserves under this Reliability Standard in the NOPR are confusing. The Commission clarifies that its direction to the ERO in this section is for it to develop a modification to BAL-005-0 through the Reliability Standards development process that changes the title of the Reliability Standard to be neutral as to the source of regulating reserves and allows the inclusion of technically qualified DSM and direct control load management as regulating reserves, subject to the clarifications provided in this section.

406. We disagree that it is not possible to use DSM and direct control load management as a source of regulating reserves or any other type of operating reserves. The Commission notes that, while DSM and direct control load management may not be widely used today as a source of operating reserves, comments received and other evidence suggest that certain types of loads are technically capable of providing this service. For example, comments received from Alcoa suggest that certain loads, such as digitally controlled DC loads, are capable of responding much faster than generation to a reserve need.

407. Given that most of the commenters' concerns over the inclusion of DSM as part of regulating reserves relate to the technical requirements, the Commission clarifies that to qualify as regulating reserves, these resources must be technically capable of providing the service. In particular, all resources providing regulation must be capable of automatically responding to real-time changes in load on an equivalent basis to the response of generation equipped with automatic generation control. From the examples provided above, the Commission understands that it may be technically possible for DSM to meet equivalent requirements as conventional generators and expects the Reliability Standards development process to provide the qualifications they must meet to participate. These qualifications will be reviewed by the Commission when the revised Reliability Standard is submitted to the Commission for approval.

iii. Whether Balancing Authorities Are Experiencing or Predicting Difficulty in Obtaining Sufficient Automatic Generation Control

(a) Comments

408. Constellation states that its ability to obtain regulating reserves is hampered by a lack of resources that qualify as regulation and the practices that some transmission service providers have adopted in implementing dynamic transfers needed to procure regulating reserves from other balancing authorities. In particular, Constellation states that many transmission service providers impose a requirement that regulation services must be provided using firm transmission. Constellation suggests that purchasing regulation from another balancing authority using non-firm transmission service is allowed under the Reliability Standards and that Requirement R5 of BAL-005-0 provides that balancing authorities must have back-up plans to provide replacement regulation service if the purchased regulation service is lost. Constellation requests that the Commission clarify that the transmission providers may not impose a requirement to rely exclusively on firm transmission for the dynamic transfers of regulating reserves.

(b) Commission Determination

409. In response to Constellation's concerns, the Commission notes that, if regulation is being provided over non-firm transmission service, the entity receiving the regulation should be responsible for having a back-up plan to include loss of the non-firm transmission service as referenced in Requirement R5. The Commission believes that a balancing authority may use non-firm transmission service for procuring regulation, so long as that balancing authority has a back-up plan that it can implement to include loss of non-firm transmission service.

iv. Other Comments

(a) Comments

410. MISO states that it is uncertain of the basis of the claim that there have been an increased number of “[automatic generation control] controllable” frequency excursions. [190] MISO further states that data in the Eastern Interconnection shows the number of larger-slower excursions has decreased over the past few years.

411. Xcel requests that the Commission reconsider Requirement R17 of this Reliability Standard stating that the accuracy ratings for older equipment (current and potential transformers) may be difficult to determine and may require the costly replacement of this older equipment on combustion turbines and older units while adding little benefit to reliability. Xcel states that the Commission should clarify that Requirement R17 need only apply to interchange metering of the balancing area in those cases where errors in generating metering are captured in the imbalance responsibility calculation of the balancing area.

412. FirstEnergy states that Requirement R17 should include only “control center devices” instead of devices at each substation. FirstEnergy states that accuracy at the substation level is unnecessary and the costs to install automatic generation control equipment at each substation would be high. FirstEnergy also states that the term “check” in Requirement R17 needs to be clarified.

413. California Cogeneration states that the Commission has previously ruled that separate metering for the gross generation of a customer-owned generator is not proper or necessary, and states that the Commission should clarify that this Reliability Standard does not establish metering requirements for individual generators, and does not allow separate metering of generation and load on an end-user's site. [191]

414. LPPC notes that BAL-005-0 has 17 requirements but no Measures, and that it uses phrases such as “adequate metering” and “burden on the interconnection.” LPPC contends that there is no definition for these ambiguous terms and that there is no way to determine if terms like “adequate metering” will mean the same thing in different parts of the country or ensure consistent penalties will be assessed for the same violation.

(b) Commission Determination

415. The Commission agrees with MISO that, while the number of frequency deviations due to loss of generation has decreased, the Commission is concerned with the implications of the actual data presented by PJM that shows two frequency deviations each week day without the loss of generation. [192] This concern is supplemented by documents that identify that some balancing authorities are restricting automatic generation control actions during schedule changes. [193]

416. Both Xcel and FirstEnergy question Requirement R17 but do not oppose the Commission's proposal to approve this Reliability Standard. Earlier in this Final Rule, we direct the ERO to consider the comments received to the NOPR in its Reliability Standards development process. Thus, the comments of Xcel and FirstEnergy should be addressed by the ERO when this Reliability Standard is revisited as part of the ERO's Work Plan.

417. California Cogeneration requests clarification that Commission rulings made prior to the enactment of FPA section 215 would still be applicable. The case cited by California Cogeneration was issued before EPAct 2005 was enacted and gave the Commission direct responsibility over Bulk-Power System reliability. By its terms, BAL-005-0 requires each generator operator with generating facilities operating within an Interconnection to ensure that those generating facilities are included within the metered boundaries of a balancing authority area. Therefore, any generator that is subject to the Reliability Standards, as discussed in the Applicability Issues section of this Final Rule, [194] is subject to the metering requirements in this Reliability Standard. Our conclusion, however, does not determine the appropriate ratemaking treatment.

418. With respect to LPPC's concern that terms used in the Reliability Standard are not definitive when viewed individually, and LPPC's statement that the Reliability Standard is ambiguous because it does not include Measures, we disagree. The Commission finds each Requirement of BAL-005-0 is clear and enforceable. The Requirements provide sufficient guidance for an entity to understand its obligations. When Measures are incorporated into the Reliability Standard, the Measures will provide guidance on assessing non-compliance with the Requirements. For these reasons and as previously addressed in the NOPR, the Commission disagrees that the enforceable obligations set forth in Requirements are unclear absent Measures.

419. The Commission notes that no one commented on the proposal to include Levels of Non-Compliance and Measures, including a Measure that provides for a verification process over the minimum required automatic generation control or regulating reserves a balancing authority maintains. The Commission adopts the NOPR proposal to require the ERO to modifiy the Reliability Standards to include a Measure that provides for a verification process over the minimum required automatic generation control or regulating reserves a balancing authority maintains. However, as discussed in the Common Issues section of this Final Rule, we will leave it to the discretion of the ERO whether to include other Measuers. [195]

420. FirstEnergy has a number of suggestions to improve the existing Reliability Standard and the ERO is directed to consider those suggestions in its Reliability Standards development process.

v. Summary of Commission Determinations

421. The Commission approves Reliability Standard BAL-005-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to BAL-002-0 through the Reliability Standards development process that: (1) Develops a process to calculate the minimum regulating reserve a balancing authority must have at any given time taking into account expected load and generation variation and transactions being ramped into or out of the balancing authority; (2) changes the title of the Reliability Standard to be neutral as to the source of regulating reserves and to allow the inclusion of technically qualified DSM and direct control load management; (3) clarifies Requirement R5 of this Reliability Standard to specify the required type of transmission or backup plans when receiving regulation from outside the balancing authority when using non-firm service and (4) includes Levels of Non-Compliance and a Measure that provides for a verification process over the minimum required automatic generation control or regulating reserves a balancing authority must maintain.

g. Inadvertent Interchange (BAL-006-1)

422. BAL-006-1 requires that each balancing authority calculate and record inadvertent interchange on an hourly basis.

423. In the NOPR, the Commission proposed to approve Reliability Standard BAL-006-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to BAL-006-1 that adds Measures and additional Levels of Non-Compliance including Measures concerning the accumulation of large inadvertent imbalances. [196]

424. In addition, the NOPR solicited comment on whether accumulation of large amounts of inadvertent imbalances is a concern to the industry and if so, options to address the accumulation.

i. Measures and Additional Levels of Non-Compliance Including Measures Concerning the Accumulation of Large Inadvertent Imbalances

(a) Comments

425. Certain commenters [197] do not support the Commission's proposal to add Measures and additional Levels of Non-Compliance, including Measures concerning the accumulation of large inadvertent imbalances. Xcel states that such a measure would not enhance reliability and involves primarily a commercial matter. MRO suggests that large inadvertent balances are an equity issue and as such should be addressed through business practices and not through the Reliability Standards. MidAmerican states that no additional measures addressing inadvertent imbalances are needed in this Reliability Standard because the issue is adequately addressed in other Reliability Standards. [198] MidAmerican states that if the Commission proceeds to require Measures and Levels of Non-Compliance for large accumulations, it must insure that no “double penalties” are imposed.

426. EEI believes that the need to set a Measure for the accumulation of large inadvertent imbalances may be premature. EEI suggests that inadvertent energy is not a problem in real-time operations and is the result of frequency over-bias. EEI further states that if the Commission believes the industry should address both inadvertent energy and frequency bias, the clear consequence is a fundamental reconsideration of the control performance standard. EEI strongly recommends that the Commission clarify whether it intends for the industry to reconsider this fundamental reliability principle.

427. Constellation states some concern regarding the ability of balancing authorities to make appropriate arrangements to settle inadvertent imbalances. In particular, Constellation states that in arranging bilateral paybacks, it is difficult to find a counterparty with an opposite balance and there are transmission fees that further hinder the process of these paybacks. Constellation states that the Commission should require the industry to adopt procedures that will better facilitate bilateral payback of inadvertent energy, such as waiving the scheduling requirement for small bilateral paybacks (such as WECC has implemented).

428. TAPS repeats the arguments it made in its comments on the Staff Preliminary Assessment that the existing treatment of balancing authority inadvertent interchange is not comparable to the treatment of energy imbalances. TAPS suggests that the Commission has an obligation to do more than what is proposed in the NOPR, which states that the issue is being addressed in the OATT reform docket [199] while approving Reliability Standards that perpetuate the preferential treatment of balancing authority inadvertent interchange. [200]

(b) Commission Determination

429. The Commission directs the ERO to develop a modification to BAL-006-1 that adds Measures concerning the accumulation of large inadvertent imbalances and Levels of Non-Compliance. While we agree that inadvertent imbalances do not normally affect the real-time operations of the Bulk-Power System and pose no immediate threat to reliability, we are concerned that large imbalances represent dependence by some balancing authorities on their neighbors and are an indication of less than desirable balancing of generation with load. The Commission also notes that the stated purpose of this Reliability Standard is to define a process for monitoring balancing authorities to ensure that, over the long term, balancing authorities do not excessively depend on other balancing authorities in the Interconnection for meeting their demand or interchange obligations.

430. The Commission disagrees with MidAmerican that having Measures in this Reliability Standard will result in double penalties. The Commission believes that this Reliability Standard has an independent reliability goal that “define[s] a process for monitoring balancing authorities to ensure that, over the long term, balancing authorities do not excessively depend on other balancing authority areas in the Interconnection for meeting their demand or interchange obligations.” [201]

431. The Commission agrees with EEI that one of the root causes of inadvertent interchange is the difference between the actual frequency response and the existing bias settings. The Commission has directed that this cause be addressed in other BAL Reliability Standards. If the industry wishes to propose alternative metrics to the control performance Reliability Standards, the Commission suggests that it does so through the ERO processes and that such changes include an explanation of how the revised metrics would better measure the ability of an individual balancing authority to match load and generation.

432. In response to Constellation's comment about the fees associated with the settlement of inadvertent imbalances, the Commission notes that this issue relates to business practices and should be brought before NAESB or otherwise addressed in contexts other than section 215 of the FPA.

433. With respect to TAPS' concerns regarding disparate treatment of imbalances for non-control area utilities, the Commission is not convinced that this is a reliability issue. As identified in Order No. 890, inadvertent interchange is not comparable to imbalances. [202]

434. Accordingly, the Commission adopts the proposal in the NOPR to direct the ERO to develop Measures under this Reliability Standard to ensure balancing authorities will not have large inadvertent imbalances.

ii. Whether the Accumulation of Large Amounts of Inadvertent Imbalances Is a Concern and Potential Options

(a) Comments

435. LPPC states that its members are concerned that large inadvertent imbalances would be an indication of an underlying issue related to overall balancing of resources and demand and suggests that options to address these large inadvertent imbalances should be addressed through the Reliability Standards development process.

436. NERC states that the performance requirements that relate to reliability are addressed in BAL-001-0 and BAL-002-0 and the new Reliability Standards which will replace them. Further, NERC states that if the Commission wishes to direct consideration of limits on the amount of inadvertent imbalances, such directive should be in the form of an issue to be resolved or reliability objective to be achieved rather than a specific requirement to set a fixed limit on inadvertent accumulation.

437. TVA, MISO and MidAmerican state that the accumulation of large inadvertent balances over time does not raise grid reliability issues. TVA asserts that this is largely a financial matter. In addition, TVA comments that if a balancing authority inappropriately uses the interconnection in a way which results in a large inadvertent imbalance this behavior should be reflected in the balancing authority's control performance standard compliance. MISO states that some large amounts of inadvertent imbalance are due to a balancing authority fulfilling its bias obligation. MISO states that an arbitrary cap should not be a part of this Reliability Standard.

(b) Commission Determination

438. As stated previously, while the Commission agrees that these imbalances do not present an immediate reliability problem, we believe, as stated by LPPC, that large interchange imbalances are indicative of an underlying problem related to balancing of resources and demand. It would be worthwhile for the ERO to examine the WECC time error correction procedure.

439. Since the ERO indicates that the reliability aspects of this issue will be addressed in a Reliability Standards filing later this year, the Commission asks the ERO, when filing the new Reliability Standard, to explain how the new Reliability Standard satisfies the Commission's concerns.

iii. Summary of Commission Determinations

440. Accordingly, the Commission approves Reliability Standard BAL-006-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to BAL-006-1 through the Reliability Standards development process that includes Measures concerning the accumulation of large inadvertent imbalances and additional Levels of Non-Compliance.

h. Regional Differences to BAL-006-1: Inadvertent Interchange Accounting and Financial Inadvertent Settlement

441. The NOPR explained that BAL-006-1 provides for two regional differences. [203] First, a regional difference is provided for an RTO with multiple balancing authorities. The control area participants of MISO requested that MISO be given an inadvertent interchange account so that financial settlement of all energy receipts and deliveries using locational marginal pricing could be implemented to meet their Commission directed market obligations. Subsequently, Southwest Power Pool (SPP) requested, and NERC approved, the same regional difference for. [204]

442. Second, the NOPR explained that a regional difference would apply to the control area participants of MISO and SPP that would allow each RTO to financially settle inadvertent energy between control areas in the RTO. Each RTO would maintain accumulations of the net inadvertent interchange for all the control areas in the RTO after the financial settlement, and therefore accumulation of net-interchange would not affect the non-participant control areas.

443. The Commission proposed to approve these regional differences, explaining that the two proposed regional differences relate solely to facilitating financial settlements of accumulated inadvertent interchange due to the physical differences of these areas and have minimal, if any, reliability implications.

i. Comments

444. FirstEnergy notes that the two proposed regional differences reference the Version 0 policies instead of the NERC Reliability Standards and requests that the Commission direct NERC to revise the regional differences accordingly. In addition, FirstEnergy states that the Commission should direct NERC to define the function of a waiver. FirstEnergy agrees that transferring responsibility for the tasks under these waivers to the RTO is appropriate.

ii. Commission Determination

445. No commenter objected to the regional differences to BAL-006-1. However, the Commission agrees with FirstEnergy that the regional differences incorrectly reference retired policy terminology. Therefore, the Commission approves the regional differences as mandatory and enforceable under Order No. 672 as necessary due to the physical differences between multiple balancing authorities and a single market [205] but the Commission directs the ERO to modify the regional differences so that they reference the current Reliability Standards and are in the standard form, which includes Requirements, Measures and Levels of Non-Compliance. The ERO should explore FirstEnergy's request to define the function of a waiver in its Reliability Standards development process.

2. CIP: Critical Infrastructure Protection

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

447. In the NOPR, the Commission proposed to approve Reliability Standard CIP-001-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to CIP-001-0 that: (1) Includes Measures and Levels of Non-Compliance; (2) gives guidance for the term “sabotage;” (3) requires an applicable entity to contact appropriate federal authorities, such as the Department of Homeland Security, in the event of sabotage within a specified period of time and (4) requires periodic review of sabotage response procedures.

448. In the NOPR, the Commission explained that the Requirements of CIP-001-0 refer to a “sabotage event” but do not define that term. The Commission stated that, while “sabotage” is a commonly understood term and the common understanding should suffice in most circumstances, it was concerned that situations may arise in which it is not clear whether action pursuant to CIP-001-0 is required. Thus, the NOPR proposed that the ERO provide guidance clarifying the triggering event for an entity to take action pursuant to CIP-001-0.

a. Comments

449. EEI and Entergy comment that they generally agree with the Commission's perspective. While APPA and Six Cities support approving CIP-001-1 as mandatory and enforceable, they ask that the Commission defer the application of monetary penalties until further guidance is provided on what events are reportable and what steps an entity must take to be certain it is in compliance with the Reliability Standard. Claiming that CIP-001-1 is too vague to be enforceable, TAPS opposes approval until NERC has further defined “sabotage” and the facilities to which the Reliability Standard applies.

450. APPA questions whether CIP-001-1 should apply to LSEs (LSEs) contending that, unlike transmission owners and generators, LSEs do not own or operate “hard assets” that are normally thought of “at risk” to sabotage. It claims that compliance would be particularly burdensome for small LSEs, such as the requirement to provide a preliminary report within one hour of an event. APPA states that NERC should therefore reconsider whether LSEs should be required to comply with this Reliability Standard. Further, while APPA supports the application of CIP-001-1 to larger generators and any unit required for reliable interconnected operations, it questions whether it is critical to extend the Reliability Standard to all generator operators—noting that there are 3,564 generating plants in the United States with a total capacity of 75 MW or less. APPA contends that the incremental benefits of requiring all generators to comply with CIP procedures seem minimal since many facilities are unlikely to have a material impact on Bulk-Power System reliability or be a target for sabotage in the first place. APPA suggests that the Commission defer action on CIP-001-1 while it implements a prioritization plan.

451. TAPS and California Cogeneration are also concerned about applicability and contend that compliance should be limited to those that have a significant or material impact on Bulk-Power System reliability. Both are concerned that compliance with this Reliability Standard would create significant administrative burdens and documentation requirements that are not justified where a facility does not have a material impact on the Bulk-Power System. California Cogeneration suggests that CIP-001-1 be revised to: (1) Exclude generator output used on-site and (2) provide a mechanism for determining that a facility has no material impact and thus is exempt from compliance.

452. A number of commenters agree with the Commission's concern that the term “sabotage” needs to be better defined and guidance provided on the triggering events that would cause an entity to report an event. [208] FirstEnergy states that this definition should differentiate between cyber and physical sabotage and should exclude unintentional operator error. It advocates a threshold of materiality to exclude acts that do not threaten to reduce the ability to provide service or compromise safety and security. SoCal Edison states that clarification regarding the meaning of sabotage and the triggering event for reporting would be helpful and prevent over-reporting.

453. APPA comments that Requirement R1 of CIP-001-1, which provides that an entity must have procedures for recognizing sabotage events and making its personnel aware of sabotage events, while a “good first step,” lacks sufficient detail upon which the ERO can base compliance and enforcement efforts. It characterizes CIP-001-1 as an “entity-specific ‘fill-in-the-blank’ standard” that does not provide sufficient direction or guidance for an entity to determine whether it is in compliance. APPA further states that Measure M1 provides no criteria for a Regional Entity, acting in its capacity as a compliance monitor, to make an objective determination that an entity's sabotage procedure is adequate.

454. In response to the Commission's concern regarding the need for periodic review of sabotage response procedures, FirstEnergy suggests that CIP-001-1 should define what time period is sufficient for periodic reviews and suggests that a bi-annual review would be appropriate. MRO believes that a requirement to annually review the sabotage response procedures should be added to the Reliability Standard.

455. NERC objects to the wording of the Commission's proposed directive that NERC modify CIP-001-1 to require an applicable entity to contact appropriate federal authorities, such as the Department of Homeland Security, in the event of sabotage within a specified period of time. NERC states the Commission's directive is overly prescriptive because it specifies language to be included in the standard and thereby circumvents the Reliability Standards development process. Further, NERC objects that this directive would require entities in other nations such as Canada or Mexico to report to the U.S. Department of Homeland Security. Santa Clara suggests that Requirement R4 (and corresponding measure M3) should be modified to state that “* * * contacts should be established with the appropriate public safety officials or directly with the local Federal Bureau of Investigation (FBI) or Royal Canadian Mounted Police (RCMP) such that communication channels are established to report incidents to the appropriate authority.” It states that, in the case of a municipal utility that is part of a local governmental agency that already has a public safety department which is in regular contact with the local FBI, and where clear communication channels already exist between the public safety department and the utility, it would be redundant for the utility to establish a direct link to the FBI for reporting purposes. Xcel also suggests that the term “appropriate federal authorities” should be modified to avoid conflict with established processes now in place, and that the term should be specifically identified so the Requirements on affected entities are clear.

456. Process Electricity Committee advocates approval of CIP-001-0 as initially proposed by NERC without modification, but it objects to the revised CIP-001-1 as placing an undue burden on smaller entities. It is concerned that the Commission's proposal to require mandatory reporting to appropriate federal authorities within a specific time frame will impose substantial burdens on end users with little or no discernable benefit. It states that there is no evidence that any entities—both regulated and unregulated—under-report sabotage events. Further, according to Process Electricity Committee, the adoption of uniform requirements could require end users to modify existing security programs and procedures that are designed to protect industrial facilities, whereas the utility generator requirements could be conflicting or duplicative.

457. Entergy and FirstEnergy express concern that there is a potential for redundancy between CIP-001-1 and other related federal reporting standards. Entergy states that NERC should consider ensuring that CIP-001-1 is consistent with, but not duplicative of, these other requirements. FirstEnergy states that both the Department of Energy (DOE) and the Energy Information Administration (EIA) impose reporting requirements that are similar to CIP-001-1 and suggests that to avoid conflicts the reporting requirements under this Reliability Standard should be conformed to the existing DOE and EIA requirements. It also states that nuclear units have their own set of operating requirements, including procedures for reporting sabotage, and suggests that a company's compliance with NRC procedures should be presumed to meet NERC standards. EEI, FirstEnergy and Xcel suggest greater coordination, possibly with all events being reported to NERC, which would then coordinate with federal authorities. Xcel suggests the development of a single sabotage reporting form to streamline the reporting process and make it easier for affected entities to provide reports in a timely manner.

458. APPA and FirstEnergy express concern about a requirement to report an act of sabotage within a fixed period of time. Xcel states that the triggering event for disclosure of an act of sabotage often will be unclear and that an investigation will take time especially if the event occurs at an unstaffed or remote facility. Thus, Xcel does not believe that the standard should contain an express time limit for reporting an act of sabotage since the amount of time necessary to make that report may vary depending on the circumstances. FirstEnergy suggests that CIP-001-1 should define the specified period for reporting an incident beginning from when the event is discovered or suspected to be sabotage. APPA is also concerned that a specific time limit for a report (such as a 60 minute requirement) would be burdensome to meet for a small LSE that is not continuously staffed when a triggering event occurs outside staffed hours.

b. Commission Determination

i. Applicability to Small Entities

459. The Commission acknowledges the concerns of the commenters about the applicability of CIP-001-1 to small entities and has addressed the concerns of small entities generally earlier in this Final Rule. Our approval of the ERO Compliance Registry criteria to determine which users, owners and operators are responsible for compliance addresses the concerns of APPA and others.

460. However, the Commission believes that there are specific reasons for applying this Reliability Standard to such entities, as discussed in the NOPR. APPA indicates that some small LSEs do not own or operate “hard assets” that are normally thought of as “at risk” to sabotage. The Commission is concerned that, an adversary might determine that a small LSE is the appropriate target when the adversary aims at a particular population or facility. Or an adversary may target a small user, owner or operator because it may have similar equipment or protections as a larger facility, that is, the adversary may use an attack against a smaller facility as a training “exercise.” The knowledge of sabotage events that occur at any facility (including small facilities) may be helpful to those facilities that are traditionally considered to be the primary targets of adversaries as well as to all members of the electric sector, the law enforcement community and other critical infrastructures.

461. For these reasons, the Commission remains concerned that a wider application of CIP-001-1 may be appropriate for Bulk-Power System reliability. Balancing these concerns with our earlier discussion of the applicability of Reliability Standards to smaller entities, we will not direct the ERO to make any specific modification to CIP-001-1 to address applicability. However, we direct the ERO, as part of its Work Plan, to consider in the Reliability Standards development process, possible revisions to CIP-001-1 that address our concerns regarding the need for wider application of the Reliability Standard. Further, when addressing such applicability issues, the ERO should consider whether separate, less burdensome requirements for smaller entities may be appropriate to address these concerns.

ii. Definition of Sabotage

462. Several commenters agree with the Commission's concern that the term “sabotage” should be defined. For the reasons stated in the NOPR, we direct that the ERO further define the term and provide guidance on triggering events that would cause an entity to report an event. [209] However, we disagree with those commenters that suggest the term “sabotage” is so vague as to justify a delay in approval or the application of monetary penalties. As explained in the NOPR, we believe that the term sabotage is commonly understood and that common understanding should suffice in most instances. [210] Further, in the interim while the matter is being addressed by the Reliability Standards development process, we direct the ERO to provide advice to entities that have concerns about the reporting of particular circumstances as they arise.

463. Further, in defining sabotage, the ERO should consider FirstEnergy's suggestions to differentiate between cyber and physical sabotage and develop a threshold of materiality. However, regarding the latter suggestion, the Commission directs that guidance for a threshold of materiality must be designed carefully to mitigate the risk that an unsuccessful sabotage event is not correctly reported because it did not cause sufficient harm.

iii. Procedures for Recognizing Sabotage Events

464. Requirement R1 of CIP-001-1 provides that an applicable entity must have procedures “for the recognition of and for making their operational personnel aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection.” The NOPR expressed concern that the provision does not establish baseline requirements regarding what issues should be addressed by the developed procedures. APPA goes even further and, characterizing it as an entity specific fill-in-the-blank standard, contends that it lacks sufficient detail upon which the ERO can base compliance and enforcement efforts.

465. While the Commission believes that this Reliability Standard can and should be enhanced by specifying baseline requirements regarding what issues should be addressed in the procedures for recognizing sabotage events and making personnel aware of such events, it disagrees with APPA that Requirement R1 lacks sufficient detail on which to base ERO compliance and enforcement efforts. As indicated in Measure M1, an applicable entity must have and maintain the procedure as defined by Requirement R1. Thus, if an applicable entity cannot provide the required procedure to the ERO or a Regional Entity auditor upon request, it would likely be subject to an enforcement action. While we expect that an applicable entity that has made a good faith effort to develop a meaningful procedure to comply with Requirement R1 (and Measure M1) would not be subject to an enforcement action, an ERO or Regional Entity audit team may provide steps to improve the individual entity's procedure, which would serve as a baseline for that entity for any subsequent audit. Such an approach would be acceptable and allow for meaningful compliance in the interim until CIP-001-1 is modified pursuant to our directive.

iv. Periodic Review of Sabotage Reporting Plans

466. The Commission was concerned that CIP-001-1 did not include a requirement for the periodic review or updating of sabotage reporting plans or procedures, or for the periodic testing of the sabotage reporting procedures to verify that they achieve the desired result. [211] In response, FirstEnergy suggests that a bi-annual review would be appropriate and MRO believes that an annual review requirement should be added to the Reliability Standard. Periodic testing of the procedures through an exercise would assist in determining if the procedures are adequate for achieving the desired result. Lessons learned from these events would help in developing or modifying the sabotage reporting procedures.

467. The Commission affirms the NOPR directive and directs the ERO to incorporate a periodic review or updating of the sabotage reporting procedures and for the periodic testing of the sabotage reporting procedures. At this time, the Commission does not specify a review period as suggested by FirstEnergy and MRO and, rather, believes that the appropriate period should be determined through the ERO's Reliability Standards development process. However, the Commission directs that the ERO begin this process by considering a staggered schedule of annual testing of the procedures with modifications made when warranted formal review of the procedures every two or three years.

v. Mandatory Reporting of a Sabotage Event

468. CIP-001-1, Requirement R4, requires that each applicable entity establish communications contacts, as applicable, with the local FBI or Royal Canadian Mounted Police officials and develop reporting procedures as appropriate to its circumstances. The Commission in the NOPR expressed concern that the Reliability Standard does not require an applicable entity to actually contact the appropriate governmental or regulatory body in the event of sabotage. Therefore, the Commission proposed that NERC modify the Reliability Standard to require an applicable entity to “contact appropriate federal authorities, such as the Department of Homeland Security, in the event of sabotage within a specified period of time.” [212]

469. As mentioned above, NERC and others object to the wording of the proposed directive as overly prescriptive and note that the reference to “appropriate federal authorities” fails to recognize the international application of the Reliability Standard. The example of the Department of Homeland Security as an “appropriate federal authority” was not intended to be an exclusive designation. Nonetheless, the Commission agrees that a reference to “federal authorities” could create confusion. Accordingly, we modify the direction in the NOPR and now direct the ERO to address our underlying concern regarding mandatory reporting of a sabotage event. The ERO's Reliability Standards development process should develop the language to implement this directive.

470. As noted above, FirstEnergy, EEI and others express concern regarding the potential for redundant reporting under CIP-001-1 and other government reporting standards, and the need for greater coordination. The Commission understands the concern about multiple reporting channels that may arise and the burden that this may present to applicable entities. We direct the ERO to explore ways to address these concerns—including central coordination of sabotage reports and a uniform reporting format—in developing modifications to the Reliability Standard with the appropriate governmental agencies that have levied the reporting requirements.

471. The Commission stated that the reporting of a sabotage event should occur within a fixed period of time, and referred to a Homeland Security procedure that references a 60-minute period for submitting a preliminary report and a follow-up report within four to six hours. [213] While commenters raise a number of concerns about the need for fairness in the implementation of such a requirement, they do not challenge the NOPR's underlying concern or the appropriateness of such a provision. The Commission believes that an applicable entity should report a sabotage event in a timely manner to allow government authorities and critical infrastructure members the opportunity to react in a meaningful manner to such information. Thus, the Commission directs the ERO to modify CIP-001-1 to require an applicable entity to contact appropriate governmental authorities in the event of sabotage within a specified period of time, even if it is a preliminary report. The ERO, through its Reliability Standards development process, is directed to determine the proper reporting period. In doing so, the ERO should consider suggestions raised by commenters such as FirstEnergy and Xcel to define the specified period for reporting an incident beginning from when an event is discovered or suspected to be sabotage, and APPA's concerns regarding events at unstaffed or remote facilities, and triggering events occurring outside staffed hours at small entities.

c. Summary of Commission Determinations

472. As explained in the NOPR, while the Commission has identified concerns regarding CIP-001-1, we believe that the proposal serves an important purpose in ensuring that operating entities properly respond to sabotage events to minimize the adverse impact on the Bulk-Power System. Accordingly, the Commission approves Reliability Standard CIP-001-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop the following modifications to the Reliability Standard through the Reliability Standards development process: (1) Further define sabotage and provide guidance as to the triggering events that would cause an entity to report a sabotage event; (2) specify baseline requirements regarding what issues should be addressed in the procedures for recognizing sabotage events and making personnel aware of such events; (3) incorporate a periodic review or updating of the sabotage reporting procedures and for the periodic testing of the sabotage reporting procedures and (4) require an applicable entity to contact appropriate governmental authorities in the event of sabotage within a specified period of time. In addition, we direct the ERO, as part of its Work Plan, to consider revisions to CIP-001-1 that address our concerns regarding applicability to smaller entities. The ERO should also consider consolidation of the sabotage reporting forms and the sabotage reporting channels with the appropriate governmental authorities to minimize the impact of these reporting requirements on all entities.

3. COM: Communications

473. The Communications (COM) group contains two Reliability Standards. The first requires that transmission operators, balancing authorities and other applicable entities have adequate internal and external telecommunications facilities for the exchange of interconnection and operating information necessary to maintain reliability. The second Reliability Standard requires that these communication facilities be staffed and available to address real-time emergencies and that operating personnel carry out effective communications.

474. The NOPR contained a discussion of how the transmission operator and generator operator function would apply to RTO, ISO and pooled resource organizations. In this Final Rule, conclusions concerning those issues are covered in the Applicability Issues section. [214] In essence, an organization may, but does not have to, accept compliance responsibility on behalf of its members. Since telecommunication is vital to the Reliable Operation of the Bulk-Power System, the Commission finds that it is not permissible to have either unnecessary overlaps or gaps in telecommunications.

a. Telecommunications (COM-001-1)

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

476. The Commission proposed to approve Reliability Standard COM-001-0 as mandatory and enforceable. In addition, the Commission proposed to direct that NERC submit a modification to COM-001-0 that: (1) Includes Measures and Levels of Non-Compliance; (2) includes generator operators and distribution providers as applicable entities and (3) includes Requirements for communication facilities for use during emergency situations.

477. In addition, the Commission sought comments on specific requirements or performance criteria for telecommunications facilities, noting that COM-001-0 might be improved by providing specific requirements for adequacy, redundancy, diverse routing, and periodic testing. The Commission also sought comments on whether the relative roles of applicable entities should be considered when setting down requirements for telecommunication facilities, since the needs will vary based on role.

478. Most comments address the specific modifications and concerns raised by the Commission in the NOPR. Below, we address each topic separately, followed by a summary of our conclusions.

i. Applicability to Generator Operators and Distribution Providers and their Telecommunications Facility Requirements

479. The Commission stated in the NOPR that communications with generator operators and distribution providers are necessary to maintain system reliability during normal and emergency situations, while recognizing that telecommunication facility needs will vary between these two entities and other reliability entities such as reliability coordinators, transmission operators and balancing authorities. The Requirements for each of these entities will vary according to its respective roles.

(a) Comments

480. EEI supports the goals stated by the Commission with regard to COM-001-1, in particular, the need to apply this Reliability Standard to distribution providers. TVA agrees with the Commission's reasoning that generator operators and distribution providers should be subject to this Reliability Standard, but seeks clarification that such entities may transfer their responsibility for data sharing with and reporting to NERC and Regional Entities by contract to another entity.

481. In contrast, MRO, APPA, TAPS and SDGE indicate that applying this Reliability Standard to generator operators and distribution providers may not be appropriate. APPA argues generator operators and distribution providers do not affect the Bulk-Power System in the same manner as a reliability coordinator, balancing authority or transmission provider does, since generator operators and distribution providers only have a secondary or support role with respect to reliability of the Bulk-Power System.

482. Further, APPA and SDGE are concerned that the Commission's proposal would unnecessarily subject generator operators and distribution providers to Requirements that were designed for transmission operators. For example, APPA indicates that NERCNet was designed as part of the NERC Interregional Security Network for communications among reliability coordinators, balancing authorities and transmission operators, and was not designed to connect generators to their balancing authorities and distribution providers to their transmission operators. Further, SDGE submits that, while generator operators and distribution providers may logically have some role in enabling communications that help ensure reliability, SDGE sees no basis for subjecting such entities to the same, extensive requirements incumbent on transmission operators.

483. APPA argues that, while telecommunications Reliability Standards with generator operators and distribution providers as applicable entities may be needed, they are already subject to telecommunications requirements as part of their bilateral interconnection agreements with balancing authorities and transmission providers. It contends that if NERC deems it necessary, a separate Reliability Standard should be developed to govern telecommunications between balancing authorities and generator operators, and between transmission operators and distribution providers under their respective footprints.

484. TAPS states that Requirement R1.4 has an ambiguous requirement [216] that, if applied to distribution providers and generator operators, would impose redundancy requirements well beyond what is reasonably necessary for Bulk-Power System reliability. Further it asserts that the NOPR provides no basis for expanding the Reliability Standard to small entities, such as a 2-MW distribution provider or generator, much less than one that has no connection to the bulk transmission system. Finally, TAPS contends that, in making this proposal, the Commission is “over-stepping its bounds” by not leaving it to the ERO's expert judgment whether COM-001-1 has sufficient coverage to protect Bulk-Power System reliability and states that, in any event, applicability should be limited through NERC's registry criteria and definition of bulk electric system.

485. MRO further states that applying this Reliability Standard to generator operators and distribution providers and including Requirements for communication facilities for use during emergency situations may also not be appropriate if the distribution provider does not operate its own systems.

486. California PUC believes that the Commission's assertion of authority to impose Reliability Standards applicable to either generator operators or distribution providers should be extremely limited, and should be based on an essential nexus between the proposed Reliability Standard and the operation of the Bulk-Power System. It contends that this aspect of the Commission's proposed directive is duplicative and unnecessary when applied to entities in California, and risks being counterproductive unless applied with considerable restraint since California PUC's Operation Standards require power plants to maintain the ability to communicate with the balancing authority at all times, and to plan for the continuity of communications during emergencies.

487. Process Electricity Committee agrees that the extent and maintenance of telecommunication facilities should vary based on the operator's potential affect on system reliability. It points out that existing regulations and contractual obligations already require end users to maintain adequate communications facilities. Further, it states that on-site generation interconnected with the electricity grid typically is required to maintain sufficient telecommunications facilities between the generator owner or operator and the grid operator. In the absence of evidence that this arrangement is inadequate, Process Electricity Committee recommends that the amended COM Reliability Standards be clarified so that they do not impose new requirements on end users and other entities that have only minimal impact on the reliability of the interconnected transmission network.

(b) Commission Determination

488. The Commission reaffirms its position that generator operators and distribution providers should be included as applicable entities in COM-001-1 to ensure there is no reliability gap during normal and emergency operations. For example, during a blackstart when normal communications may be disrupted, it is essential that the transmission operator, balancing authority and reliability coordinator maintain communications with their distribution providers and generator operators. However, the current version of Reliability Standard COM-001-1 does not require this because it does not include generator operators and distribution providers as applicable entities. We clarify that the NOPR did not propose to require redundancy on generator operators' or distribution providers' telecommunication facilities or that generator operators or distribution providers be trained on anything not related to their functions during normal and emergency conditions. We expect the telecommunication requirements for all applicable entities will vary according to their roles and that these requirements will be developed under the Reliability Standards development process.

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

490. The Commission agrees with APPA that the primary purpose of Requirement R6 is to provide information to ensure reliable interregional operations and therefore should not apply to generator operators and distribution providers. However, we disagree that this leads to the conclusion that generator operators and distribution providers should not be included in COM-001-1. As we have stated, telecommunication requirements for all applicable entities will vary according to their roles. In modifying COM-001-1 through the Reliability Standards development process, the Commission believes that the ERO should create appropriate telecommunications requirements for generator operators and distribution providers, which may be additional and separate Requirements to COM-001-1 or, alternatively, a new Reliability Standard as suggested by APPA.

491. In response to SDGE, the Commission's intent is not to subject generator operators and distribution providers to the same requirements placed on transmission operators. As part of the modification of this Reliability Standard or development of a new Reliability Standard to include the appropriate telecommunications facility requirements for generator operators and distribution providers, the ERO should take into account what would be required of generator operators and distribution providers in terms of telecommunications for the Reliable Operation of the Bulk-Power System, instead of applying the same requirements as are placed on other reliability entities such as reliability coordinators, balancing authorities and transmission operators.

492. With regard to TAPS's comment, the Commission has identified a concern and directs that the ERO address the matter through its Reliability Standards development process. This comports with section 215(d)(5) of the FPA which authorizes the Commission, upon its own motion, to order the ERO “to submit to the Commission a proposed Reliability Standard or a modification to a Reliability Standard that addresses a specific matter if the Commission considers such a new or modified Reliability Standard appropriate to carry out this section.” We have identified such a matter and have left to the ERO to develop a specific proposal by invoking its Reliability Standards development process. Further, consistent with our discussion above regarding applicability of Reliability Standards, applicability would be limited through NERC's registry criteria and definition of bulk electric system at this time.

493. In response to California PUC, in this Final Rule we are initially limiting the applicability of these Reliability Standards to those users, owners and operators of the Bulk-Power System on the ERO's compliance registry. The Commission notes that it has jurisdiction under section 215 of the FPA over all users, owners and operators of the Bulk-Power System to ensure Reliable Operation of the Bulk-Power System. To ensure reliability, it is important to include appropriate generator operators and distribution providers as applicable entities in Reliability Standard COM-001-1. However, any generator operator or distribution provider that is not a user, owner or operator of the Bulk-Power System will not be included. Also, at this time, the Bulk-Power System is defined on the basis of the ERO's definition of the “bulk electric system.” The Commission believes that this should satisfy California PUC's concern that this Reliability Standard be limited to Bulk-Power System operations. We will not further limit our directive as to which entities this Reliability Standard should apply.

494. As we explained in the NOPR, communication with generator operators and distribution providers becomes especially important during an emergency when generators with black start capability must be placed in service and nearby loads restored as an initial step in system restoration. This occurs at a critical time when normal communication paths may be disrupted. While many generator operators and distribution providers may have telecommunications requirements pursuant to a bilateral contract as indicated by APPA, it is important that all generator operators and distribution providers identified by the ERO through its registration process are subject to uniform telecommunications requirements. Therefore, we adopt our proposal to require the ERO to modify COM-001-1 to apply to generator operators and distribution providers. However, we recognize that some of the existing requirements (such as Requirement R6 related to NERCNet) need not apply to generator operators and distribution providers. In light of commenters' concerns, as an alternative, it would be acceptable for the ERO to develop a new Reliability Standard that would specifically address an appropriate range of Requirements for telecommunication facilities of generator operators and distribution providers that reflect their respective roles on Reliable Operation of the Bulk-Power System.

ii. Requirements for Telecommunications Facilities

495. The Commission sought comment on specific requirements or performance criteria for telecommunication facilities and whether the modified Reliability Standard should provide requirements that also consider the relative role of applicable entities.

(a) Comments

496. A number of commenters agree with the Commission that the relative role of an entity should be taken into account when specifying the requirements for its telecommunications facilities. [218] For example, ISO-NE states that a single generator operator will not need the level of redundancy and diverse routing that a reliability coordinator needs.

497. Many commenters recommend that telecommunications facilities requirements should be specified in broad terms. EEI, APPA, Alcoa, International Transmission, LPPC and SoCal Edison believe that revision to COM-001-1 should provide specific or minimum requirements for adequacy, redundancy and diverse routing. However, EEI, Alcoa and Northern Indiana maintain that entities should have flexibility in meeting the requirements and to allow for innovative technological advancements. Alcoa and Northern Indiana maintain that without flexibility, an applicable entity may choose a less optimal solution just to comply with the Reliability Standard. EEI asserts that such flexibility will also permit alternative means of implementing the requirements that will translate into cost savings. International Transmission cautions that we should not prejudice the modification of this Reliability Standard by indicating the specific requirements or the performance criteria.

498. APPA states that, because the communications requirements for an entity that is responsible for serving 3,000 MW of load is distinctly different from another entity that serves 30 MW of load, the ERO should take the size of the entity into consideration.

499. NERC believes that the questions posed by the NOPR regarding performance criteria should be considered through the Reliability Standards development process, in accordance with NERC's Work Plan, which will allow a broader industry debate on the requirements for telecommunications facilities. This approach will avoid any potential conflicts with the requirements already established in the telecommunications industry and by the Institute of Electrical and Electronics Engineers.

500. Entergy states that it is unclear what cyber assets are covered by COM-001-0. Entergy believes that the Reliability Standard should focus on telecommunications that support the operation of critical assets. Entergy also believes that COM-001-0 should be expanded to include advances in communications technology. It states that NERC should consider addressing the following in a way that will facilitate an understanding of the Reliability Standards' requirements: (1) Voice communications; (2) command and control data communications; (3) security coordination data communications; (4) digital messaging communications; (5) human linguistic convention and (6) other types of communications, including video conferencing and communications with remote security cameras. Entergy believes that this could be accomplished through an enhancement to the definition of communications in the NERC glossary and recasting COM-001-0 to improve the specificity of requirements for each form of communication. Finally, Entergy believes that Requirement R4 of COM-001-0, which requires reliability coordinators, transmission operators and balancing authorities to use English in all types of communications, should apply only to verbal and written communications.

501. FirstEnergy asserts that the Requirement R2 is unclear because it does not specify whether the phrase “telecommunication facilities” covers both voice and data facilities in the context of alarms. It states that, although the word “telecommunications facilities” is generally understood to mean both voice and data facilities, the current practice is to display alarms only for data facilities. Requirement R2 could be misinterpreted to require alarms on voice facilities as well, which would be impractical.

502. Six Cities is concerned that the scope of improper conduct under the “NERCNet security policy” in Attachment 1 is virtually limitless [219] Six Cities recognizes that it would be difficult to provide a comprehensive and detailed list of all conduct that might be considered a misuse of NERCNet data, but that difficulty does not justify exposing NERCNet users to the risk of monetary penalties based on amorphous and unbounded descriptions of potentially violative conduct. Six Cities states that one solution would be to limit the imposition of monetary penalties for misuse of NERCNet data to instances where such misuse is intentional or grossly negligent. According to Six Cities, it would be appropriate to exact a monetary penalty where a NERCNet user deliberately uses NERCNet data for unauthorized or unreasonable purposes. Six Cities asks that it be modified to provide for a warning for the improper disclosure of NERCNet data where the disclosure was not intentional or grossly negligent.

(b) Commission Determination

503. The Commission adopts its NOPR proposal that telecommunications facility requirements must reflect the roles of the respective operating or reliability entities that are included in the applicability section in this Reliability Standard and how they would affect the reliability of the Bulk-Power System. We note that most commenters agree with this approach.

504. The Commission agrees with commenters that flexibility is important in setting telecommunications requirements in order to foster innovation, allow the adoption of new technologies and provide for cost-effective solutions for compliance with the Reliability Standard. However, the Commission finds that certain modifications to COM-001-1 are necessary to ensure system reliability. We believe that the ERO must specify requirements for using telecommunications facilities during normal and emergency conditions that: (1) Reflect the roles of the applicable entities and their impact on Reliable Operation and (2) include adequate flexibility. Accordingly, the Commission directs the ERO to modify COM-001-1 through the Reliability Standards development process to address our concerns. The Commission believes that the concerns of Entergy and FirstEnergy are best addressed by the ERO in the Reliability Standards development process.

505. Six Cities suggests specific new improvements to COM-001-1. As stated above, such comments should be addressed as the ERO modifies the Reliability Standards in the Reliability Standards development process.

iii. Measures and Levels of Non-Compliance

506. In its November 15, 2006, filing, NERC submitted COM-001-1, which supersedes the Version 0 Reliability Standard. COM-001-1 adds Measures and Levels of Non-Compliance to the Version 0 Reliability Standard.

(a) Comments

507. ISO-NE notes that Compliance 1.1 of COM-001-0 specifies that “Regional Reliability Organizations shall be responsible for compliance monitoring * * *.” ISO-NE suggests that since NERC designed and created NERCNet, NERC should be responsible for maintaining and ensuring the compliance with the Reliability Standard rather than regional reliability organizations. ISO-NE recommends that the Commission direct NERC to modify Compliance 1.1 to provide that NERC shall be responsible for monitoring compliance of the NERCNet user organizations.

(b) Commission Determination

508. With respect to ISO-NE's comment, we find that a regional reliability organization does not have any role with compliance matters; that role is reserved for the ERO or the Regional Entities. However, we disagree with ISO-NE that the ERO must replace the regional reliability organization as the compliance monitor. The fact that NERC designed and created NERCNet does not require the ERO to be the compliance monitor. Section 215 of the FPA states that the ERO may delegate compliance and enforcement authority to a Regional Entity, even if the ERO creates the Reliability Standards. Therefore, although we direct that the regional reliability organization should not be the compliance monitor for NERCNet, we leave it to the ERO to determine whether it is the appropriate compliance monitor or if compliance should be monitored by the Regional Entities for NERCNet User Organizations.

iv. Summary of Commission Determination

509. While the Commission has identified a number of concerns with regard to COM-001-1, this Reliability Standard is independently enforceable without the modifications we are directing. Therefore, the Commission approves Reliability Standard COM-001-1 as mandatory and enforceable. Because of the importance of this Reliability Standard in requiring transmission operators and others to have necessary telecommunications equipment, we additionally, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, direct the ERO to develop a modification to COM-001-1 through the Reliability Standards development process that: (1) Expands the applicability to include generator operators and distribution providers and includes Requirements for their telecommunications facilities; (2) identifies specific requirements for telecommunications facilities for use in normal and emergency conditions that reflect the roles of the applicable entities and their impact on Reliable Operation and (3) includes adequate flexibility for compliance with the Reliability Standard, adoption of new technologies and cost-effective solutions. As an alternative to applying this Reliability Standard to generator operators and distribution providers, the ERO may develop a new Reliability Standard that will address the Requirements for telecommunication facilities applicable to generator operators and distribution providers.

b. Communications and Coordination (COM-002-2)

510. COM-002-2 [220] seeks to ensure that transmission operators, generator operators and balancing authorities have adequate communications and that their communications capabilities are staffed and available to address real-time emergency conditions. This Reliability Standard requires balancing authorities and transmission operators to notify others through pre-determined communication paths of any condition that could threaten the reliability of their areas or when firm load shedding is anticipated.

511. The Commission proposed in the NOPR to approve Reliability Standard COM-002-1 as mandatory and enforceable. In addition, the Commission proposed to direct that NERC submit a modification to COM-002-1 that: (1) Includes Measures and Levels of Non-Compliance; (2) includes a Requirement for the reliability coordinator to assess and approve actions that have impacts beyond the area views of transmission operators or balancing authorities; (3) includes distribution providers as applicable entities and (4) requires tightened communications protocols, especially for communications during alerts and emergencies. With respect to this final issue, the Commission proposed alternatively to direct NERC to develop a new Reliability Standard that responds to Blackout Report Recommendation No. 26, which deals with the need for tightened communications protocols.

i. Applicability to Distribution Providers

(a) Comments

512. While EEI states that there is a clear need to apply the Reliability Standard to distribution providers, APPA finds the proposal problematic because it would mean that close to 2,000 public power systems would have to be added to the compliance registry. APPA argues that the Commission should instruct NERC to consider the applicability of COM-002-2 to distribution providers through its Reliability Standards development process. MRO requests that the Commission clarify whether the distribution providers will continue to operate their own systems in the future.

(b) Commission Determination

513. The Commission finds that, during both normal and emergency operations, it is essential that the transmission operator, balancing authority and reliability coordinator have communications with distribution providers. In response to APPA, as discussed above, any distribution provider that is not a user, owner or operator of the Bulk-Power System would not be required to comply with COM-002-2, even though the Commission is requiring the ERO to modify the Reliability Standard to include distribution providers as applicable entities. APPA's concern that 2,000 public power systems would have to be added to the compliance registry is misplaced, since, as we explain in our Applicability discussion above, we are approving NERC's registry process, including the registry criteria. Therefore, we adopt our proposal to require the ERO to modify COM-002-2 to apply to distribution providers through its Reliability Standards development process.

514. The Commission believes that this Reliability Standard does not alter who would operate a distribution provider's system. It only concerns communications, not the operation of the distribution system.

ii. Measures and Levels of Non-Compliance

(a) Comments

515. APPA notes that the Levels of Non-Compliance for COM-002-2 are inadequate in two respects: (1) reliability coordinators are not included in any Level of Non-Compliance and (2) the Levels of Non-Compliance for transmission operators and balancing authorities in Compliance D.2 do not reference Requirements R1 and R2. Therefore, APPA would support approval of COM-002-2 as a mandatory Reliability Standard, but would not support levying penalties for violating incomplete portions of the Reliability Standard.

(b) Commission Determination

516. As stated in the Common Issues section, a Reliability Standard is enforceable even if it does not contain Levels of Non-Compliance. [221] However, the Commission agrees with APPA that this Reliability Standard could be improved by incorporating the changes proposed by APPA. Therefore, when reviewing the Reliability Standard through the Reliability Standards development process, the ERO should consider APPA's concerns.

iii. Reliability Coordinator Assessment and Approval of Actions that have Impacts Beyond the Area Views of Transmission Operators and Balancing Authorities

(a) Comments

517. Alcoa argues that there is a need for communication regarding operating actions taken by transmission operators and balancing authorities that may have impacts beyond their area views. However, a number of commenters oppose the Commission's proposal to modify the Reliability Standard to require reliability coordinators to assess and approve actions that have impacts beyond the area views of transmission operators or balancing authorities and seek clarifications. [222] Alcoa, California PUC, SDGE and Xcel are concerned that obtaining approval from reliability coordinators could create delays in completing the operating action in emergency situations. Xcel and Alcoa request that the Commission clarify that this requirement would not prevent timely performance by a transmission operator of actions necessary to maintain the reliability of its system under emergency conditions. [223] Both Alcoa and Xcel are concerned that waiting for an assessment and approval by a reliability coordinator may not be feasible, especially during emergencies. Xcel further asks the Commission to clarify that the entity taking operating actions should not be held responsible for delays caused by the reliability coordinator's assessment and approval. Alcoa suggests that there should be a clear definition of what actions have an impact beyond the area views of transmission operators or balancing authorities. SDGE further states that serious damage to transmission equipment could occur if the transmission operator is not able to take immediate action during an emergency.

518. ISO-NE is concerned that the Commission proposal goes too far and if implemented, will prevent capable transmission operators from quickly addressing reliability problems that may arise. It maintains that transmission operators usually do not have enough time to inform the reliability coordinator, who must then “assess and approve” the proposed action. If the Commission's proposal is implemented, transmission operators will doubt themselves and delay necessary action. However, it does not see any problem for the New England balancing area and the NPCC region, because ISO-NE serves as the New England reliability coordinator, balancing authority and transmission operator.

519. APPA contends that the Commission's proposed directive appears to have been covered under Reliability Standard IRO-005-1. EEI agrees, stating that IRO-005-1 already requires a reliability coordinator to ensure that transmission operators and balancing authorities operate to prevent action or non-action that will impact neighboring areas. [224]

(b) Commission Determination

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

521. Further, we clarify that we did not propose to require an entity to inform its reliability coordinator of every action it takes. Instead, the proposed directive included a Requirement for the reliability coordinator to assess and approve only those actions that have impacts beyond the area views of transmission operators and balancing authorities. We remain convinced that it is the reliability coordinator's responsibility to ensure Reliable Operation of its reliability coordinator area. The reliability coordinator must also ensure that actions taken by operating entities under its authority will not have wide-area impacts that would adversely impact Reliable Operation of the Bulk-Power System. Therefore, we adopt the proposed directive as stated in the NOPR.

522. In response to commenters, the Commission clarifies that the proposed directive does not conflict with the transmission operators' and balancing authorities' rights to take actions necessary to preserve reliability of their areas and alleviate operating emergencies, consistent with Requirement R1 and R2 in TOP-001-1. [226] Further, the proposed directive does not in any way diminish their operating authority regarding local area reliability for normal and emergency situations, a responsibility that is under the responsibility of a transmission operator or a balancing authority. However, the majority of their operating actions are not emergency actions and would only affect a transmission operator's or balancing authority's area of responsibilities. Since these actions are expected to have little impact outside of the transmission operator's or balancing authority's area, the authority to take unilateral actions remains with the transmission operator or balancing authority. Other non-emergency actions should be coordinated with the reliability coordinator prior to taking action.

523. Regarding SDGE's concern that serious damage to transmission equipment could occur if the transmission operator is not able to take immediate action during an emergency, we believe this is adequately addressed under Requirement R3 of TOP-001-0 which provides that operating entities need not comply with directives from reliability coordinators when such actions would violate safety, equipment, regulatory or statutory requirements.

524. NERC should consider Xcel's suggestion that the entity taking operating actions should not be held responsible for delays caused by the reliability coordinator's assessment and approval in the Reliability Standards development process. We note that the operating entity has the authority to take emergency actions to protect its system that may circumvent or preempt the reliability coordinator's approval process under TOP-001-1 Requirement R3 in cases of personnel safety, potential equipment failure or environmental needs.

525. We disagree with commenters that the Commission's proposed directive is already covered under Requirement R13 of IRO-005-1, which requires each reliability coordinator to ensure that all transmission operators, balancing authorities and others operate to prevent the likelihood that a disturbance, action, or non-action in its reliability coordinator area will result in a SOL and IROL violation in another area of the Interconnection. In order for the reliability coordinator to carry out its function under IRO-005-1, it must have information from the transmission operators and balancing authorities. However, IRO-005-1 does not require transmission operators and balancing authorities to provide the reliability coordinator with the information it would need to prevent the likelihood that an action from these two entities will result in a SOL or IROL violation in another area of the Interconnection. The Commission's directive ensures that the reliability coordinator has such information. Therefore, we do not believe that COM-002-2 is duplicative of IRO-005-1.

526. Accordingly, we direct the ERO to include a Requirement for the reliability coordinator to assess and approve actions that have impacts beyond the area views of transmission operators or balancing authorities, including how to determine whether an action needs to be assessed by the reliability coordinator. This Requirement is best developed under the Reliability Standards development process including the consideration whether this Requirement should be included in this communications Reliability Standard or an operating Reliability Standard.

iv. Tightened Communications Protocols

527. The Blackout Report cited ineffective communications as a factor common to the August 14, 2003 blackout and other previous major outages in North America. [227] In addition, Recommendation No. 26 of the Blackout Report instructed NERC, working with reliability coordinators and control area operators, to “[t]ighten communications protocols, especially for communications during alerts and emergencies * * * ”. [228] In the NOPR, the Commission endorsed Blackout Recommendation No. 26 and proposed to direct the ERO to require tightened communications protocols, especially for communications during alerts and emergencies. Alternatively, we proposed to direct the ERO to develop a new Reliability Standard that responds to the Blackout Report Recommendation.

(a) Comments

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

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

530. APPA believes that the communications protocols to be used during emergencies should be included in the relevant Reliability Standard that governs each type of emergency, rather than in COM-002-2. For example, Requirement R3 of Reliability Standard VAR-002-1 establishes the protocol for communication with the transmission operator if a generator loses its ability to provide voltage control. By keeping the necessary communication protocols clustered with the events to which they apply, NERC would make the Reliability Standards more user-friendly.

531. MISO claims that Blackout Report Recommendation No. 26 on tightened communications protocols dealt primarily with NERC infrastructure and has been fully implemented. It is concerned that developing measures that require ongoing administration will impede rather than improve timely communications in an emergency.

(b) Commission Determination

532. We adopt our proposal to require the ERO to establish tightened communication protocols, especially for communications during alerts and emergencies, either as part of COM-002-2 or as a new Reliability Standard. We note that the ERO's response to the Staff Preliminary Assessment supports the need to develop additional Reliability Standards addressing consistent communications protocols among personnel responsible for the reliability of the Bulk-Power System.

533. While we agree with EEI that EOP-001-0, Requirement R4.1 requires communications protocols to be used during emergencies, we believe, and the ERO agrees, that the communications protocols need to be tightened to ensure Reliable Operation of the Bulk-Power System. We also believe an integral component in tightening the protocols is to establish communication uniformity as much as practical on a continent-wide basis. This will eliminate possible ambiguities in communications during normal, alert and emergency conditions. This is important because the Bulk-Power System is so tightly interconnected that system impacts often cross several operating entities' areas.

534. Regarding APPA's suggestion that it may be beneficial to include communication protocols in the relevant Reliability Standard that governs those types of emergencies, we direct that it be addressed in the Reliability Standards development process.

535. In response to MISO's contention that Blackout Report Recommendation No. 26 has been fully implemented, we note that Recommendation No. 26 addressed two matters. We believe MISO is referring to the second part of the recommendation requiring NERC to “[u]pgrade communication system hardware where appropriate” instead of tightening communications protocols. While we commend the ERO for taking appropriate action in upgrading its NERCNet, we remind the industry to continue their efforts in addressing the first part of Blackout Recommendation No. 26.

536. Accordingly, we direct the ERO to either modify COM-002-2 or develop a new Reliability Standard that requires tightened communications protocols, especially for communications during alerts and emergencies.

v. Other Issues

(a) Comments

537. Santa Clara requests clarification whether the phrase “Such communications shall be staffed and available” in Requirement R1 applies only to operating staff available on site at all times or includes repair personnel who are available only on an on-call basis.

538. FirstEnergy asks that the Reliability Standard specify what is meant by “staffed” and states that the term should not require a physical presence at all facilities at all times because some units, such as peaking units, are not staffed 24 hours a day. In addition, FirstEnergy suggests that, because nuclear units are already subject to communications requirements in their operating procedures, their compliance with NRC operating procedures should be deemed in compliance with the NERC Reliability Standards.

539. Similarly, Six Cities states that, to avoid unnecessary staffing burdens, particularly for smaller entities, the Commission should direct NERC to clarify COM-002-2 by providing that identification of an emergency contact person on call to respond to real-time emergency conditions will constitute adequate compliance.

(b) Commission Determination

540. Santa Clara, FirstEnergy and Six Cities suggest specific new improvements to the Reliability Standards. As stated above, such comments should be considered as the ERO modifies the Reliability Standards in the Reliability Standards development process.

vi. Summary of Commission Determination

541. While the Commission identified concerns regarding COM-002-2, the proposed Reliability Standard serves an important purpose by requiring users, owners and operators to implement the necessary communications and coordination among entities. Accordingly, the Commission approves Reliability Standard COM-002-2 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to COM-002-2 through the Reliability Standards development process that: (1) Expands the applicability to include distribution providers as applicable entities; (2) includes a new Requirement for the reliability coordinator to assess and approve actions that have impacts beyond the area view of a transmission operator or balancing authority [231] and (3) requires tightened communications protocols, especially for communications during alerts and emergencies. Alternatively, with respect to this final issue, the ERO may develop a new Reliability Standard that responds to Blackout Report Recommendation No. 26 in the manner described above. Finally, we direct the ERO to include APPA's suggestions to complete the Measures and Levels of Non-Compliance in its modification of COM-002-2 through the Reliability Standards development process.

4. EOP: Emergency Preparedness and Operations

542. The Emergency Preparedness and Operations (EOP) group of proposed Reliability Standards consists of nine Reliability Standards that address preparation for emergencies, necessary actions during emergencies and system restoration and reporting following disturbances.

a. Emergency Operations Planning (EOP-001-0)

543. NERC's proposed Reliability Standard EOP-001-0 requires each transmission operator and balancing authority to develop, maintain and implement a set of plans to mitigate operating emergencies. These plans must be coordinated with other transmission operators and balancing authorities and the reliability coordinator.

544. In the NOPR, the Commission proposed to approve Reliability Standard EOP-001-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to EOP-001-0 that: (1) Includes the reliability coordinator as an applicable entity with responsibilities as described above; (2) clarifies the 30-minute requirement in Requirement R2 of the Reliability Standard to state that load shedding should be capable of being implemented as soon as possible and much less than 30 minutes and (3) includes definitions of system states to be used by the operators, such as transmission-related “normal,” “alert,” and “emergency” states, provides criteria for entering into these states and identifies the authority that will declare these states.

545. Most of the comments address the specific modifications and concerns raised by the Commission in the NOPR. Below, we address each topic separately, followed by an over-all conclusion and summary.

i. Applicability to reliability coordinators

(a) Comments

546. MRO states that it is necessary to include reliability coordinators as applicable entities because reliability coordinators have a wide-area view. FirstEnergy also supports making the proposed Reliability Standard applicable to the reliability coordinator. FirstEnergy states the reliability coordinator should take an active role and should have clearly defined, specific responsibilities for coordinating and implementing emergency operations plans. In addition, FirstEnergy states that inclusion of the reliability coordinator as an applicable entity removes ambiguity that may exist concerning the reliability coordinator's role and its responsibilities during restoration activities.

547. SoCal Edison agrees that certain aspects of EOP-001-0 should be applicable to reliability coordinators; however, it proposes that NERC, through the stakeholder process, should receive input from stakeholders on which requirements should be exclusive to the transmission operator or balancing authority with the reliability coordinator responsible only for collecting and incorporating this information into its overarching plan. MISO, on the other hand, questions the need for the proposed modification, contending that the reliability coordinators have parallel responsibilities laid out in other EOP Reliability Standards.

(b) Commission Determination

548. In the NOPR, we stated that the proposed Reliability Standard applies to transmission operators and balancing authorities, that the applicability portion of the Reliability Standard is sufficiently clear as to who must comply with the filed version of the Reliability Standard and that the Reliability Standard can be enforced against these entities. [232] However, we recognized commenters' concerns that the Reliability Standard does not assign a role to the reliability coordinator, which is the highest level of authority responsible for reliable operation of the Bulk-Power System and which has a wide-area view. MISO contends that EOP-001-0 need not apply to reliability coordinators because they have parallel responsibilities in other EOP Reliability Standards. We disagree. Given the importance NERC attributes to the reliability coordinator in connection with matters covered by EOP-001-0, the Commission is persuaded that specific responsibilities for the reliability coordinator in the development and coordination of emergency plans must be included as part of this Reliability Standard. While balancing authorities and transmission operators are capable of developing, maintaining and implementing plans to mitigate operating emergencies for their specific areas of responsibility, unlike reliability coordinators, they do not have wide-area views.

549. Further we agree with SoCal Edison that clear direction is needed on which requirements should be exclusive to transmission operators and balancing authorities with the reliability coordinator being responsible for incorporating this information into its overarching plan. Accordingly, the Commission finds the reliability coordinator is a necessary entity under EOP-001-0 and directs the ERO to modify the Reliability Standard to include the reliability coordinator as an applicable entity. In addition, the ERO should consider SoCal Edison's suggestion in the ERO's Reliability Standards development process.

ii. Clarification of the 30-minute Load Shedding Requirement

(a) Comments

550. NERC comments that the proposed directive to clarify the 30-minute requirement in Requirement R2 presumes that all manual load shedding can be performed by supervisory control. It states that, in many systems, shedding load requires actions by field personnel who must be dispatched to a site. NERC recognizes the reliability benefit of being able to shed greater amounts of load in seconds or minutes but contends that the amount of load shedding under remote supervisory control and the timing requirements should be vetted through industry experts based on good utility practice. While acknowledging that the proposed modification is appropriate because it corresponds to current good utility practice and widely held interpretations of the requirement to shed load, FirstEnergy, like NERC, notes that loads that does not have SCADA cannot be shed within 30 minutes because field staff must be dispatched. It proposes that the Reliability Standard should specify that, for loads that do not have SCADA, the implementation plan must be initiated, but not necessarily completed, within 30 minutes. Similarly, MidAmerican is concerned that if load shedding is to be performed in much less than 30 minutes it will require automatic load shedding which may trigger when not required leading to less reliability under certain conditions. MidAmerican proposes a modification to specifically permit load shedding with non-automatic schemes.

551. Xcel states that the proposed modification is unnecessary because there are many different options besides load shedding that could be implemented to alleviate IROL violations within 30 minutes. It adds that load shedding is the option of last resort and that the timing for implementation of load shedding would be better addressed in proposed Reliability Standard EOP-003-1. EEI and California PUC state that not all load reduction schemes should be required to be operable within 30 minutes; only those used for emergency operations. APPA states that the 30-minute interval was selected based on industry consensus and, rather than dismiss this consensus, the Commission should instruct NERC to reconsider the 30-minute requirement and either modify it or better explain why it is the appropriate time period for the requirement. MISO questions what would be achieved by the proposed modification and states that operators do not intentionally delay taking action when required.

552. International Transmission and PGE state that shedding load “as soon as possible and much less than 30 minutes” is vague and unenforceable. International Transmission proposes shedding of load “as soon as possible when required to mitigate an IROL violation, but in no case in more than 30 minutes.”

(b) Commission Determination

553. The proposed Reliability Standard states that the transmission operator shall have an emergency load reduction plan for all identified IROLs and that the load reduction plan must be capable of being implemented within 30 minutes. In the NOPR, we proposed to direct NERC to modify EOP-001-0 to clarify the 30-minute requirement in Requirement R2 to state that load shedding should be capable of being implemented as soon as possible and in much less than 30 minutes. [233] The intent was to have a requirement that precludes waiting until the 29th minute to begin implementation.

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

555. Further, as Xcel recognizes, load shedding is the option of last resort and there may be other options available to alleviate IROL violations within 30 minutes. The ERO should consider these other options as it works through the Reliability Standards development process to modify EOP-001-0.

556. With regard to the wording of the proposed modification stating that load shedding should be capable of being implemented “as soon as possible and in much less than 30 minutes,” the Commission agrees with PGE and International Transmission that this language may be unclear and unduly subjective. In the NOPR, we stated that the reference to 30 minutes could suggest that anything up to that limit was acceptable and proposed the modification to emphasize our concern that implementation was expected much sooner than in 30 minutes. International Transmission's suggested rewording addresses our concern. Accordingly, we direct the ERO to develop a modification through the Reliability Standards development process clarifying that when the load reduction plan of Requirement R2 involves load shedding, such load shedding be capable of being implemented as soon as possible when required to mitigate an IROL violation but in no case in more than 30 minutes.

557. Finally, in response to APPA's comments, as stated in the NOPR, [235] the Commission accepts the 30-minute requirement as a reasonable period within which operators should return the system to a reliable operating state. However, in order to satisfy this Requirement, when load shedding is the only viable option, the Commission believes that operators must have the capability through SCADA or other equivalent means to shed appropriate amounts of load in the desired locations as soon as possible to mitigate IROL violations but in no case in more than 30 minutes. [236]

iii. Definitions of System States

(a) Comments

558. FirstEnergy states that it may be difficult to define system states that cover all operating conditions, but nonetheless recognizes that the standardization of these states is a first step to bringing clarity to operators concerning system conditions and the resulting actions they are expected to take. California PUC, on the other hand, states that imposing uniform definitions for “normal,” “alert” and “emergency” states is impractical and counterproductive. California PUC claims that trying to define in advance all contingencies that the system may face is probably infeasible and argues that improved real-time monitoring of the grid is the preferred approach for quick identification and correction of problems.

559. ISO-NE states that it is important to define system states but that such definitions should not be implemented until a “pilot program” is field tested. ISO-NE explains that after such a pilot program is conducted operators would need to make changes to their policies and procedures, including operator training, to make sure that their practices are administered in a secure and well-understood fashion.

(b) Commission Determination

560. In the NOPR, the Commission stated that clearly defined system states incorporated into real-time operation can significantly improve operator recognition of emergency conditions, rapid and accurate response and recovery to normal system conditions. [237]

561. The Commission recognizes that the triggering events and the nature of the emergency states may be different for different systems; however, we find that a clearly defined set of system states will help operators proactively avert escalations of system disturbances and cascading outages. Further, operators, the ERO and regulators will better understand how reliably the system is operating and how it performed historically if statistics can be collected based on well-defined system states. We find it reasonable for the ERO, through the stakeholder process, to develop a well-defined set of uniform, continent-wide system states that can be understood by transmission operators, balancing authorities, reliability coordinators and the ERO to correspond to specific, predetermined levels of urgency.

562. As we noted in the NOPR, some control areas define and effectively use more than the “normal,” “alert” and “emergency” system states included in the Blackout Report recommendation. [238] We proposed that the ERO determine the optimum number of system states to be employed continent-wide and to consider the addition of the restoration state. [239] Accordingly, we direct the ERO to determine the optimum number of continent-wide system states and their attributes and to modify the Reliability Standard through the Reliability Standards development process to accomplish this objective.

563. Further, we agree with ISO-NE that the proposed modification should be field-tested and that policies and procedure be put in place, including operator training, before any processes for continent-wide system states are implemented. Such testing will help assure that all applicable entities and their personnel understand how the terms will be used and will allow operators to train staff to make any necessary changes to their policies and procedures. We direct the ERO to consider such a pilot program as it modifies EOP-001-0 through the Reliability Standards development process.

iv. Other issues

(a) Comments

564. ISO-NE raises two additional concerns with the proposed Reliability Standard. First, it states that activities outlined in Requirement R7.4, including coordinating fuel conservation and arranging for fuel deliveries, are not functions that independent transmission operators and balancing authorities typically perform. Second, ISO-NE notes that Requirement R5 provides that each transmission operator and balancing authority must include applicable elements of Attachment 1 of EOP-001-0 in an emergency plan. However, according to ISO-NE, the elements identified in Attachment 1 are characterized as “for consideration” and are not mandatory. ISO-NE argues that the proposed Reliability Standard should be clarified to indicate that the actual emergency plan elements, and not the “for consideration” elements of Attachment 1, should be the basis for compliance.

(b) Commission Determination

565. With regard to ISO-NE's concern that certain activities outlined in Requirement R7.4 are not functions normally performed by independent transmission operators and balancing authorities, the Commission understands that this Requirement covers either delivery of fuel or delivery of electrical energy from remote systems. While arranging for fuel deliveries may be outside of the functions that ISOs and RTOs perform, the requirement to arrange deliveries of electrical energy from remote systems is a function they normally perform. Because an ISO or RTO may choose to either deliver fuel or electrical energy from remote systems, Requirement R7.4 will not burden ISOs and RTOs with functions they do not normally perform.

566. The Commission agrees with ISO-NE that the Reliability Standard should be clarified to indicate that the actual emergency plan elements, and not the “for consideration” elements of Attachment 1, should be the basis for compliance. However, all of the elements should be considered when the emergency plan is put together.

v. Summary of Commission Determination

567. Accordingly, the Commission concludes that Reliability Standard EOP-001-0 is just, reasonable, not unduly discriminatory or preferential and in the public interest and approves it as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-001-0 through the Reliability Standards development process that: (1) Includes the reliability coordinator as an applicable entity with responsibilities as described above; (2) clarifies the 30-minute requirement in Requirement R2 of the Reliability Standard to state that load shedding should be capable of being implemented as soon as possible but in no more than 30 minutes; (3) includes definitions of system states to be used by the operators, such as transmission-related “normal,” “alert” and “emergency” states, provides criteria for entering into these states, and identifies the authority that will declare these states and (4) clarifies that the actual emergency plan elements, and not the “for consideration” elements of Attachment 1, should be the basis for compliance. Further, the Commission directs the ERO to consider a pilot program for system states, as discussed above.

b. Capacity and Energy Emergencies (EOP-002-2)

568. EOP-002-2 applies to balancing authorities and reliability coordinators and is intended to ensure that they are prepared for capacity and energy emergencies. [240] The Reliability Standard requires that balancing authorities have the authority to bring all necessary generation on line, communicate about the energy and capacity emergency with the reliability coordinator and coordinate with other balancing authorities. EOP-002-2 includes an attachment that describes an emergency procedure to be initiated by a reliability coordinator that declares one of four energy emergency alert levels to provide assistance to the LSE.

569. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to the Reliability Standard that: (1) Addresses emergencies resulting not only from insufficient generation but also from insufficient transmission capability, including situations where insufficient transmission impacts the implementation of the capacity and energy emergency plan; (2) identifies DSM in Requirement R6 as one possible remedy that a balancing authority may use to bring it in compliance with control performance and disturbance control Reliability Standards and (3) includes a clear warning that the TLR procedure is an inappropriate and ineffective tool to mitigate IROL violations or for use in emergency situations.

570. Most of the comments address the specific modifications and concerns raised by the Commission in the NOPR. Below, we address each topic separately, followed by an over-all conclusion and summary.

i. Insufficient Transmission Capability

(a) Comments

571. MRO believes that the definition for the term “insufficient transmission capability” should be clarified because insufficient transmission capability could be due to a thin spot in the interconnection, prior outages or storm damage.

(b) Commission Determination

572. As we stated in the NOPR, neither EOP-002-2 nor any other Reliability Standard addresses the impact of inadequate transmission during generation emergencies. [241] The Commission agrees with MRO that “insufficient transmission capability” could be due to various causes. The ERO should examine whether to clarify this term in the Reliability Standards development process.

ii. Demand-Side Management

(a) Comments

573. FirstEnergy states that it is appropriate to include demand-side resources as another tool for balancing authorities to use in meeting control performance and disturbance control Reliability Standards. It states, however, that in order to qualify, the demand-side resource options must meet similar technical requirements as generation resource options. Comverge recommends that the terms “demand response” and “curtailable loads” be specifically added to R3, R4 and R6.3 and Alert Level 1 to ensure that they are included in the list of resources that will be controlled during capacity and energy emergencies. APPA contends that Requirement R6.6 adequately accounts for the use of demand-side remedies to address emergencies. As such, APPA opposes the Commission's proposal as being unduly prescriptive. Also ISO-NE contends that the proposed modifications effectively dictate a specific means to solve the underlying problems instead of leaving it to the responsible entities to determine how to achieve the reliability objective. A proper recommendation would be to make the requirement resource-neutral.

(b) Commission Determination

574. The Commission agrees with FirstEnergy that for demand-side resources to qualify as another tool for balancing authorities to use in meeting control performance and disturbance control Reliabilty Standards, they must meet comparable technical performance requirements as generation resource options. In response to comments from Comverge and APPA, the Commission believes that curtailable loads are adequately addressed in Requirement R6 of the Reliability Standard but that demand response is not covered. [242] Demand response covers considerably more resources than interruptible load. Accordingly, the Commission directs the ERO to modify the Reliability Standard to include all technically feasible resource options in the management of emergencies. These options should include generation resources, demand response resources and other technologies that meet comparable technical performance requirements.

iii. Warning regarding TLR procedure

(a) Comments

575. MRO states that it is very important that all concerned parties realize that TLR is not a first line of defense to mitigate IROL violations. Entergy and MidAmerican agree that TLR procedures are not effective to mitigate IROL violations or for use in emergency situations. EEI supports the Commission's proposed modifications to the Reliability Standard; however, EEI along with Entergy, MidAmerican and APPA, believes that the TLR process is effective in avoiding and mitigating potential IROL violations. These commenters request that the Commission clarify the proposed modification so that it does not foreclose such use of the TLR process.

576. International Transmission states that TLR can be an effective and appropriate means to mitigate IROL violations or for use in emergency situations and therefore EOP-002-2 should not preclude the use of TLR when its use is warranted. MISO states that, while TLR is not the preferred method of responding to emergencies, an operator should not be precluded from implementing TLR during emergencies. It argues that TLR may be appropriate when events develop slowly or when an entity is affected by external transactions and has exhausted all control actions or needs to reserve some control actions for contingencies.

577. APPA contends that the specific direction provided in this proposed modification intrudes on NERC's role as a standard setting agency and would be better framed as a direction to NERC to investigate the concern and revise the Reliability Standard accordingly. Similarly, while ISO-NE supports the Commission's conclusion that reliance on TLR procedures can be inappropriate, it recommends that the proposed Reliability Standard would be improved if it did not specify the operating method required to achieve compliance. ISO-NE also believes that the Commission should direct NERC to allow the responsible entities flexibility in the means by which they achieve compliance with the Reliability Standard. [243]

(b) Commission Determination

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

579. As to APPA's comment that we are intruding on NERC's role as a standard-setting agency, we have authority to direct the ERO to submit a modification and, in this instance, requiring the ERO to “investigate the concern” first is unnecessary. The issue is narrowly-framed and the comments identify no points requiring the approach suggested by APPA. In response to ISO-NE, we are precluding use of TLR procedures at times of actual IROL violations, but are not otherwise specifying permissible responses.

iv. Other issues

580. ISO-NE states that Requirement R2 essentially requires the same actions covered by ISO-NE Operating Procedure No. 4. ISO-NE is concerned that a strict approach to auditing compliance with the Reliability Standard could result in a finding that ISO-NE was in violation of the Reliability Standard if it skipped a particular action under its emergency plan even though that action was not called for under ISO-NE procedures. ISO-NE requests that the Commission direct NERC to clarify that a system operator has discretion not to implement every action specified in its capacity and energy emergency plans when other appropriate actions are possible.

581. FirstEnergy claims that Requirement R1 may impose overlapping obligations and authority on reliability coordinators and balancing authorities who may have the same, partial or whole footprint and who are both likely to respond to the same emergency.

582. APPA notes that revised Reliability Standard EOP-002-2, filed by NERC on November 15, 2006, includes new Measures for some of the requirements but not all the requirements. APPA states that NERC should be directed to include Measures related to Requirements R4, R5, R6, R7 and R9.1.

(a) Commission Determination

583. The Commission finds that the issues raised by ISO-NE should be addressed through the Reliability Standards development process. As to FirstEnergy's concern with Requirement R1, the reliability coordinator has the highest level of authority. Accordingly, the Commission directs that the ERO, through the Reliability Standards development process, address ISO-NE's concern. Further, we direct the ERO to consider adding Measures and Levels of Non-Compliance in the Reliability Standard.

v. Summary of Commission Determination

584. Accordingly, the Commission approves Reliability Standard EOP-002-2 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-002-2 through the Reliability Standards development process that: (1) Addresses emergencies resulting not only from insufficient generation but also from insufficient transmission capability particularly where this affects the implementation of the capacity and energy emergency plan; (2) includes all technically feasible resource options, including demand response and generation resources, in the management of emergencies and (3) ensures that the TLR procedure is not used to mitigate actual IROL violations.

c. Load Shedding Plans (EOP-003-1)

585. EOP-003-1 deals with load shedding plans and requires that balancing authorities and transmission operators operating with insufficient transmission and generation capacity have the capability and authority to shed load rather than risk a failure of the Interconnection. [245] It includes requirements to establish plans for automatic load shedding for underfrequency or undervoltage, manual load shedding to respond to real-time emergencies and communication with other balancing authorities and transmission operators.

586. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to EOP-003-0 that: (1) Specifies the minimum load shedding capability that should be provided and the maximum amount of delay before load shedding can be implemented; (2) requires periodic drills of simulated load shedding and (3) contains Measures and Levels of Non-Compliance.

587. Most of the comments address the specific modifications and concerns raised by the Commission in the NOPR. Below, we address each topic separately, followed by an over-all conclusion and summary.

i. Minimum load shedding and maximum delay

(a) Comments

588. FirstEnergy and APPA agree that NERC should modify EOP-003-1 to specify the minimum load shedding capability and the maximum amount of delay. However, FirstEnergy adds that Requirement R8, which states that load shedding actions must be taken in a “time frame adequate for responding to the emergency,” is ambiguous and difficult to substantiate. NERC acknowledges that significant improvements can be made to the EOP Reliability Standards to establish criteria for the provision of load shedding capability, but it states that requiring a specific minimum amount of load (MW) or percentage of load that must be capable of being shed and the maximum amount of time delay is as likely to reduce reliability as it is to increase it. NERC contends that the electric characteristics of local systems and loads must be considered in designing manual and automatic load shedding capabilities. Accordingly, it proposes that the Commission direct NERC to review industry best practices and propose requirements in the Reliability Standards to ensure that adequate load shedding capabilities are provided to protect the Bulk-Power System without causing adverse impacts associated with unnecessary shedding of firm load.

589. SoCal Edison states that in certain circumstances, but not in all cases, it would be valuable to have a minimum limit established for the amount of load shedding an entity is to accomplish. It suggests that the specific requirements should be derived based on studied conditions.

590. Xcel, ISO-NE, TVA and International Transmission do not support a nationwide Reliability Standard for minimum load shedding and maximum delay for implementing load shedding because there are large variations in load, resources and system configuration and characteristics across the continent. TVA states that these parameters should be determined based on studies of the specific transmission systems and applicable contingency events. MISO states that it is not clear what is intended or achieved by this requirement because balancing authorities and transmission operators should already have the ability to shed, by some means, all load within their area and the timing requirements are specified in the IROL-related Reliability Standards.

591. California PUC is concerned that the proposed modification assumes that load shedding at the transmission level is the only or the primary way to address system emergencies. SDGE recommends that the maximum delay for shedding load should begin when the transmission operator or balancing authority has actual knowledge of the circumstances that would precipitate load shedding.

(b) Commission Determination

592. Shedding of firm load is an operating measure of last resort to contain system emergencies and prevent cascading. System operators must have the capability to shed load in a timely manner to return the system to a stable condition. The Commission disagrees with NERC's contention that requiring a specific minimum amount of load that must be capable of being shed and the maximum amount of delay is as likely to reduce reliability as it is to increase it. As stated in the NOPR, the actual amount of load to be shed, the location and the time frame will be at the discretion of the system operator based on the nature of the system problem and the operator's assessment of corrective actions required. [246] However, if the capability to shed sufficient load in locations where it is required and in a timely manner is not available to the system operator, then the risk of uncontrolled failure of system elements or cascading outages is increased.

593. While the Reliability Standard requires transmission operators and balancing authorities to be capable of load shedding in a time frame adequate for responding to emergencies, this could be clearer, as noted by FirstEnergy. As mentioned by NERC, significant improvements can be made to the Reliability Standard to establish criteria for the provision of load shedding capability. We agree.

594. Several commenters state that they do not support a nationwide Reliability Standard for minimum load shedding capability and maximum delay in implementing load shedding because these parameters are dependent on system configurations and load and resource characteristics across the continent, and as such, must be determined based on system studies. [247] The Commission agrees that the minimum load shedding capability must take into account system characteristics and topology, however the maximum time delay before load shedding can be implemented is independent of system characteristics and is governed by what is considered to be feasible.

595. California PUC is concerned that the proposed modification on load shedding assumes that load shedding at the transmission level is the only or preferred way to address system emergencies. The Commission clarifies that this assumption is incorrect and agrees with California PUC that load shedding at the distribution level has the minimum societal and economic impact.

596. The Commission concludes that the Reliability Standard needs to be modified to ensure that adequate load shedding capabilities are provided so that system operators have an effective operating measure of last resort to contain system emergencies and prevent cascading. The Commission recognizes that the amount of load shedding capability required is dependent on system characteristics and therefore it may not be feasible to have a uniform nationwide load shedding capability. This, however, does not preclude a uniform nationwide criterion on the methodology for establishing load shedding capability that would specify the minimum amount of load shedding capability that should be provided based on system characteristics and conditions and the maximum amount of delay before load shedding can be implemented. The Commission directs the ERO to address the minimum load and maximum time concerns of the Commission through the Reliability Standards development process. We suggest that a review of industry best practices would be useful in developing nationwide critera.

ii. Periodic drills of simulated load shedding

(a) Comments

597. California PUC states that, since load shedding at the distribution level has the minimum societal and economic impact, the Reliability Standard should require all neighboring distribution or transmission utilities to participate in annual drills when requested by an ISO or other bulk power authority. Northern Indiana and FirstEnergy support mandating periodic drills of simulated load shedding; however, FirstEnergy states that the drill requirements should include simulated load shed via a simulator or table-top exercise, not an actual deployment of manpower, and that these drill requirements should be included in the PER-005-0 Reliability Standard instead of EOP-003-1. PER-005-0 only involves training of control room personnel, whereas these drills should also include testing the readiness and functionality of procedures and personnel outside of the control room.

(b) Commission Determination

598. As suggested by California PUC, periodic drills of simulated load shedding should involve all participants required to ensure successful implementation of load shedding plans. As such, the drills should extend beyond system operators to distribution operators and LSEs. The Reliability Standard should require periodic drills by entities subject to section 215, and require those entities to seek participation by other entities. The drills should test the readiness and functionality of the load shedding plans, including, at times, the actual deployment of personnel. Therefore the Commission disagrees with FirstEnergy that the requirement for periodic drills of simulated load shedding should be incorporated into the new PER-005-0 Reliability Standard that is currently being drafted to address operator training.

iii. Other issues

(a) Comments

599. Santa Clara states that since automatic load shedding for undervoltage conditions is not required in most parts of the West and possibly in other areas of the country, Requirement R2 should be modified to include the words “as applicable per the Regional Reliability Organization.” In addition, APPA states that NERC should consider requiring balancing authorities and transmission operators to expand coordination and planning of their automatic and manual load shedding plans to include their respective Regional Entities, reliability coordinators and generation owners. ISO-NE proposes that NERC establish coordinated trip settings within and among balancing authorities for each interconnection.

600. While EEI generally supports the proposed modifications, it believes that the proposal for senior management to post letters to safeguard operators who shed load in accordance with approved guidelines does not respond to or meet the needs reflected in the Blackout Recommendation No. 8. EEI points out that, under other provisions of the FPA, the Commission has approved liability limiting provisions for some operators that appears to be consistent with the Blackout Report Recommendation No. 8, but has rejected other similar protections. EEI requests that the Commission explicitly state that transmission operators taking action in compliance with the load shedding provisions of Commission approved Reliability Standards will be protected from retaliatory actions, including legal actions.

(b) Commission Determination

601. Regarding Santa Clara's concern that undervoltage load shedding is not required in most parts of WECC and that Requirement R2 should be modified to reflect this, the Commission notes that Requirement R2 states that each transmission operator and balancing authority shall establish plans for automatic load shedding for underfrequency or undervolatge conditions. The Commission clarifies that the Reliability Standard does not mandate undervoltage load shedding unless needed for Reliable Operation.

602. We also note that APPA and ISO-NE raise issues regarding coordination of trip settings and automatic and manual load shedding plans. The Commission directs the ERO to consider these comments in future modification to the Reliability Standard through the Reliability Standards development process.

603. EEI seeks adoption of a provision to shield transmission operators from liability when they take action in compliance with the load shedding provisions of the Reliability Standards. Consistent with our discussion of Blackout Report Recommendation No. 8 in the Common Issues section of this Final Rule, the Commission will not adopt new liability protections. [248] According to the Task Force, no further action is needed to implement that recommendation because some states already have appropriate protection against liability suits. [249] Further, in Order No. 890, we have already declined to provide a uniform federal liability standard.

iv. Summary of Commission Determination

604. The Commission approves proposed Reliability Standard EOP-003-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-003-1 through the Reliability Standards development process that: (1) Includes a requirement to develop specific minimum load shedding capability that should be provided and the maximum amount of delay before load shedding can be implemented based on an overarching criteria that take into account system characteristics and (2) requires periodic drills of simulated load shedding.

d. Disturbance Reporting (EOP-004-1)

605. EOP-004-1 establishes requirements for reporting system disturbances to the regional reliability organization and the ERO. [250] It also establishes requirements for the analysis of these disturbances.

606. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to the Reliability Standard that: (1) Includes any requirements necessary for users, owners and operators of the Bulk-Power System to provide data that will assist NERC in the investigation of a blackout or disturbance and (2) includes Measures and Levels of Non-Compliance.

i. Comments

607. EEI and FirstEnergy support the Commission's proposed modifications to the Reliability Standard. EEI states that data reporting requirements and other process requirements should be contained in enforceable Reliability Standards. FirstEnergy states that the proposed modification corresponds to good utility practice and that explicitly stating the requirement to provide data to NERC brings clarity to the expectations of NERC and the Commission.

608. APPA is concerned about the scope of Requirement R2 because, in its opinion, Requirement R2 appears to impose an open-ended obligation on entities such as generation operators and LSEs that may have neither the data nor the tools to promptly analyze disturbances that could have originated elsewhere. APPA proposes that Requirement R2 be modified to require affected entities to promptly begin analyses to ensure timely reporting to NERC and DOE.

609. Xcel expresses concern regarding what constitutes a reportable event for each applicable entity and recommends that the Reliability Standard be revised to define what a reportable event is for each entity that has reporting obligations. Further, Xcel states that the requirement in Requirement R3.4 for a final report within 60 days may not be feasible given the current WECC process, which among other things, requires the creation of a group to prepare the report and a 30-day posting of a draft report before it becomes final. Xcel also states that if the ultimate purpose of the report is to provide information to avoid a recurrence of a system disturbance, then the Reliability Standard should be revised to require the distribution of the report to similarly situated entities.

610. FirstEnergy states that, since nuclear units have their own NRC reporting procedures covering the Requirements under EOP-004-1, the Reliability Standard should specify that compliance with such operating procedures is sufficient to satisfy the requirements of EOP-004-1. FirstEnergy also states that the title of this Reliability Standard should be changed to “Disturbance Event Reporting” to indicate that the events covered under this Reliability Standard include a broad range of events that go beyond the events for which reports may be required under Reliability Standard BAL-002-0.

611. APPA states that NERC's November 15, 2006 revision partially fulfills the proposed modification to include Measures and Levels of Non-Compliance. APPA notes that EOP-004-1 did not provide Measures for R2, R3.2, R3.4, R4 and R5.

ii. Commission Determination

612. Complete and timely data is essential for analyzing system disturbances. In the NOPR, the Commission proposed modifying this disturbance Reporting Standard to include requirements necessary for users, owners and operators of the Bulk-Power System to provide disturbance data, voice recordings and other information collected during the disturbance to assist NERC in the investigation of the blackout or disturbance. [251] While some commenters agree with this proposal, APPA and Xcel express concerns regarding the scope and applicability of some of the Requirements of the Reliability Standard.

613. Requirement R2 of the Reliability Standard requires reliability coordinators, balancing authorities, transmission operators, generator operators and LSEs to promptly analyze disturbances on their system or facilities. APPA is concerned that generator operators and LSEs may be unable to promptly analyze disturbances, particularly those disturbances that may have originated outside of their systems, as they may have neither the data nor the tools required for such analysis. The Commission understands APPA's concern and believes that, at a minimum, generator operators and LSEs should analyze the performance of their equipment and provide the data and information on their equipment to assist others with their analyses. The Commission directs the ERO to consider this concern in future revisions to the Reliability Standard through the Reliability Standards development process.

614. The Commission disagrees with Xcel that the Reliability Standard is unclear about what constitutes a reportable event. Attachment 1 of the Reliability Standard details the various events that would trigger the reporting requirement under this Reliability Standard.

615. FirstEnergy states that since nuclear units have their own NRC reporting requirements the Reliability Standard should specify that compliance with NRC procedures is sufficient to satisfy the obligations of this Reliability Standard. The Commission disagrees with FirstEnergy because there are situations where the ERO Reliability Standards are more stringent than the NRC procedures. In such cases, the ERO Reliability Standards must apply in addition to the NRC requirements. Also, the Commission disagrees with FirstEnergy's comment on changing this Reliability Standard's name to avoid confusion with BAL-002-0. The purpose of the Reliability Standard is clear as to the extent of the disturbances to be reported.

616. The Commission declines to address Xcel's concerns about the current WECC process. These issues should be addressed in the Reliability Standards development process or submitted as a regional difference. The Commission directs the ERO to consider all comments in future modifications of the Reliability Standard through the Reliability Standards development process.

617. In response to APPA's concern that NERC did not provide a Measure for each Requirement, we reiterate that it is in the ERO's discretion whether each Requirement requires a corresponding Measure. The ERO should consider this issue through the Reliability Standards development process.

618. While the Commission has identified concerns with regard to EOP-004-1, we believe that the proposal serves an important purpose in establishing requirements for reporting and analysis of system disturbances. Accordingly, the Commission approves Reliability Standard EOP-004-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-004-1 through the Reliability Standards development process that includes any Requirements necessary for users, owners and operators of the Bulk-Power System to provide data that will assist NERC in the investigation of a blackout or disturbance.

619. Requirement R3 addresses the reporting of disturbances to the regional reliability organizations and NERC. The Commission directs the ERO to change its Rules of Procedure to assure that the Commission also receives these reports within the same time frames as DOE.

e. System Restoration Plans (EOP-005-1)

620. EOP-005-1 deals with system restoration plans and requires that plans, procedures, and resources be available to restore the electric system to a normal condition in the event of a partial or total system shut down. The Reliability Standard requires transmission operators, balancing authorities, and reliability coordinators to have effective restoration plans, to test those plans, and to be able to restore the interconnection using them following a blackout. It also requires operating personnel to be trained in these plans.

621. In the NOPR, the Commission proposed to approve Reliability Standard EOP-005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to EOP-005-1 that: (1) Includes Measures and (2) identifies time frames for training and review of restoration plan requirements to simulate contingencies and prepare operators for anticipated and unforeseen events.

i. Comments

622. APPA and EEI state that Reliability Standard EOP-005-1 is sufficient for approval as a mandatory Reliability Standard and requests that the Commission direct NERC to address missing Measures and training requirements. In addition, APPA notes that the Reliability Standard is applicable to both balancing authorities and transmission operators but the Measures and Levels of Non-Compliance elements refer only to transmission operators.

623. ISO-NE does not support adoption of the proposed Reliability Standard because, while Requirement R1 requires transmission operators to include applicable elements from Attachment 1 of EOP-005-1 in their restoration plans, Requirement R1 appears to indicate that the elements in Attachment 1 are to be included in the emergency plan only “as applicable.” ISO-NE states that the Reliability Standard should be clarified to indicate that the actual emergency plan elements should be the basis for compliance.

624. EEI and FirstEnergy note that the proposed modification to identify time frames for training and review of restoration plan requirements is being addressed in the proposed Reliability Standard PER-005-1 and that including this requirement in EOP-005-1 would be redundant. MISO also believes that the proposed modification is unnecessary. It states that there are already requirements for simulation-based training on emergencies and restoration and it is unclear what is meant by conducting training to prepare operators for unforeseen events.

625. FirstEnergy states that Requirement R1 calls for a plan for a partial shutdown of the system and that there is an infinite set of events that can cause a partial shutdown. According to FirstEnergy, because the borders of a partial shutdown are difficult, if not impossible, to foresee, the Reliability Standard should specify some boundaries for analysis of partial shutdowns including an appropriate definition of the term “partial shutdown.” In addition, FirstEnergy states that one uniform plan for all systems is not feasible; rather the Reliability Standard should recognize that some companies already have existing plans that could be used for analyzing events. FirstEnergy also states that the Reliability Standard should provide a uniform checklist of factors to analyze, developed on a company-specific basis.

626. NRC suggests that this Reliability Standard include: (1) A requirement to record the time it takes to restore power to the auxiliary power systems of nuclear power plants; (2) a provision stating that the affected transmission operators shall give high priority to restoration of off-site power to nuclear power plants whether or not a nuclear power plant is being powered from the nuclear power plant's onsite power supply and (3) a provision stating that restoration shall not violate nuclear power plant minimum voltage and frequency requirements.

627. While not commenting on the substance of Reliability Standard EOP-005-1, MRO states that EOP-005-1, EOP-006-1 and EOP-007-0 are ordered in a confusing manner and should be renumbered. MRO reasons that since the regional coordinator has oversight responsibility for system restoration, EOP-006-1 should be first in the system restoration sequence of Reliability Standards (i.e., EOP-006-1 should precede EOP-005-1). Further, MRO recommends that EOP-005-1 follow EOP-006-1 because transmission owners and balancing authorities are responsible for submitting restoration plans to the regional coordinator. MRO requests that if a reason exists for the current order, NERC should provide that reason to the Commission.

ii. Commission Determination

628. With regard to comments that the Commission's concerns are being addressed in NERC's drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1 only includes Requirements on the control room personnel and not those outside of the control room. System restoration requires the participation of not only control room personnel but also those outside of the control room. These include blackstart unit operators and field switching operators in situations where SCADA capability is unavailable. As such, the Commission believes that inclusion of periodic system restoration drills and training and review of restoration plans in a system restoration Reliability Standard is the most effective way of achieving the desired goal of ensuring that all participants are trained in system restoration and that the restoration plans are up to date to deal with system changes.

629. Several commenters raise issues that should be addressed by the ERO through the Reliability Standards development process. [252] For example: whether the Measures and Levels of Non-Compliance should refer to balancing authorities; clarification of the elements that form the basis for compliance with the requirements of Attachment 1; what constitutes a partial shutdown for which restoration plans must be developed and recognition that some companies already have existing plans that could be used for analyzing events; and that the Reliability Standard should provide a uniform checklist of factors to analyze, developed on a company-specific basis. We find that consideration of these issues could be helpful in meeting the objectives of the Reliability Standard. Accordingly, the ERO should consider these concerns in future revisions of the Reliability Standard through the Reliability Standards development process.

630. NRC raises several issues concerning the role and priority that nuclear power plants should have in system restorations. The Commission shares these concerns and directs the ERO to consider the issues raised by NRC in future revisions of the Reliability Standard through the Reliability Standards development process. In addition the Commission directs the ERO to gather data, pursuant to § 39.5(f) of the Commission's regulations, from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to the Commission on a quarterly basis.

631. We find that the Reliability Standard adequately addresses operating personnel training and system restoration plans to ensure that transmission operators, balancing authorities and reliability coordinators are prepared to restore the Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP-005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1 through the Reliability Standards development process that identifies time frames for training and review of restoration plan requirements to simulate contingencies and prepare operators for anticipated and unforeseen events and gathers the data from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to the Commission on a quarterly basis.

f. Reliability Coordination-System Restoration (EOP-006-1)

632. Proposed Reliability Standard EOP-006-1 addresses reliability coordination and system restoration. [253] It establishes specific requirements for reliability coordinators during system restoration, and it states that reliability coordinators must have a coordinating role in system restoration to ensure that reliability is maintained during restoration and that priority is placed on restoring the Interconnection.

633. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to the Reliability Standard that: (1) requires that the reliability coordinator be involved in the development of and approves restoration plans and (2) includes Measures and Levels of Non-Compliance.

i. Comments

634. APPA states that Reliability Standard EOP-006-1, which NERC filed on November 15, 2006, includes the required Measures and Levels of Non-Compliance and as such APPA agrees that EOP-006-1 should be approved as mandatory and enforceable. In addition, APPA does not oppose industry consideration of a requirement that reliability coordinators be involved in the development and approval of restoration plans.

635. EEI states that Requirements R4 and R11 of EOP-005-1 already address reliability coordinator involvement in the development and approval of transmission operator system restoration plans. Further, while EEI agrees that the reliability coordinator's role is appropriate, it believes that the asset owner, as the entity that ultimately bears responsibility for restoration capabilities, should also have authority to develop and maintain the plans. MISO believes that it is unnecessary to modify the Reliability Standard to involve the reliability coordinator because there is already a requirement in EOP-005-1 for balancing authorities and transmission operators to coordinate their plans with the reliability coordinator.

636. Xcel disagrees that the reliability coordinator should be involved with the development of restoration plans because the reliability coordinator typically does not have the knowledge of the details necessary to develop the plans in contrast to the balancing authorities and the transmission operators. Instead it proposes that the reliability coordinator develop its own plans and coordinate that with the balancing authority and transmission operator's plans.

ii. Commission Determination

637. The reliability coordinator is the highest level of authority that is responsible for the reliable operation of the Bulk-Power System. Given the importance of this role in connection with matters covered by EOP-006-1, the Commission believes that the reliability coordinator must be involved in the development and approval of the restoration plans. The current Reliability Standard only requires that the reliability coordinator be aware of the restoration plan of each transmission operator in its area. The Commission disagrees with EEI and MISO, who contend that the reliability coordinator's role in the transmission operator's restoration plan is covered in EOP-005-1. EOP-005-1 only requires coordination with the reliability coordinator, and during actual system restoration, EOP-005-1 requires approval from the reliability coordinator to resynchronize isolated areas with other isolated areas.

638. In response to comments by Xcel, the Commission believes that while the reliability coordinator may not have the level of detailed knowledge that the balancing authorities and transmission operators may have for setting-up the stable islands required under restoration plans, the reliability coordinator is in the best position to determine how those stable islands should be resynchronized with each other and the rest of the interconnected system.

639. The Commission finds that the Reliability Standard adequately addresses the goals of effective and efficient reliability coordination and system restoration. Accordingly, the Commission approves Reliability Standard EOP-006-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-006-1 through the Reliability Standards development process that ensures that the reliability coordinator, which is the highest level of authority responsible for reliability of the Bulk-Power System, is involved in the development and approval of system restoration plans.

g. Establish, Maintain, and Document a Regional Blackstart Capability Plan (EOP-007-0)

640. EOP-007-0, which deals with establishing, maintaining and documenting regional blackstart capability plans, ensures that the quantity and location of system blackstart generators are sufficient and that they can perform their expected functions as specified in the overall coordinated regional system restoration plans.

641. The NOPR did not propose to approve or remand EOP-007-0, because it applies only to regional reliability organizations.

i. Comments

642. APPA agrees that EOP-007-0 should not be approved as a mandatory Reliability Standard and states that in the interim the regional reliability organizations and Regional Entities should continue to perform this function. In addition, APPA proposes that, in the interim, an umbrella organization composed of representatives from each regional reliability organization and Regional Entity should be formed to establish operation planning rules, including blackstart requirements, across the Eastern Interconnection. APPA suggests that such an effort would go a long way in identifying critical facilities, using consistent and transparent study assumptions and minimizing seams during system emergencies throughout the Interconnection.

643. TANC states that the number of blackstart units and their locations depend heavily on regional characteristics and cannot be prescribed in a uniform, continent-wide manner. It proposes that regional flexibility be afforded to provide an appropriate mix of facilities to achieve the reliability objectives. EEI suggests that EOP-007-0 be rewritten so that compliance obligations are assigned directly to those entities that provide the data and other information.

644. FirstEnergy and MRO state that the reliability coordinator, not the Regional Entity, should be responsible for the regional blackstart plan for its area of responsibility. Further, FirstEnergy states that the blackstart plan developed for a region should be consistent with NRC requirements, should recognize that nuclear units have no blackstart capability and should recognize that nuclear units must have priority access to off-site power for safety reasons. FirstEnergy requests that the Commission direct NERC to revise the definition of a blackstart unit to mean a “diesel, hydro, pump storage, or the combustion turbine generating unit that is used to provide cranking power to a larger steam generating unit designed to restore load” or to mean a “larger steam generating unit designed to restore load.” [254] MRO states that arrangements for coordination of blackstart capability should be addressed in a contract between appropriate entities.

ii. Commission Determination

645. The Commission will not approve or remand EOP-007-0, because it applies only to regional reliability organizations. However, the Commission provides guidance for the ERO's future consideration.

646. The Commission disagrees with APPA that an umbrella organization is needed for the Eastern Interconnection while the Reliability Standard is pending final approval. The Commission is persuaded that FirstEnergy's and MRO's comments concerning the reliability coordinator being responsible for regional blackstart plans have merit. The Commission has directed that the reliability coordinator approve the system restoration plans and this is a logical extension of that direction. However, until such time as the Reliability Standard has been revised and approved by the ERO and the Commission, the regional reliability organization (or Regional Entity, depending on the organization of a particular region) should continue to perform this role as it has in the past. [255]

647. With regard to TANC's request for regional flexibility in determining the appropriate mix of facilities needed to achieve the reliability objectives, it is our understanding that the Reliability Standard provides for the number and location of blackstart units to vary depending on the specific requirements of each system. We believe that uniformity will be required, however, in the criteria used to determine the number and location of blackstart units and testing requirements.

648. EEI, FirstEnergy and MRO offer suggestions for improving the Reliability Standard. The Commission directs the ERO to consider these suggestions in future revisions to improve EOP-007-0, through the Reliability Standards development process.

649. Accordingly, the Commission will not approve or remand EOP-007-0 at this time.

h. Plans for Loss of Control Center Functionality (EOP-008-0)

650. EOP-008-0 addresses plans for loss of control center functionality. It requires each reliability coordinator, transmission operator and balancing authority to have a plan to continue reliable operations and to maintain situational awareness in the event its control center is no longer operable.

651. The Commission proposed five modifications to the Reliability Standard and requested additional comments on other issues. We have grouped the comments into two general categories: (1) Capabilities of backup control centers and (2) which entities should have full backup centers. Below, we address each topic separately, followed by an overall conclusion and summary.

i. Capabilities of Backup Control Centers

652. In the NOPR, the Commission proposed to approve Reliability Standard EOP-008-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to EOP-008-0 that includes a Requirement that provides for backup capabilities that, at a minimum, must: (1) Be independent of the primary control center; (2) be capable of operating for a prolonged period of time and (3) provide for a minimum set of tools and facilities to replicate the critical reliability functions of the primary control center. [256] In addition to these three capabilities requirements, the Commission solicited comments concerning other specific capabilities.

(a) Comments

653. EEI, Entergy, FirstEnergy and Northern Indiana support the proposed modifications to EOP-008-0. Entergy agrees with the Commission's proposed modifications to include more Requirements regarding backup capabilities.

654. APPA, Nevada Companies and TAPS caution that costs must be considered and compared to possible benefits. APPA states that it would take some time to implement the proposed modifications and therefore specific requirements for backup control facilities and capabilities should be left to the Reliability Standard development process. Nevada Companies cautions that utilities that have invested millions of dollars in back-up capabilities may find these facilities to be non-compliant with the proposed Reliability Standard. It suggests that cost/benefits analyses be conducted and that a grandfathering provision be adopted to protect investments in backup systems that were made in a good faith effort to comply with rules in place in the past, but which may not comply with the Reliability Standard.

655. MRO requests clarification of the term “capability” because it is unsure if the term is intended to refer to a facility, what such a facility should consist of and what operators should be capable of doing from that facility.

656. In response to the request for comments on backup capabilities, NERC states that these are best addressed through the Reliability Standards development process.

657. SoCal Edison suggests that a risk-based assessment be considered to determine the requirements for backup. MISO, TAPS and International Transmission note that work is underway by NERC to address the provisions for redundancy and backup control capabilities via the Operating Committee Backup Control Task Force and that the focus is on functionality rather than physical requirements. TAPS states that, rather than directing NERC to adopt specific modifications to the Reliability Standard that would inappropriately burden small systems with the cost of dual facilities, the Commission should identify objectives to the Task Force. TAPS also states that a small balancing authority might be able to meet the functional requirements for a backup control center with a contract with another entity while larger entities might need a physical backup center.

658. Northern Indiana states that the Commission's proposal appears to eliminate an entity's opportunity to contract for backup capabilities from others who already have full backup control centers. FirstEnergy and Northern Indiana advocate for flexibility in the means used to meet the backup requirements and request that the Commission clarify that a “full backup center” can include providing full redundancy by contract rather than physical backup center facilities. SoCal Edison states that when entities utilize the services of another entity for backup, they should be required to test the backup capability a minimum number of times during the year and that all system operators should be required to participate in such testing over a specified time period.

659. NRC suggests that this Reliability Standard require: (1) A list of the nuclear power plants and their voltage, thermal, and/or frequency limits and (2) provisions to notify nuclear power plants of the loss of control center functionality.

(b) Commission Determination

660. As we stated in the NOPR, the goal of the Reliability Standard is the continuation of reliable operations and the maintenance of situational awareness in the event that the primary control center is no longer operational. [257] Some commenters support the proposal to require backup capabilities while others including APPA, Nevada Companies and TAPS caution that the cost of the proposal may not be justified. In addition, some commenters, including FirstEnergy and Northern Indiana, advocate for flexibility in meeting the backup requirements and suggest that entities should be able to contract for full redundancy. MRO seeks clarification regarding the use of the term “capability.”

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

662. On the issue of additional backup capabilities, NERC, MISO, TAPS and International Transmission propose that the functional requirements for backup capabilities be determined by the NERC Backup Control Task Force. NRC offers requirements it believes should be added to the Reliability Standard.

663. The Commission disagrees with the Nevada Companies' proposal for grandfathering. The Reliability Standards must define the minimum functions that are necessary for the Reliable Operation of the Bulk-Power System. The flexibility described above on how capabilities are provided should mitigate any costs incurred to upgrade older centers.

664. Given the importance to reliability of maintaining situational awareness in the event of loss of the primary control center operations, the Commission believes that, at a minimum, the three requirements—independence from the primary control center, capability to operate for a prolonged period corresponding to the time it would take to replace the primary control center, and the provision of a minimum set of tools and facilities to replicate the critical reliability functions of the primary control center—must be included as explicit requirements in the Reliability Standard. Other additional Requirements may be developed by the Backup Control Task Force for inclusion in the Reliability Standard. The Commission directs the ERO to develop modifications to the requirements in future revisions to the Reliability Standard through the Reliability Standards development process.

ii. Which entities should have full backup centers

665. In the NOPR , the Commission proposed to direct that NERC submit a modification to EOP-008-0 that: (1) Provides that the extent of the backup capability be consistent with the impact of the loss of the entity's primary control center on the reliability of the Bulk-Power System and (2) includes a Requirement that all reliability coordinators have full backup control centers. The Commission also requested comments on what other entities, such as balancing authorities and large transmission operators, should have full backup centers.

(a) Comments

666. International Transmission, MISO and FirstEnergy state that in addition to reliability coordinators, large balancing authorities and transmission operators need full backup control centers. MISO states that there are certain situations where large generation fleets that are controlled centrally would also warrant full backup systems and that small entities can operate reliably with less robust systems. Further, it argues that the ERO needs latitude to decide from a reliability standpoint how much redundancy is needed. FirstEnergy states that in place of full backup control facilities it should be acceptable to have standing contracts in place to provide backup services in the event of a loss of a control center.

667. NERC states that the proposed directive presumes that the only way to achieve highly reliable and independent backup capability to perform reliability coordinator functions in an emergency is to have a redundant control center. NERC contends that while this may be an option, it may not be the only one for achieving the necessary reliability objective. NERC proposes that the Reliability Standard be modified to define the performance results expected rather than how an entity should meet the requirements.

668. NERC, SoCal Edison and Otter Tail state that the question of what other entities should have full backup centers is best addressed through the Reliability Standards development process. Otter Tail requests that the Commission not require all balancing authorities to have full backup centers since the loss of a small balancing authority's control center would not have a substantial impact on the reliability of the Bulk-Power System. Northern Indiana states that requiring transmission operators and balancing authorities to have full backup centers would result in significant unnecessary facility duplication, at great cost to consumers, and without a material increase in reliability.

669. FirstEnergy comments that the Reliability Standard should not require a fully redundant SCADA system for the backup control center for balancing authorities or transmission operators because the cost would be prohibitive. It states that balancing authorities, transmission operators and centrally-located generation owners should be permitted to have a single distributed computer system in place to diminish the probability of a complete system shutdown due to a natural disaster or a single man-made physical act of sabotage.

670. Nevada Companies also questions whether the significant cost of full replication could ever be cost-effective, especially considering the very high level of control center reliability achieved now with the existing solution of a single control center plus backup of critical systems.

(b) Commission Determination

671. Several commenters agree with the Commission that reliability coordinators at a minimum should have full backup control centers. They also propose that this requirement be extended to large balancing authorities, transmission operators and centrally dispatched generation facilities. Others caution on the cost implications of requiring full duplication given the very high level of control center reliability achieved with the existing technology and backup of critical systems. Having carefully considered all the issues raised by commenters and taking into account the reliability impacts of loss of primary control centers and the role of reliability coordinators as the highest level of authority responsible for reliability of the Bulk-Power System, the Commission is persuaded that all reliability coordinators must have fully redundant independent backup control centers. In response to NERC, any proposed modification that is independent from the primary center, provides for continuous monitoring and has the full functionality of the primary center would satisfy our concerns. Other entities, including balancing authorities, transmission operators and centrally dispatched generation control centers, must provide for the minimum backup capabilities discussed above but may do so through other means, such as contracting for these services instead of through dedicated backup control centers.

672. In addition, in response to FirstEnergy's concern regarding balancing authorities and transmission operators having fully redundant SCADA systems and distributed computer systems, the Commission requires the primary and backup capabilities to replicate critical reliability functionalities and be independent from the primary control center, including telemetered data and control from remote terminal units. This can be achieved through a variety of design alternatives, e.g., developing a SCADA management platform that will allow telemetered data and control to be shared among SCADA systems so that data and control is not lost during a SCADA or communications failure. The Commission's focus is on function, not design.

iii. Summary of Commission Determination

673. Accordingly, the Commission approves Reliability Standard EOP-0081-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-008-0 through the Reliability Standards development process that includes a Requirement that provides for backup capabilities that, at a minimum, must: (1) Be independent of the primary control center; (2) be capable of operating for a prolonged period of time, generally defined by the time it takes to restore the primary control center; (3) provide for a minimum functionality to replicate the critical reliability functions of the primary control center; (4) provides that the extent of the backup capability be consistent with the impact of the loss of the entity's primary control center on the reliability of the Bulk-Power System; (5) includes a Requirement that all reliability coordinators have full backup control centers and (6) requires transmission operators and balancing authorities that have operational control over significant portions of generation and load to have minimum backup capabilities discussed above but may do so through contracting for these services instead of through dedicated backup control centers.

i. Documentation of Blackstart Generating Unit Tests Results (EOP-009-0)

674. Proposed Reliability Standard EOP-009-0 deals with documentation of blackstart generating unit test results. In the NOPR, the Commission proposed to approve EOP-009-0 as mandatory and enforceable without modifications.

i. Comments

675. APPA agrees that EOP-009-0 is sufficient for approval as a mandatory and enforceable Reliability Standard. Xcel states that the Reliability Standard should provide details on what constitutes a blackstart test and FirstEnergy states that EOP-009-0 should be consolidated with EOP-007-0 because the Requirements of EOP-009-0 already exist in EOP-007-0.

ii. Commission Determination

676. The Commission believes that this Reliability Standard sufficiently addresses documentation of blackstart generating unit test results. Accordingly, the Commission approves Reliability Standard EOP-009-0 as mandatory and enforceable.

677. Two commenters made suggestions for improving the Reliability Standard. The Commission directs the ERO to take these suggestions into consideration when revising the Reliability Standard through the Reliability Standards development process.

5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities

678. The nine Facility (FAC) Reliability Standards address topics such as facility connection requirements, facility ratings, system operating limits and transfer capabilities. The FAC Reliability Standards also establish requirements for maintaining equipment and rights-of-way, including vegetation management. The NOPR provided direction for seven of the nine FAC Reliability Standards; NERC withdrew two others, Reliability Standards FAC-004-0 and FAC-005-0. NERC, in its November 15, 2006 filing requests approval of three additional FAC Reliability Standards: FAC-010-0, FAC-011-0 and FAC-014-0. These Reliability Standards are being addressed in a separate docket.

a. Facility Connection Requirements (FAC-001-0)

679. Proposed Reliability Standard FAC-001-0 is intended to ensure that transmission owners establish facility connection and performance requirements to avoid adverse impacts to the Bulk-Power System. In the NOPR, the Commission proposed to approve FAC-001-0 as mandatory and enforceable.

i. Comments

680. APPA agrees with the Commission's proposal to approve FAC-001-0 as mandatory and enforceable.

ii. Commission Determination

681. As discussed in the NOPR, the Commission believes that Reliability Standard FAC-001-0 is just, reasonable, not unduly discriminatory or preferential and in the public interest and approves it as mandatory and enforceable.

b. Coordination of Plans for New Generation, Transmission, and End-User Facilities (FAC-002-0)

682. Proposed Reliability Standard FAC-002-0 requires that each generation owner, transmission owner, distribution provider, LSE, transmission planner and planning authority assess the impact of integrating generation, transmission and end-user facilities into the interconnected transmission system.

683. In the NOPR, the Commission proposed to approve Reliability Standard FAC-002-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a modification to FAC-002-0 that amends Requirement R1.4 to require evaluation of system performance under both normal and contingency conditions by referencing TPL-001 through TPL-003.

i. Applicability and Assessment Responsibility

(a) Comments

684. APPA, Xcel and FirstEnergy state that this Reliability Standard is not clear about who will perform the required assessment and how many assessments are required under this Reliability Standard. APPA requests that the Reliability Standard be clarified to state that the required assessment must be performed only by the transmission planner and the planning authority. Xcel requests that the Commission clarify that only one required assessment needs to be done when new facilities are added, and that all the listed entities should participate in that single assessment.

685. FirstEnergy requests that NERC clarify what is considered a new facility and asks if, for example, up-rates should be included as new facilities. MRO is concerned that the impact of the Commission's directive is too broad and may have a substantial affect on those individual entities that are responsible for performing the studies; MRO asks the Commission to clarify FAC-002-0 to the extent necessary, but does not propose a specific change.

686. Six Cities requests that this Reliability Standard clarify that all applicable entities must make available data necessary for all other responsible entities to perform the required assessment. Six Cities also suggests that the transmission operator be added as an entity to which this Reliability Standard is applicable, at least from the perspective that it make necessary data available to all other entities responsible for assessment. TAPS believes that this Reliability Standard seems to assume that the LSE and distribution provider actively participate in planning of new facilities in the Bulk-Power System. TAPS states that very few LSEs or distribution providers have the expertise to perform the tasks outlined in this Reliability Standard and that these two entities provide only certain data regarding certain new facilities to some or all of the other entities identified in this Reliability Standard. TAPS therefore believes that it would be unreasonable to require LSEs to provide the transmission planning evaluations and assessments called for by R1. California Cogeneration believes that the Reliability Standard implies that generator owners will perform an independent assessment and if so, it believes that such task is impossible, since generators do not have the relevant information about the power system to perform such evaluations. California Cogeneration believes that the Reliability Standard should be clarified so that generator owners cooperate with and provide input to the assessment performed by the transmission operator and the balancing authority.

687. FirstEnergy states that both MISO and PJM already have Large Generator Interconnection Procedures (LGIP) in place that provide a formal process that meets the requirements listed under R1, and asks that the Commission state that complying with the interconnection agreement and/or OATT satisfies this requirement. MISO states that their procedures for coordinating plans for new generation, transmission and end-user facilities includes modeling of normal system and contingency conditions.

(b) Commission Determination

688. All of the above commenters request clarification of Requirement R1 in the Reliability Standard that states that various functional entities “shall each coordinate and cooperate on its assessments with its transmission planner and planning authority.” [259] The Commission believes that all entities listed in the Applicability section have a stake in the performance of the system and should have the opportunity to provide input in the assessment under R1. The Commission believes that commenters have raised valid concerns that, if addressed, would make the Reliability Standard better. The wording would allow a number of organizational approaches to achieving the goal of performing an analysis. The Commission does not intend to limit which organizational approach is used by the entities, only to assure that a single competent and collaborative analysis is performed. Therefore, the Commission directs the ERO to address these concerns in the Reliability Standards development process.

689. FirstEnergy asks the Commission to state that complying with MISO's and PJM's interconnection agreements and/or OATT satisfies requirement R1 under this Reliability Standard. We will not make that determination here. If FirstEnergy believes that complying with the MISO and PJM interconnection procedures meets the applicable Reliability Standards, then it should follow those procedures, it should not be concerned about violating the Reliability Standard.

ii. Standards of Conduct

(a) Comments

690. Xcel and MidAmerican believe that the assessment required under this Reliability Standard may conflict with the Commission's Standards of Conduct [260] since the assessment requires coordination among several different functional groups within a vertically integrated public utility. MidAmerican asserts that, since direct communication between the generation and transmission entities would result in more efficient overall planning, the Commission should clarify its intended application of Standards of Conduct restrictions on joint planning activities. Xcel asks the Commission to clarify that actions taken to comply with this Reliability Standard will not result in a transmission provider being in violation of the Standards of Conduct.

(b) Commission Determination

691. The Commission disagrees with MidAmerican and Xcel that this Reliability Standard may conflict with the Standards of Conduct. This type of system assessment is being performed today with the cooperation of the entities listed in the Applicability section. Further, we note that the Standards of Conduct were designed to address such interactions. The entities participating in the assessment effort can continue to contribute to this assessment and observe the Standards of Conduct at the same time. If any entity finds an area where it believes the Standards of Conduct prevent it from cooperating with the assessment process, it may seek clarification from the Commission as to whether that area of involvement is in conflict with the Standards of Conduct.

iii. Reference to TPL Reliability Standards

(a) Comments

692. While APPA and EEI agree with the Commission's proposal to direct NERC to submit a modification to FAC-002-0 that amends Requirement R1.4 to require evaluation of system performance under both normal and contingency conditions by referencing TPL-001-0 through TPL-003-0, Entergy disagrees and proposes that evaluation of system performance under Reliability Standards TPL-001-0 and TPL-002-0 should be sufficient. Entergy states that given the large number of small end-user requests that transmission operators may receive, expanding the scope of Requirement R1.4 may lead to additional work and documentation that ultimately will not benefit reliability. First Entergy states that the proposed reference to TPL Reliability Standards should be expanded to include TPL-001-0 through TPL-004-0.

(b) Commission Determination

693. The Commission notes that APPA and EEI agree with the Commission's proposed directive to NERC to modify FAC-002-0 to require evaluation of system performance under both normal and contingency conditions by referencing TPL-001-0 through TPL-003-0. The Commission also notes that NERC, in response to the Staff Preliminary Assessment, has also agreed with the same proposal. [261] These three TPL Reliability Standards cover normal operation, first contingency operation and multiple contingency operations respectively. The Commission disagrees with Entergy that TPL-001-0 and TPL-002-0 are sufficient because it is important to plan for new facilities taking into account not only normal circumstances but also contingencies. In addition, we note that including TPL-001-0 through TPL-003-0 will result in the FAC-002 Reliability Standard being consistent with Order No. 2003, which requires interconnecting entities to take into account multiple contingencies in interconnection studies. With respect to FirstEnergy's suggestion to also include a reference to Reliability Standard TPL-004-0, we direct the ERO to consider it through the Reliability Standards development process.

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

c. Transmission Vegetation Management Program (FAC-003-1)

695. According to NERC, FAC-003-1 is designed to minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances between transmission lines and vegetation, and establishing a system for uniform reporting of vegetation-related transmission outages. FAC-003-1 would apply to transmission lines operated at 200 kV or higher voltage (and lower-voltage transmission lines which have been deemed critical to reliability by a regional reliability organization). It would require each transmission owner to have a documented vegetation management program in place, including records of its implementation. Each program must be designed for the geographical area and specific design configurations of the transmission owner's system.

696. This Reliability Standard requires a transmission owner to define a schedule for and the type (aerial or ground) of right-of-way vegetation inspections. In addition, it requires a transmission owner to determine and document the minimum allowable clearance between energized conductors and vegetation before the next trimming, and it specifically provides that “Transmission-Owner-specific minimum clearance distances shall be no less than those set forth in the IEEE Standard 516-2003 (IEEE Guide for Maintenance Methods on Energized Power Lines).” [262]

697. In the NOPR, the Commission proposed to approve Reliability Standard FAC-003-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification to FAC-003-1 that: (1) Requires the ERO develop a minimum vegetation inspection cycle that allows variation for physical differences and (2) removes the general limitation on applicability to transmission lines operated at 200 kV and above so that the Reliability Standard applies to Bulk-Power System transmission lines that have an impact on reliability as determined by the ERO.

i. Applicability

(a) Comments

698. Entergy agrees with the Commission's proposal and supports applying the Reliability Standard to only those lines that have an impact on reliability as determined by the ERO, as supported by reliability studies using consistent reliability contingency criteria.

699. LPPC supports using an impact-based definition of the Bulk-Power System to determine applicability and suggests that the definition of significant adverse impact should be determined through the NERC process. Further, LPPC asserts that actual facilities meeting that criteria should be determined by Regional Entities, which best understand the impacts of facilities on the regional system. LPPC notes that Regional Entities can continue to use such tools as modeling and power flow analyses to determine which facilities are critical to the reliability of the Bulk-Power System.

700. APPA and Avista believe that Regional Entities should determine what transmission facilities this standard applies to, since Regional Entities have detailed knowledge regarding the transmission facilities within their regions. APPA would have the Regional Entities create a regional Reliability Standard to do so, subject to ERO review for reasonableness and consistency. Avista points out that WECC and the other Regional Entities have already reviewed and designated critical lower voltage transmission facilities, and the Reliability Standards currently apply to such facilities.

701. MISO asks for clarification with respect to the intent of adding transmission lines below 200 kV “that impact reliability” and whether the included lines are IROL-related facilities [263] or some other facilities. Progress and SERC suggest that it may be appropriate to limit the applicability of the Reliability Standard to all lines that are operated at 200 kV and above and to operationally significant circuits between 100 kV and 200 kV that are elements of IROLs.

702. California PUC believes that discretion about determining which lines are critical to the Bulk-Power System should be left to the individual state (working in concert with RTOs and ISOs), which has much greater knowledge of what is needed on the local level, rather than to NERC or the Regional Reliability Organization.

703. Progress, SERC, FirstEnergy and Avista argue that automatically subjecting lines below 200 kV to Reliability Standard FAC-003-1 would increase maintenance, documentation and reporting costs and impacts to land owners, but would not necessarily increase the reliability of the grid. LPPC does not object to eliminating the 200 kV bright line threshold, but believes that extending vegetation management practices to all facilities of 100 kV and above would unnecessarily extend the scope of the vegetation management requirements, creating large cost increases for many utilities without creating a material increase in the reliability of the Bulk-Power System. FirstEnergy recommends that if the voltage level is lowered, implementation, especially for reporting requirements, should be spread over at least one year. Similarly, Xcel asks the Commission to allow flexibility in complying with this Reliability Standard for lower-voltage facilities that previously were not subject to this Reliability Standard.

704. EEI maintains that not changing this Reliability Standard would best maintain reliability, since removing the existing 200 kV threshold requirement could inadvertently expose the Bulk-Power System to a new set of risks. SoCal Edison argues that the Reliability Standard already covers transmission lines rated less than 200 kV, because Requirement 4.3 of FAC-003-1 states that this Reliability Standard “shall apply to all transmission lines operated at 200 kV and above and to any lower voltage lines designated by the regional reliability organization as critical to the reliability of the electric system in the region.”

705. APPA opposes the Commission's proposal to direct NERC to change the applicability of this Reliability Standard. APPA argues that the Commission should deal with this concern by having NERC reevaluate the Reliability Standard. National Grid argues that expanding the applicability of Reliability Standards would not be appropriate because it could dramatically change the meaning of the Reliability Standards and would undermine the Reliability Standard development process which yielded the careful balances struck in developing the standards.

706. NERC argues that the Commission's proposed modification should be vetted through the Reliability Standards development process to better understand what will be gained in terms of impacts to the reliability of the Bulk-Power System. NERC notes that the current applicability of the Reliability Standard to 200 kV and above transmission lines was debated extensively by the industry, and any change to this requirement should be vetted again.

(b) Commission Determination

707. We will not direct NERC to submit a modification to the general limitation on applicability as proposed in the NOPR. However, we will require the ERO to address the proposed modification through its Reliability Standards development process. As explained in the NOPR, the Commission is concerned that the bright-line applicability threshold of 200 kV will exclude a significant number of transmission lines that could impact Bulk-Power System reliability. Although the regional reliability organizations are given discretion to designate lower voltage lines under the proposed Reliability Standard, none have designated any operationally significant lines even though there are lower voltage lines involving IROL as suggested by Progress and SERC. We continue to be concerned that this approach will not prospectively result in the inclusion of all transmission lines that could impact Bulk-Power System reliability. In proposing to require the ERO to modify the Reliability Standard to apply to Bulk-Power System transmission lines that have an impact on reliability as determined by the ERO, we did not intend to make this Reliability Standard applicable to fewer facilities than it currently is with the 200 kV bright line applicability, but to extend the applicability to lower-voltage facilities that have an impact on reliability. We support the suggestions by Progress Energy, SERC and MISO to limit applicability to lower voltage lines associated with IROL and these suggestions should be part of the input to the Reliability Standards development process. Similarly, the ERO should evaluate the suggestions proposed by LPPC, APPA and Avista.

708. California PUC suggests that states should have discretion over what lines are critical to Bulk-Power System reliability. The Commission has been given the responsibility to approve Reliability Standards that assure the Reliable Operation of the Bulk-Power System, including which facilities are covered by the Reliability Standards. We cannot delegate that responsibility as proposed by California PUC. Further, since many transmission facilities traverse multiple states, we are concerned that this proposal could result in the Reliability Standard applying to a section of a line in one state but not applying to the same line in a neighboring state. Since a vegetation-related outage affects all customers connected to that transmission line, customers in both states could potentially have lower reliability as a result of one state having a less stringent standard than another.

709. Avista, LPPC, Progress and SERC raise concerns about the cost of implementing this Reliability Standard if the applicability is expanded to lower-voltage facilities. We recognize these concerns, and this was one of the reasons we proposed to apply this Reliability Standard to Bulk-Power System transmission lines that have an impact on reliability as determined by the ERO. We recognize that many commenters would like a more precise definition for the applicability of this Reliability Standard, and we direct the ERO to develop an acceptable definition that covers facilities that impact reliability but balances extending the applicability of this standard against unreasonably increasing the burden on transmission owners.

710. FirstEnergy and Xcel suggest that if the applicability of this Reliability Standard is expanded, the Commission should allow flexibility in complying with this Reliability Standard for lower-voltage facilities, or allow lower-voltage facilities one year before the Reliability Standard is implemented. The ERO should consider these comments when determining when it would request that the modification of this Reliability Standard to go into effect.

711. In response to EEI's concerns that removing the existing 200 kV threshold could expose the Bulk-Power System to a new set of risks, we clarify that we are not immediately modifying this Reliability Standard. Instead, it will go into effect as written and the ERO will revise it through the Reliability Standards development process, with the expectation that the applicability of this Reliability Standard will expand to include additional facilities that impact reliability that currently are not covered by this Reliability Standard. A modification that reduces the applicability of this Reliability Standard would not meet the Commission's directives. In response to SoCal Edison's argument that the Reliability Standard already addresses the Commission's concerns, the Commission agrees that while there appears to be a mechanism for inclusion of additional lines, none have been included. This lack of inclusion is in spite of the evidence that some lower voltage lines can have significant impacts on the Bulk-Power System, including IROLs and SOLs.

712. In response to APPA, NRECA and NERC we agree that the proposed modifications should be vetted through the Reliability Standards development process. The Commission's goal is to promote the Reliable Operation of the Bulk-Power System by including all of those entities necessary to comply with this Reliability Standard. We believe that requiring the Reliability Standard to include a greater number of entities and exclude those that will not affect reliability will more effectively sustain reliability than an overly exclusive list of applicable entities.

ii. Inspection Cycles

713. In the NOPR, the Commission proposed to direct NERC to submit a modification to FAC-003-1 that requires the ERO to develop a minimum vegetation inspection cycle that allows variation for physical differences.

(a) Comments

714. FirstEnergy states that a designation of a minimum annual inspection cycle is appropriate and the method of inspection (aerial or by ground) should be left to the transmission owner. Dominion cautions that if there is a requirement for annual inspections, it should be flexible and allow for different approaches to transmission line inspections.

715. APPA, Entergy, EEI, LPPC, Progress Energy, SERC and SoCal Edison disagree with the Commission's proposal to require the ERO to set minimum vegetation inspection cycles that allow for physical differences. APPA, Entergy and LPPC say that, instead of proposing the development of a Reliability Standard for minimum vegetation inspection cycles, the Commission should permit the transmission system owner or local utility to determine the inspection cycle best suited for its system and adhere to that cycle, with compliance enforcement performed by the Regional Entities and the ERO.

716. Progress Energy and SERC believe that the Reliability Standard as written provides flexibility regarding vegetation inspection cycles and that the Commission should not impose requirements on the ERO to develop minimum inspection intervals on a continent with such regional diversity in climate and vegetation. In addition, Progress Energy argues that, where a particular region is heavily forested and has heavy rainfall along with extended or year round growing seasons, a “back stop” minimum inspection frequency could lead transmission owners to conduct inspections less frequently than what the local conditions require, which would lead to a lowest common denominator Reliability Standard. This could result in a transmission owner complying with the Reliability Standard while not adequately protecting the reliability of that region's transmission system.

717. Progress Energy and SERC argue that, since the performance metrics in FAC-003-1 require reporting of applicable transmission interruptions caused by vegetation, the compliance process associated with this Reliability Standard should appropriately identify transmission owners' inspection cycles that are not adequate, and the ERO can use its authority to remedy any vegetation-related outage that is attributed to the transmission owner's inspection frequency.

718. SoCal Edison states that transmission owners are already obligated by Requirement R1.1 to establish a minimum vegetation inspection schedule that allows adjustment for changing conditions. SoCal Edison believes that the best measure of an effective transmission vegetation management program is whether or not tree-to-line contacts are occurring. SoCal Edison recommends the Commission rescind the two proposed directives and order no further revisions to FAC-003-1 until such time as Reliability Standard is deemed unenforceable by the ERO or is not otherwise achieving its stated goals.

719. APPA and Progress Energy state that a minimum vegetation inspection cycle could result in an undue financial burden for some regions of the country, because they would be forced into a minimum cycle that might be inappropriate for their own region. For example, Progress Energy states that, where a particular region is arid, sparsely forested or has a minimum growing season, a “back stop” minimum could require a more frequent interval than is realistically needed. This would result in increased and unnecessary costs to the transmission owner and its customers without providing a comparable increase in reliability. EEI believes that a minimum inspection cycle will add nothing to the strength of the existing practices and could add a requirement that is not merited by actual circumstances in many locations.

(b) Commission Determination

720. The Commission is concerned about minimizing outages and supports a realistic inspection cycle. In the NOPR, the Commission proposed a minimum inspection cycle that takes account of physical differences as one way to address this concern. However, we recognize that there may be other options to achieve the same reliability goal. For example, the ERO could determine whether a prepared company-tailored inspection cycle is appropriate given the physical and geographic factors and, through audits, inspect individual vegetation management programs for compliance.

721. While the Commission disagrees that incorporating a backstop would lead to a lowest common denominator Reliability Standard, the Commission is dissuaded from requiring the ERO to create a backstop inspection cycle at this time. Instead, the Commission agrees that an entity's vegetation management program should be tailored to anticipated growth in the region and take into account other environmental factors. The goal is to assure that transmission owners conduct inspections at reasonable intervals. In the Commission's Vegetation Management Report, we found that many entities performed aerial or ground inspections less than every three years or even “as needed.” [264]

722. The Commission continues to be concerned with leaving complete discretion to the transmission owners in determining inspection cycles, which limits the effectiveness of the Reliability Standard. Accordingly, the Commission directs the ERO to develop compliance audit procedures, using relevant industry experts, which would identify appropriate inspection cycles based on local factors. These inspection cycles are to be used in compliance auditing of FAC-003-1 by the ERO or Regional Entity to ensure such inspection cycles and vegetation management requirements are properly met by the responsible entities.

iii. Minimum Clearances on National Forest Service Lands

723. In the NOPR, the Commission did not propose to modify the ERO's general approach with respect to clearances. However, the Commission expressed its belief that any potential issues regarding minimum clearances on National Forest Service (Forest Service) lands should be dealt with on a case-by-case basis. The Commission requested comments on whether another approach would be more appropriate to address this issue.

(a) Comments

724. APPA believes that a case-by-case approach may have to be employed, since Forest Service lands are located all across the country and have different regional characteristics. APPA notes that U.S. Fish and Wildlife Service personnel have begun to take action regarding vegetation management on non-federal lands, and reports that APPA members have been told by U.S. Fish and Wildlife personnel to refrain from cutting vegetation at certain times of the year in the absence of an imminent reliability threat. APPA concludes that this information conflicts with specifying minimum nationwide vegetation inspection/cutting cycles and clearances. In addition, APPA requests clarification of the Commission interpretation “we interpret the FAC-003-1 to require trimming that is sufficient to prevent outages due to vegetation management practices under all applicable conditions.”

725. Several commenters express concern about the Commission's position that any potential issues regarding minimum clearances on National Forest Service lands should be dealt with on a case-by-case basis. [265] EEI, Progress Energy and SERC believe that this approach is inconsistent with the Reliability Standard's intent to use consistent approaches in setting minimum vegetation clearance distances on both private and public lands and the Commission's statement that this Reliability Standard requires minimum clearances that are “sufficient to prevent outages due to vegetation management practices under all applicable conditions.” [266] Therefore, International Transmission, EEI, LPPC, Progress Energy and SERC assert that Reliability Standard FAC-003-1 should be applicable to all responsible entities including those with transmission on both private and public lands because consistency is the only way to provide a uniform and reliable electrical system. Dominion suggests the Commission defer to NERC and the stakeholder process to develop specifications for clearances.

726. Progress Energy and SERC note that EEI and certain federal agencies [267] have jointly addressed the issue of consistency in vegetation management work on federal lands, and developed a memorandum of understanding (Vegetation MOU) which sets the framework for managing vegetation on transmission line rights-of-way under Federal agency jurisdiction. [268] Progress Energy and SERC recommend using the EEI's Vegetation MOU framework for managing vegetation on transmission line rights-of-way under federal agency jurisdiction rather than the case-by-case approach proposed in the NOPR. LPPC recommends creating a bright-line when it comes to utilities' obligations (and rights) for trimming vegetation located on Forest Service lands. Avista and Portland General ask that the Vegetation MOU be affirmed by the Commission and permitted to govern transmission line rights-of-ways located on lands managed by federal land management agencies.

727. SoCal Edison believes that transmission owners should be allowed the latitude to establish measures/procedures for less rigid tree-to-line clearances in response to state and federal agency demands or requests but is concerned that these measures/procedures will prove to be of little or no value in the event of an ERO investigation into a tree-to-line contact occurring within national/state forestry boundaries or on private property.

728. California PUC points out that California already has requirements applicable to minimum vegetation clearance, and that the Commission must take care to assure that any mandatory Reliability Standard does not preempt the ability of California (and other states with similar state standards) to impose stricter requirements that have no adverse impacts on reliability.

729. FirstEnergy states that the standard should define rights-of-way to encompass the required clearance area instead of the corresponding legal land rights. Some rights-of-way may be larger to accommodate future needs and therefore may exceed clearances needed for existing lines. FirstEnergy believes that Reliability Standards should not require clearing entire rights-of-way when the required clearance for existing lines does not take up the entire right-of-way.

(b) Commission Determination

730. As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1 requires sufficient clearances to prevent outages due to vegetation management practices under all applicable conditions. As to APPA's requests for clarification concerning the term “under all applicable conditions,” the Reliability Standard already addresses this issue in Requirement R3.2 by allowing for exceptions for natural disasters (including wind shears and major storms) that cause vegetation to fall into the transmission lines from outside the ROW. The Commission therefore finds that no clarification is required in response to APPA.

731. The Commission agrees that ownership of the land does not change the impact of a vegetation-related outage on the Bulk-Power System. However, the present Reliability Standard leaves the determination and documentation of “clearance 1” to transmission owners. As such, there are no specific clearances, or criteria/procedures to develop clearances, before the Commission for approval. What is in front of the Commission relative to “locations on the right-of-way where the Transmission Owner is restricted from attaining the clearances specified in Requirement R1.2.1” is addressed in Requirement R1.4. Requirement R1.4 states that “Each Transmission Owner shall develop mitigation measures to achieve sufficient clearances for the protection of the transmission facilities when it identifies locations on the right-of-way where the Transmission Owner is restricted from attaining the clearances specified in Requirement R1.2.1.” This Requirement addresses the instances when an entity cannot attain the clearances that it needs on land that it controls. Since there are multiple mitigation measures that the entity can employ to achieve the goal of preventing outages due to vegetation management practices, the Commission has stated that any potential issues regarding minimum clearances on Forest Service lands should be dealt with on a case-by-case basis.

732. Avista and Portland General ask the Commission to endorse the Vegetation MOU. The Commission reiterates its direction that the minimum clearances must be sufficient to avoid any sustained vegetation-related outages for all applicable conditions. The Vegetation MOU references IEEE 516 as the only way to determine applicable minimum clearances. The Commission declines to endorse the use of IEEE 516 as the only minimum clearance because it is intended for use as a guide by highly-trained maintenance personnel to carry out live-line work using specialized tools under controlled environments and operating conditions, not for those conditions necessary to safely carry out vegetation management practices. [269] Further, the allowable clearances in the IEEE standard are significantly lower than those specified by the relevant U.S. safety codes. As such, use of IEEE clearance provision as a basis for minimum clearance prior to the next tree trimming as a Requirement in vegetation management is not appropriate for safety and reliability reasons. For example, the IEEE Standard 516-2003 specifies a 2.45-foot clearance from a live conductor for the 120 kV voltage class, [270] whereas the ANSI Z-133 standard specifies 12 feet, 4 inches as the approach distance for the 115 kV voltage class. [271]

733. Accordingly, the Commission directs the ERO to develop a Reliability Standard that defines the minimum clearance needed to avoid sustained vegetation-related outages that would apply to transmission lines crossing both federal land and non-federal land. While this consensus is developed, the Commission directs the ERO to address any potential issues regarding mitigation measures needed to assure these minimum clearances on Forest Service lands are appropriate on a case-by-case basis. The Commission also directs the ERO to collect outage data for transmission outages of lines that cross both federal and non-federal lands, analyze it, and use the results of this analysis and information to develop a Reliability Standard that would apply to transmission lines crossing both federal and non-federal land.

734. In regard to California PUC's concern about its ability to impose stricter requirements on vegetation clearances, the Commission notes that section 215(i)(3) of the FPA states that nothing in section 215 shall be construed to preempt the authority of a state to take action to ensure the reliability of electric service within that state, as long as the action is not inconsistent with any Reliability Standard. Therefore, the State of California may set its own vegetation management requirements that are stricter than those set by the Commission as long as they do not conflict with those set by the Commission. Further, the Commission notes that once a Reliability Standard is established, California PUC can develop stricter rules to be applied within the state of California, and if it wants them to be enforceable under section 215 of the FPA, could submit those Reliability Standards to the ERO and the Commission for approval as a regional difference.

735. FirstEnergy suggests that rights-of-way be defined to encompass the required clearance areas instead of the corresponding legal rights, and that the standards should not require clearing the entire right-of-way when the required clearance for an existing line does not take up the entire right-of-way. The Commission believes this suggestion is reasonable and should be addressed by the ERO. Accordingly, the Commission directs the ERO to address this suggestion in the Reliability Standards development process.

iv. Summary of Commission Determinations

736. The Commission approves FAC-003-1 as mandatory as enforceable. In addition, while we do not direct the ERO to submit a modification to the general limitation on applicability as proposed in the NOPR, we require the ERO to address the proposed modification through its Reliability Standards development process as discussed above. Further, while the Commission is dissuaded from requiring the ERO to create a backstop inspection cycle at this time, it directs the ERO to develop compliance audit procedures to identify appropriate inspection cycles based on local factors. These inspection cycles are to be used in compliance auditing of FAC-003-1 by the ERO or Regional Entity to ensure such inspection cycles and vegetation management requirements are properly met by the responsible entities. Finally, the Commission directs the ERO to develop a Reliability Standard through the Reliability Standard development process that defines the minimum clearance needed to avoid sustained vegetation-related outages that would apply to transmission lines crossing both federal land and non-federal land. While this consensus is developed, the Commission directs the ERO to address any potential issues regarding mitigation measures needed to assure these minimum clearances on Forest Service lands are appropriate on a case-by-case basis. The Commission also directs the ERO to collect outage data for transmission outages of lines that cross both federal and non-federal lands, analyze it, and use the results of this analysis and information to develop a Reliability Standard that would apply to transmission lines crossing both federal and non-federal land.

d. Facility Ratings Methodology (FAC-008-1)

737. FAC-008-1 requires each transmission owner and generation owner to develop a facility rating methodology for its facilities, which should consider manufacturing data, design criteria (such as IEEE, ANSI or other industry methods), ambient conditions, operating limitations and other assumptions. This methodology is to be made available to reliability coordinators, transmission operators, transmission planners and planning authorities who have responsibility in the same areas where the facilities are located for inspection and technical reviews.

738. In the NOPR, the Commission proposed to approve Reliability Standard FAC-008-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to develop a modification to FAC-008-1 through the Reliability Standards development process that requires transmission and generation facility owners to: (1) Document underlying assumptions and methods used to determine normal and emergency facility ratings; (2) develop facility ratings consistent with industry standards developed through an open process such as IEEE or CIGRE and (3) identify the limiting component(s) and define the increase in rating based on the next limiting component(s) for all critical facilities.

i. Methodology Used To Determine Facility Ratings and Documentation of Underlying Assumptions

(a) Comments

739. EEI, Valley Group, MidAmerican and TANC support the Commission's proposal to require additional documentation as a reasonable means to provide more transparency and consistency. EEI suggests that this requirement could be accommodated with a provision for the disclosure of such information upon request by a registered user, owner or operator. TANC supports the Commission's proposal to not require a uniform facility rating methodology and recommends that the Commission adopt a policy that provides for each transmission owner and generation owner to develop and document a facility rating methodology, which is consistent with industry methodologies, for their facilities. TANC also states that the methodology used for developing facility ratings should include a description of and justification for all of the assumptions. Valley Group states that it is extremely important that the underlying assumptions and methods are documented and known to all parties. Valley Group maintains that this will also ensure that the rating assumptions used by operating and planning functions are consistent with each other. Valley Group emphasizes that making these assumptions open is important, especially regarding paths between different transmission owners, to ensure that transmission owners cannot exercise market power. It argues that open assumptions will also provide rational grounds for dispute resolution.

(b) Commission Determination

740. As EEI, TANC, Valley Group and MidAmerican discuss in their comments, the Commission's proposal to modify FAC-008-1 to require additional documentation supports the Commission's goals of improving uniformity and transparency in the facility ratings process. EEI's suggestion that having this information available for review upon request of a registered user, owner or operator should be considered by the ERO in its Reliability Standards development process. As proposed in the NOPR, the Commission directs the ERO to submit a modification to FAC-008-1 that requires transmission and generation facility owners to document underlying assumptions and methods used to determine normal and emergency facility ratings. As stated in the NOPR, the Commission believes that this added transparency will allow customers, regulators and other affected users, owners and operators of the Bulk-Power System to understand how facility owners set facility ratings through differing methods that provide equivalent results.

ii. Rating Facilities Consistent with Industry Standards Developed Through an Open Process such as IEEE and CIGRE

(a) Comments

741. The Valley Group states that the Commission correctly identifies IEEE and CIGRE as examples of open process methodologies suitable for overhead transmission line ratings calculations. It claims that IEEE and CIGRE are the only methodologies which make their algorithms available to everybody, and clearly document their assumptions. Valley Group notes that both of these methodologies will undergo a revision for accuracy regarding calculations for high temperatures and high current densities in the next two years, which may lead in some cases to slightly lower line ratings, although the changes are not expected to be substantial.

742. APPA suggests that the proposal to rate facilities consistent with industry methodologies developed through an open process such as IEEE and CIGRE should be considered in the ERO's Reliability Standards development process rather than ordered by the Commission. LPPC asks the Commission to require only that facility ratings be consistent with good utility practice. According to LPPC, to the extent facility rating methodologies need to be more prescriptive than good utility practice, the details must be spelled out in the ERO Reliability Standards themselves, not by reference to other unspecified industry methodologies. LPPC believes that it would be poor policy for the Commission to endorse these methodologies since it would be impossible to police the processes by which such organizations develop their methodologies. MidAmerican states that the Commission should recognize that the proposal to require facility ratings be consistent with industry methodologies developed through an open process is potentially problematic, noting that certain aspects of the development of facility ratings are based on industry standards that are not developed through an open process, such as information provided by engineering textbooks or manufacturer information that is not specifically referenced in any current standard. MidAmerican recommends that the Commission delete the requirement that facility ratings be “developed through an open process such as IEEE or CIGRE” or add other sources that the Commission would find appropriate, such as the results of accepted scientific and engineering investigations and common sense. MRO requests that the Commission clarify whether its directive to modify FAC-008-1 to develop facility ratings consistent with industry standards developed through an open process such as IEEE or CIGRE would allow for legitimate regional differences such as climate, terrain or population density.

(b) Commission Determination

743. In the NOPR, the Commission stated, “While not proposing to mandate a particular methodology, we do propose that the methodology chosen by a facility owner be consistent with industry standards developed through an open process such as IEEE or CIGRE.” [272] These processes have been validated through actual testing and have been shown to provide appropriate results. Information from engineering textbooks, common sense or manufacturer information would be part of the underlying assumptions. The Commission's intent in the NOPR was to require that FAC-008-1 be modified to require that facility ratings be developed consistent with industry standards developed through an open, transparent and validated process. The Commission agrees with Valley Group that IEEE and CIGRE are two examples of such processes and disagrees with LPPC that reference to industry standards is poor policy. Industry standards that have been verified by actual testing are appropriate. However, the Commission agrees with MidAmerican that IEEE and CIGRE are just two examples of such bodies; any other open process that has been technically validated for its provision of accurate, consistent ratings is also acceptable. The ERO should consider the concerns raised by LPPC and MRO in its Reliability Standards development process, and is hereby directed to do so. The Commission does not expect there to be any regional differences because the only differences should be from different underlying assumptions that are not defined by the Reliability Standard.

iii. Identify the Limiting Component(s) and Define for All Critical Facilities the Rating Based on the Next Limiting Component Within the Same Facility

(a) Comments

744. TANC maintains that the rating information provided by the transmission owners and generator owners should include additional information about all of the limiting components of the elements (e.g., transmission lines, transformers, etc.) for all critical facilities. Access to such information will enable neighboring systems to accurately study the effects of other facilities on their own systems and determine the critical elements for increasing facility ratings.

745. Valley Group states that identifying the limiting elements is an excellent objective for reliability enhancement, but notes that its granularity must be limited to major elements of the circuits, such as transformers and breakers, while treating the transmission lines as single elements. Valley Group also notes that, of the two examples discussed in the NOPR, the example regarding relay settings is technically well justified, whereas rating the line based on a single limiting span is generally impractical because line design engineers add to the National Electric Safety Code minimum requirements “safety buffers,” which vary depending on their confidence in the accuracy of design calculations.

746. APPA is concerned about the possible “unintended consequences” of this modification and questions whether this proposed Requirement can be done as a practical matter; how many critical facilities and limiting components would have to be modeled to meet such a Requirement; and whether the cost of such modeling is justified by the reliability benefits. Dynegy, MISO and Wisconsin Electric also oppose this requirement because it is ambiguous, the additional work required to identify the increase in rating based on the next limiting component(s) is unwarranted and potentially costly, and the need for any such specific information is questionable. Dynegy and Wisconsin Electric do not believe there is a widespread need for this type of information and recommend that the need for it be explored on a case-by-case basis rather than including a global requirement in the standards.

747. Dynegy, FirstEnergy and MISO state that it is not clear what specific criteria would be used to define “critical facilities” and “limits.” EEI also states that developing a practical definition of “critical facilities” presents a challenge, and that compliance would require the analysis of possibly hundreds of thousands of “limiting” transmission elements to determine whether a limit is of primary concern or is contingent on the status of other nearby elements or system conditions at a particular time. EEI suggests that, rather than requesting that the industry develop a definition, it may be more useful for the Commission to recommend that the industry develop a set of high-level criteria that could be used to identify those transmission elements that create significant potential limits that are independent of other factors and considerations.

748. EEI and TVA assert this recommendation does not seem to be intended to enhance reliability but to provide additional commercial information to the market, and may not be appropriate to include in a Reliability Standard. Portland General further points out that this information can be obtained from a transmission provider by submitting a transmission or interconnection request when ATC is not posted or not available. TVA comments that, since the focus of this proceeding is the Reliable Operation of the Bulk-Power System, changes to a proposed Reliability Standard, such as FAC-008-1, that appear designed to promote maximum commercial use of the grid are unwarranted in this proceeding and could jeopardize, rather than further, reliable transmission system operations.

749. MRO seeks clarification about whether the proposed modification will require that all limiting facilities elements be published. MRO believes that serious confidentiality issues are raised due to the security-sensitive nature of the information and urges the Commission not to require the publication of such information.

750. Dominion states that the Commission should exclude from this requirement facilities that are covered under an open, regional transmission expansion planning process, such as the Regional Transmission Expansion Plan process in PJM, where any interested party can be involved in the studies and determine what the limitations are and what could be done to increase transmission capacity.

751. International Transmission states that, if the Commission were to require defining the increase in facility rating based on the next limiting element, it should restrict such application to transmission elements where the conductor itself is not the limiting element. International Transmission explains that in cases where the line must be completely rebuilt, it would not be feasible to estimate the increase in facility rating, since the new line could be specified to carry virtually any amount of power.

752. MISO questions how a generator operator or generation owner would identify the increase in rating based on the next most limiting component(s) associated with generator output. FirstEnergy believes that this modification should recognize that generators may need to rely on transmission owners to point out facilities that are more limiting than the generator facilities.

753. Manitoba's technical experts disagree with the Preliminary Staff Assessment regarding FAC-008-1. The Reliability Standard properly places the responsibility of determining facility ratings with the facility owners. Manitoba also states that, since this Reliability Standard requires that the “Facility Rating shall be equal to the most limiting applicable Equipment Rating of the individual equipment that comprises that Facility,” information on the next limiting component is already identified. Contrary to the Commission's view, Manitoba does not believe it would be appropriate in this Reliability Standard to identify the increase in rating for all critical facilities based on the next limiting component. In a networked system, there may be other limitations that set the current carrying capability of the critical facility.

754. Manitoba further notes that the Commission proposal may lead to international conflicts in Reliability Standards. Manitoba states that a mandated change to FAC-008-1, which forces an entity to accept facility ratings beyond its risk tolerance, would be grounds for Manitoba to recommend that the provincial government of Manitoba not approve this Reliability Standard because it would degrade reliability.

755. APPA suggests that the proposal to identify the limiting component and define for all critical facilities the rating based on the next limiting component be considered in the ERO's Reliability Standards development process rather than ordered by the Commission.

(b) Commission Determination

756. The Commission agrees with TANC that this modification would provide useful information to neighboring systems and users, owners and operators of the Bulk-Power System. The Commission also agrees with Valley Group that identifying the limiting elements of facilities enhances reliability by providing operators specific information about the limiting elements and therefore allowing them to assess the risks associated with circuit loadings.

757. In response to the comments of APPA, Dynegy, EEI, MISO and Wisconsin Electric, the Commission clarifies that this Reliability Standard and the Commission's proposed modification apply to facilities. As defined in the NERC glossary, a facility is “a set of electrical equipment that operates as a single Bulk Electric System Element [273] (e.g., a line, a generator, a shunt compensator, transformer, etc.).” The most limiting component in a facility determines its rating, just like the rating of a chain is determined by the weakest link. The Commission's proposed modification would require identifying and documenting the limiting component for all facilities and the increase in rating if that component were no longer the most limiting component; in other words, the rating based on the second-most limiting component. The Commission further clarifies that this Reliability Standard will require this additional thermal rating information only for those facilities for which thermal ratings cause the following: (1) An IROL; (2) a limitation of TTC; (3) an impediment to generation deliverability or (4) an impediment to service to major cities or load pockets.

758. EEI and TVA raise concerns that this modification promotes commercial use of the grid rather than ensuring Reliable Operation of the Bulk-Power System, and relates more to transmission access than reliable operations. The Commission disagrees that this modification relates primarily to transmission access. When the transmission operators know which component within the transmission element is limiting they have more information to inform their decisions about how to provide for the Reliable Operation of the Bulk-Power System. Our proposed modification does not require any entity to invest in equipment to increase ratings of any facility; it simply requires the next limiting component of each facility to be identified in order to understand what components are causing the limits that are to be used in reliability mitigation assessments. The identification of the first limiting component is already an inherent requirement in the existing rating process. As clarified above, the modification to identify an increase in rating of the transmission element that would result from removing the first limitating component applies only to critical facilities whose thermal ratings have been reached causing an SOL or IROL condition. As Dominion highlights in its comments, this information is already identified in the planning processes of some RTOs and ISOs.

759. In response to the concerns raised by EEI and MRO about sharing confidential, market-sensitive information, the Commission disagrees that ratings information is confidential or market-sensitive. All users, owners and operators should have access to the facility ratings in order to operate the system reliably. Section 215(a)(4) of the FPA defines Reliable Operation, in part, as operating the elements of the Bulk-Power System within equipment and electric system thermal stability limits. [274] Without knowing the ratings, it is not possible to know whether this requirement is being met. As to the argument that this information is confidential, the Commission clarifies that, as with the other information required by this Reliability Standard, the additional information required by this modification would be shared only with users, owners and operators of the Bulk-Power System.

760. In response to Dominion's comments, if the PJM Regional Transmission Expansion Planning process meets the criteria, there is no need to exclude facilities covered by that process from this requirement.

761. The Commission directs the ERO to consider International Transmission's comments regarding requiring information about the increase in facility rating based on the next limiting element only for lines where the conductor itself is not the limiting element in its Reliability Standards development process. Similarly, the ERO should also consider the comments from MISO and FirstEnergy that generators will have difficulty determining the increase in ratings due to the next limiting element, since in most cases the generator itself would be the most limiting element.

762. We agree with Manitoba that this Reliability Standard properly places the responsibility to determine facility ratings on the facility owner. The Commission is not proposing to change this. We also agree with Manitoba that the most limiting component is already identified when facility ratings are determined. The Commission is only directing transmission and generation owners to provide additional information on the next limiting component within the facility so that facility ratings are more transparent.

763. In response to Manitoba's and APPA's concerns, we recognize that this is an additional requirement with some complexities, and this modification will go through the ERO Reliability Standards development process. We do not intend to usurp the Reliability Standards development process, where Manitoba may raise its concerns for the ERO to consider.

iv. Applicability to Generator Owners

(a) Comments

764. Xcel states that this Reliability Standard should not apply to generator owners because capability testing, rather than using mathematical calculations, is the preferred method of determining generating unit capability. Capability testing clearly includes the capability of all the supporting components behind the generator that are required to produce a MW of capability. Xcel also states that this proposed Reliability Standard, if applied to generating units, would not improve system reliability and could result in conflicting and confusing unit capability ratings. Xcel notes that generating units already are required to be capability-tested on a periodic and seasonal basis to demonstrate unit gross and net capability in accordance with proposed standards MOD-024-1 and MOD-025-1.

765. FirstEnergy also points out that facility ratings for nuclear units are part of NRC license agreements and that the ratings methodologies included in NRC license agreements are approved by NRC. FirstEnergy proposes that compliance with NRC ratings methodology requirements should be assumed to comply with this Reliability Standard.

(b) Commission Determination

766. The Commission agrees with Xcel that an actual test could be used as a substitute for a mathematical calculation of capability, and we ask the ERO to consider these comments in its Reliability Standards development process. The Commission understands that NRC provides ratings methodologies for nuclear power plants and not for the transmission system. Capacity ratings of nuclear generators determined using this methodology are acceptable for reliability purposes. We also direct the ERO to consider FirstEnergy's comments in its Reliability Standards development process.

v. Compliance With Blackout Report Recommendation No. 27

(a) Comments

767. Manitoba believes this Reliability Standard meets the requirement of Blackout Report Recommendation No. 27 because the recommendation does not require a uniform set of methodologies for rating facilities, but instead only recommends that there be a clear, unambiguous requirement to rate transmission lines.

768. Valley Group notes that, while the Commission's proposal would direct the ERO to respond to a part of Blackout Report Recommendation No. 27, it does not address the important second part of the Recommendation, namely dynamic ratings. Valley Group notes that dynamic ratings offer a very powerful tool both for maximizing the capabilities of transmission paths and for avoiding unnecessary transmission line loading relief. Valley Group also notes that dynamic ratings, based either on ambient-adjusted ratings or ratings generated by real-time monitoring systems, are widely used in the PJM system, while broader real-time ratings are applied on certain lines in SPP and ERCOT and at several individual utilities. Valley Group states that controlling unnecessary operator interventions with dynamic ratings both increases the reliability of Bulk-Power System and improves its economy. Valley Group concludes that it would be highly desirable for the ERO to establish policies and procedures regarding dynamic ratings—as recommended by the Blackout Report, and recommends that the Commission include such guidance in its Final Rule.

(b) Commission Determination

769. The Commission believes that implementation of the modifications discussed earlier to Reliability Standard FAC-008-1 meets our goal of implementing Blackout Report Recommendation No. 27, which is to “develop enforceable standards for transmission line ratings.” [275] To achieve a clear and unambiguous Requirement to rate transmission lines, it is important to understand the underlying assumptions and the methodologies that will be used to develop those ratings. The Commission recognizes that dynamic line ratings are an innovative application, and directs the ERO to consider the comments from Valley Group in future revisions of this Reliability Standard.

vi. General Comments

770. APPA notes that FAC-008-1 should be revised to replace Levels of Non-Compliance with Violation Security Levels, and to include Violation Risk Factors on all FAC-008-1 requirements.

(a) Commission Determination

771. The Commission acknowledges that the Reliability Standards are changing. In this Final Rule, we are ruling on the Reliability Standards as they were filed, and these documents use the term Levels of Non-Compliance. The ERO should address APPA's comments in its Reliability Standards development process.

vii. Summary of Commission Determination

772. Accordingly, as discussed in the responses to comments above, the Commission approves FAC-008-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to FAC-008-1 through its Reliability Standards development process requiring transmission and generation facility owners to: (1) Document underlying assumptions and methods used to determine normal and emergency facility ratings; (2) develop facility ratings consistent with industry standards developed through an open, transparent and validated process and (3) for each facility, identify the limiting component and, for critical facilities, the resulting increase in rating if that component is no longer limiting.

e. Establish and Communicate Facility Ratings (FAC-009-1)

773. FAC-009-1 requires each transmission owner and generation owner to establish facility ratings consistent with its associated facility ratings methodology and provide those ratings to its reliability coordinator, transmission operator, transmission planner and planning authority. In the NOPR, the Commission proposed to approve FAC-009-1 as mandatory and enforceable.

i. Comments

774. APPA supports approval of FAC-009-1 as a mandatory and enforceable Reliability Standard.

ii. Commission Determination

775. FAC-009-1 serves an important reliability purpose of ensuring that facility ratings are determined based on an established methodology. Further, the proposed Requirements set forth in FAC-009-1 are sufficiently clear and objective to provide guidance for compliance. Accordingly, the Commission approves Reliability Standard FAC-009-1 as mandatory and enforceable.

f. Transfer Capability Methodology (FAC-012-1)

776. Proposed Reliability Standard FAC-012-1 requires each reliability coordinator and planning authority to document the methodology used to develop its inter-regional and intra-regional transfer capabilities. This methodology must describe how it addresses transmission topology, system demand, generation dispatch and use of projected and existing commitment of transmission.

777. In the NOPR, the Commission explained that, because the methodology to calculate transfer capability used by a reliability coordinator or planning authority has not been submitted to the Commission, it is not possible to determine at this time whether FAC-012-1 satisfies the statutory requirement that a proposed Reliability Standard be just, reasonable, not unduly discriminatory or preferential, and in the public interest. Thus, the NOPR did not propose to approve or remand this Reliability Standard until the regional procedures are submitted.

778. The NOPR explained that FAC-012-1 only requires that the regional reliability organization provide documentation on transfer capability methodology and provide it to entities such as the relevant transmission planner, planning authority, reliability coordinator and transmission operator. The Reliability Standard does not contain clear requirements on how transfer capability should be calculated, which has resulted in diverse interpretations of transfer capability and the development of various calculation methodologies. The NOPR suggested that FAC-012-1 should, as a minimum, provide a framework for the transfer capability calculation methodology including data inputs and modeling assumptions. In addition, the NOPR asked for comments on the most efficient way to make the above information transparent for all participants.

i. Methodology

(a) Comments

779. APPA, International Transmission and MidAmerican agree that the proposed FAC-012-1 is not sufficient and should not be accepted for approval as a mandatory Reliability Standard. They suggest that, at a minimum, this Reliability Standard should provide a framework for the transfer capability calculation methodology, including data inputs and modeling assumptions. APPA notes that, in the Western Interconnection and ERCOT, the sets of rules for long-range and operational planning studies are transparent to all users, owners and operators and suggests that in the Eastern Interconnection, where multiple regions exist, the Regional Entities should consider developing an umbrella organization or process comprised of representatives from each of the Eastern Interconnection's Regional Entities to establish the planning and operational rules for the Interconnection. APPA suggests that this approach would work well to identify critical facilities, by using consistent and transparent study assumptions, and it would also minimize seams issues when establishing facility rating and transfer capabilities throughout the entire Interconnection. International Transmission states that this Reliability Standard should identify the performance that is required, that specifics of how transfer capability should be calculated do not belong in this Reliability Standard, and that a reference document could be developed for this purpose.

(b) Commission Determination

780. Although we are not proposing to approve or remand this Reliability Standard, because it is applicable to the regional reliability organization, the Commission agrees with APPA, International Transmission and MidAmerican that, at a minimum, this Reliability Standard should provide a framework for the transfer capability calculation methodology, including data inputs and modeling assumptions. The Commission agrees with APPA that there should be an umbrella organization to assure consistency within the Eastern Interconnection and the other interconnections. We believe that the best organization to do this would be the ERO, because it is the only organization with knowledge of all of the individual Regional Entities that can carry out this function. Therefore, we direct the ERO to modify this Reliability Standard to provide such a framework.

ii. Transparency and Confidentiality

(a) Comments

781. International Transmission cautions that, in making information regarding the framework for calculating transfer capability transparent to all participants, a balance must be maintained between the need for transparency and the need to maintain the confidentiality of sensitive critical energy infrastructure information (CEII). The results of certain critical contingency analyses would not be appropriate for public disclosure, but may be the basis for transfer capability limits imposed on some interfaces.

782. MidAmerican suggests that transparency could be provided in the Eastern Interconnection by each reliability coordinator and each planning authority posting the transfer capability calculations performed pursuant to FAC-012-1, along with a document outlining how they were determined and the purposes for which they are used on a protected Web site. The protected site should be accessible only to qualified entities. MidAmerican suggests that the Western Interconnection's approach, the WECC message system used for certain qualified paths, is an appropriately transparent system.

(b) Commission Determination

783. Although we are not proposing to approve or remand this proposed Reliability Standard, the Commission believes that it can be improved. The Commission believes that the process used to determine transfer capabilities should be transparent to the stakeholders, and agrees with International Transmission and MidAmerican that the results of those calculations should not be available for public disclosure but only for qualified entities on a confidential basis. In addition, the process and criteria used to determine transfer capabilities must be consistent with the process and criteria used for other users of the Bulk-Power System. Simply stated, the criteria used to calculate transfer capabilities for use in determining ATC must be identical to those used in planning and operating the system. The Commission directs the ERO to take this into account in its Reliability Standards development process, and to modify the Reliability Standard consistent with Order No. 890 in Docket No. RM05-25-000.

784. Accordingly, the Commission affirms the NOPR proposal to not approve or remand this Reliability Standard. We understand that the ERO implemented its Reliability Standards development process to revise the Reliability Standard and will be submitting it in accordance with the schedule identified in Order No. 890.

g. Establish and Communicate Transfer Capability (FAC-013-1)

785. FAC-013-1 requires either the reliability coordinator or the planning authority, as determined by the regional reliability organization, to calculate transfer capabilities consistent with its transfer capability methodology and provide those capabilities to its transmission operators, transmission service providers and planning authorities.

786. In the NOPR, the Commission proposed to approve Reliability Standard FAC-013-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to develop a modification to FAC-013-1 that: (1) Makes it applicable to all reliability coordinators and (2) removes the regional reliability organization as the entity that determines whether a planning authority has a role in determining transfer capabilities.

i. Comments

787. APPA supports the Commission's proposal to approve FAC-013-1 as a mandatory and enforceable Reliability Standard, but disagrees with the Commission's proposed modification to remove the regional reliability organization as the entity that determines whether a planning authority has a role in determining transfer capabilities. APPA believes that regional committee processes are essential to determine, through their planning and operating committees, which planning authorities and reliability coordinators are responsible for determining and distributing each of the specific transfer capability values within each regional footprint. APPA proposes that in the Eastern Interconnection, where multiple regional reliability organizations and Regional Entities exist, the Regional Entities should consider developing an umbrella organization or process comprised of representatives from each of the Eastern Interconnection's Regional Entities, to establish the planning and operational planning rules for the Interconnection. APPA believes that such a program would minimize seams issues when establishing facility ratings and transfer capabilities throughout the entire Interconnection.

788. MidAmerican supports the Commission's proposal to make this Reliability Standard applicable to all reliability coordinators and planning authorities. MidAmerican believes in a clear separation of responsibilities between the reliability coordinators and planning authorities. MidAmerican believes that reliability coordinators should calculate transfer capabilities in the operating horizon, while planning authorities calculate transfer capabilities in the planning horizon, and would support additional clarification of the standard by explicitly stating the continued responsibility of planning authorities to calculate transfer capabilities for the planning horizon.

789. TANC is concerned that, if the transmission service provider and the transmission operators are specifically named in Requirement R2.1 of this Reliability Standard, but are not included in the Applicability section, this will cause ambiguity. TANC questions whether a transmission service provider or transmission operator that does not receive the transfer capabilities from the reliability coordinator will be held accountable and penalized for not producing the transfer capabilities when the reliability coordinator never provided them. If this is the case, TANC questions whether there will be different penalties for the transmission service provider and transmission operator, or whether they will be subject to the same penalties as the entities listed in the Applicability section.

790. EEI believes that the full range of issues discussed here are currently under review under Docket No. RM05-25 and proposes that these issues remain in a single forum to avoid confusion.

ii. Commission Determination

791. The Commission does not believe that the regional reliability organization should be able to decide the type of entity to which this Reliability Standard applies. The Commission disagrees with APPA that regional committee processes are essential to determine which planning authorities and reliability coordinators are responsible for determining and distributing each of the specific transfer capability values. Reliability coordinators have a wider-area view of the transmission system than planning authorities, which is important in calculating inter- and intra-regional transfer capabilities. Therefore, the Commission agrees with MidAmerican that reliability coordinators should calculate transfer capabilities in the operating horizon. The Commission will not address MidAmerican's proposal regarding calculating transfer capabilities in the planning horizon because those Reliability Standards are being considered in Docket No. RM07-3-000 and are therefore beyond the scope of this proceeding.

792. The Commission, as discussed elsewhere in this Final Rule, has considered APPA's proposal concerning creating an umbrella organization in regard to FAC-012-001. [276]

793. In regard to TANC's concern that transmission service providers and transmission operators may be liable because they are specifically named in Requirement R2.1, the Commission clarifies that, because the Reliability Standard only provides that the transmission service providers and transmission operators receive information regarding transfer capabilities, and does not require an affirmative action on the part of transmission service providers or transmission operators, a transmission service provider or transmission operator cannot be liable for violating the Reliability Standard.

794. The Commission disagrees with EEI that these matters should be evaluated only in the OATT Reform Proceeding. In Order No. 890, the Commission directed transmission owners to use the ERO's Reliability Standards development process to implement changes required in that Final Rule. [277]

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

6. INT: Interchange Scheduling and Coordination

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

a. Interchange Authority

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

i. Comments

798. ISO-NE states that it is unclear who the interchange authority should be, how its tasks could be performed operationally and how the interchange authority function relates to other reliability and market functions. ISO-NE states that NERC has not yet fully incorporated the concept of an interchange authority into its Functional Model and has not provided a means for an entity to register as an interchange authority under the Functional Model. Finally, ISO-NE states that NERC must still create a process to allow the appropriate entities to register as interchange authorities so that their status is clear to all applicable entities, and it urges that approval of the Reliability Standards that have the interchange authority as an applicable entity be withheld until these issues are resolved.

799. APPA agrees that applicability of the Reliability Standards to the interchange authority is confusing. However, APPA suggests the best approach to the problem is for NERC to identify the source and sink balancing authorities as the applicable entity in these Reliability Standards until the Functional Model is revised to better specify the status and responsibility of interchange authorities.

800. EEI observes that there is considerable confusion throughout the industry regarding the registration process and the relationship between registration and applicability of standards, with the interchange authority being an example of that confusion. However, EEI states it understands that the role of an interchange authority is currently being addressed and revisions to the Functional Model are currently moving through the approval process. If Version 3 of the Functional Model is approved by the NERC Board, EEI believes it will clarify that a sink balancing authority performing a Tag authority service could serve as an interchange authority and this modification would address the Commission's concern.

801. The CAISO suggests that it is premature to place any INT Reliability Standards involving an interchange authority into effect until more information is provided concerning the interchange authority's role.

ii. Commission Determination

802. The NERC glossary definition of interchange authority indicates that it is intended to provide essentially a quality control function in verifying and approving interchange schedules and communicating that information. Our understanding is that, in the interim, sink and source balancing authorities will serve as interchange authorities until the ERO has further clarified an interchange authority's role and responsibility in the modification of the Functional Model and in the registration process. The new interchange authority function allows an entity other than a balancing authority to perform this function in the future; the pre-existing INT-001-1 Reliability Standard identified the balancing authority as the responsible entity to perform this function. Any such entity should be registered by the ERO in the ERO compliance registry, so that the responsibility of an entity, other than a balancing authority, that takes on this role in the future would be clear.

803. In short, there is sufficient clarity concerning the nature and responsibilities of this function for it to be implemented at this time. Withholding approval of INT Reliability Standards pending further clarification on this matter would create an unnecessary gap in the coverage of the Reliability Standards that potentially could threaten the reliability of the Bulk-Power System.

b. Interchange Information (INT-001-2)

804. INT-001-1 seeks to ensure that interchange information is submitted to the reliability analysis service identified by NERC. [280] This Reliability Standard applies to purchasing-selling entities and balancing authorities. It specifies two Requirements that focus primarily on establishing who has responsibility in various situations for submitting the interchange information, previously known as transaction tag data, to the reliability analysis service identified by NERC. The Requirements apply to all dynamic schedules, delivery from a jointly owned generator and bilateral inadvertent interchange payback.

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

806. The Commission also noted in the NOPR that certain Requirements of INT-001-0 that relate to the timing and content of e-Tags had been deleted in the Version 1 Reliability Standard. NERC indicated that these Requirements are business practices that would be included in the next version of the NAESB Business Practices. The Commission stated in the NOPR that NERC's explanation of this change was acceptable and proposed to approve INT-001-1 with the deletion of Requirements R1.1, R3, R4 and R5. However, the Commission also noted that NAESB had not yet filed the e-Tagging requirements as part of its business practices, and that if no such business practice has been submitted at the time of the Final Rule, the Commission may reinstate these Requirements in the Final Rule.

807. NERC submitted INT-001-2, which supersedes the Version 1 Reliability Standards, in its November 15, 2006 filing. INT-001-2 adds Measures and Levels of Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, the Commission addresses INT-001-2, as filed with the Commission on November 15, 2006.

i. Comments

808. APPA states that NERC's submission of INT-001-2 on November 15, 2006 has fulfilled the Commission's proposed directive to include Measures and Levels of Non-Compliance in this Reliability Standard. APPA also states that, while it does not oppose NERC consideration of the Commission's proposed directive regarding the submission of interchange information for all point-to-point transfers entirely within a balancing authority area, it does not understand the Commission's reliability concerns in this connection.

809. MidAmerican states that it favors the Commission's proposed directive to NERC for a modification of the Reliability Standard as a substantial improvement for reliability. Constellation supports this proposal and states that the proposal, together with other initiatives, such as OATT reform, represent additional steps to achieving not only Bulk-Power System reliability, but also a reduction of undue discrimination in transmission services.

810. NERC disagrees with the Commission's proposal to direct the submission of interchange information on all point-to-point transfers within a balancing area. NERC contends that this issue was discussed at great length in the Reliability Standards development process and the vast majority of commenters and voters agreed that such a requirement would have no merit from a reliability perspective. It also states that such data is not used today by the NERC interchange distribution calculator for reliability. [282] Finally, NERC concludes that while it may be appropriate for this issue to be reconsidered in revisions to the Reliability Standards, a Commission directive to include a requirement that the collective expertise and the consensus of the industry have determined to be unnecessary for reliability constitutes “setting the standard.”

811. LPPC agrees with the Commission that Requirements R1.1, R3, R4 and R5 are good business practices, and it states that for this reason they should not be included in the Reliability Standards. These business practices should more appropriately be contained in NAESB standards, or perhaps the pro forma OATT.

812. ERCOT maintains that INT-001-1 is not appropriate for the ERCOT region. ERCOT states that it is a single balancing authority. To the extent that INT-001-1 requires tagging transfers within a single balancing authority, it cannot be applied to ERCOT as written because all point-to-point transfers within ERCOT are financial transactions only. ERCOT notes that it tags transfers outside the ERCOT region.

813. Allegheny states that the requirement to tag point-to-point transactions cannot be met in the PJM market where Tags are not used when a transaction's source and sink are within the PJM footprint. Such transactions are reported through the PJM eSchedule system, which already provides adequate information for the PJM region to conduct reliability and curtailment analyses. Allegheny states that there is no reliability gap in the PJM market arising from this issue.

814. Santa Clara submits that LSEs should be applicable entities under proposed revised INT-001-2 to ensure that they have adequate notice of the requirements of this Reliability Standard. It states that the actions of LSEs are implicated in Requirement R1 of this proposed Reliability Standard. [283]

ii. Commission Determination

815. The Commission approves INT-001-2 as a mandatory and enforceable Reliability Standard. In addition, we direct the ERO to develop modifications to the Reliability Standard through the Reliability Standards development process, as discussed below.

816. We agree with APPA that INT-001-2, submitted on November 15, 2006 includes Measures and Levels of Compliance, and we will not direct any further action regarding Measures and Levels of Compliance at this time.

817. MidAmerican and Constellation support the Commission's proposal that this Reliability Standard include a Requirement that interchange information must be submitted for all point-to-point transfers entirely within a balancing authority area, including all grandfathered and “non-Order No. 888” transfers. The Commission points out that unless these grandfathered and “non-Order No. 888” transfers are included in one of the INT Reliability Standards, they might not be subject to appropriate curtailment as necessary due to system conditions. Curtailments are determined using the interchange distribution calculator. Unless transactions internal to a balancing authority area are included in the calculator as we proposed, they are not recognized by the calculator and may never be curtailed. For instance, even if a transaction internal to a balancing authority area is non-firm and some inter-balancing authority trades are firm, the latter could be cut before the former, despite the curtailment priorities in the Order No. 888 tariff. While we recognize that most trades internal to a balancing authority area do not affect interchange, some do, since electricity flows do not necessarily follow the contract path.

818. In addition, e-Tagging of such transfers was previously included in INT-001-0 and the Commission is aware that such transfers are included in the e-Tagging logs. In short, the practice already exists, but if this Requirement is removed from INT-001-2, no Reliability Standard would require that such information be provided. We therefore will adopt the directive we proposed in the NOPR and direct the ERO to include a modification to INT-001-2 that includes a Requirement that interchange information must be submitted for all point-to-point transfers entirely within a balancing authority area, including all grandfathered and “non-Order No. 888” transfers.

819. The Commission agrees with ERCOT's conclusion that the Reliability Standard does not apply to financial point-to-point transfers within the ERCOT region. This interpretation is consistent with the proposed INT Reliability Standards. Likewise, Allegheny's views on tagging point-to-point transactions within the PJM market are consistent with the proposed INT Reliability Standards.

820. With respect to Santa Clara's position that LSEs should be applicable entities under the Reliability Standard, the Commission notes that in situations where a LSE is securing energy from outside the balancing authority to supply its end-use customers, it would function as a purchasing-selling entity, as defined in the NERC glossary, and would be included in the NERC registry on that basis. This interpretation flows from the language of the Reliability Standards, and the Commission does not perceive any ambiguity in this connection. Nevertheless, the Commission directs the ERO to consider Santa Clara's comments, and whether some more explicit language would be useful, in the course of modifying INT-001-2 through the Reliability Standards development process.

821. The Commission accepts NERC's explanation that Requirements R1.1, R3, R4 and R5 of INT-001-0 that were deleted in INT-001-1 are business practices. NAESB voluntarily filed “Standards for Business Practices and Communication Protocols for Public Utilities” in Docket No. RM05-5-000 on November 16, 2006. This filing contains wholesales electric business practice standards that incorporate e-Tagging requirements and is the subject of a separate rulemaking process that is expected to result in rules that will become effective on or about the same time as the Reliability Standard becomes mandatory.

822. Accordingly, the Commission approves Reliability Standard INT-001-2 as mandatory and enforceable. In addition, the Commission directs the ERO to develop a modification to INT-001-2 through its Reliability Standards development process that includes a Requirement that interchange information must be submitted for all point-to-point transfers entirely within a balancing authority area, including all grandfathered and “non-Order No. 888” transfers. [284]

c. Regional Difference to INT-001-2 and INT-004-1: WECC Tagging Dynamic Schedules and Inadvertent Payback

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

i. Comments

824. APPA agrees with the Commission's proposed course of action addressing this regional difference.

825. Xcel requests that the Commission accept the proposed regional difference; tagging requirements for dynamic schedules do not apply now in WECC, and it would be burdensome and would provide little reliability benefit to apply those requirements to WECC by June 2007. The Commission therefore should approve the proposed variance for an interim period until WECC's tagging requirements for dynamic schedules are developed and approved.

ii. Commission Determination

826. The Commission stressed in Order No. 672 that uniformity of Reliability Standards should be the goal and practice, “the rule rather than the exception.” [286] The Commission therefore stated in the NOPR that the absence of a tagging requirement for dynamic schedules in WECC is a matter of concern, and that for this reason it could not approve or remand this regional difference without the additional information it requested. To date the Commission has not received this information. Of particular importance in this compliance filing will be the ERO's demonstration that this practice is due to a physical difference in the system or results in a more stringent Reliability Standard. Without this information, we are unable to address Xcel's comments further. The Commission therefore directs the ERO to submit a filing within 90 days of the date of this order either withdrawing this regional difference or providing additional information.

d. Regional Difference to INT-001-2 and INT-003-2: MISO Energy Flow Information

827. NERC proposed a regional difference that would allow MISO to provide market flow information in lieu of tagging intra-market flows among its member balancing authorities; the MISO energy flow information waiver is needed to realize the benefits of locational marginal pricing within MISO while increasing the level of granularity of information provided to the NERC TLR Process. The waiver request text states that it is understood that the level of granularity of information provided to reliability coordinators must not be reduced or reliability will be negatively affected. The waiver request text includes a condition specifying that the “Midwest ISO must provide equivalent information to Reliability Authorities as would be extracted from a transaction tag.” The Commission proposed in the NOPR to approve this regional difference. It explained there that, based on the information provided by NERC, the proposed regional difference is necessary to accommodate MISO's Commission-approved, multi-control area energy market. Thus, the Commission stated it believed that the regional difference is appropriate, because it is more stringent than the continent-wide Reliability Standard and otherwise satisfies the statutory standard for approval of a Reliability Standard.

i. Comments

828. APPA agrees with Commission's proposed course of action in approving this regional difference.

ii. Commission Determination

829. The information received by the Commission demonstrates that the proposed regional difference to INT-001-2 and INT-003-2, as filed on November 15, 2006, is necessary to accommodate MISO's Commission-approved, multi-control area energy market. The Commission concludes that the regional difference is appropriate, because it is more stringent than the continent-wide Reliability Standard and otherwise satisfies the statutory standard for approval of a Reliability Standard, and therefore approves it as mandatory and enforceable.

e. Interchange Transaction Implementation (INT-003-2)

830. The purpose of INT-003-1 is to ensure that balancing authorities confirm interchange schedules with adjacent balancing authorities before implementing the schedules in their area control error equations. INT-003-1 contains a Requirement that focuses on ensuring that a sending balancing authority confirms interchange schedules with its receiving balancing authority before implementing the schedules in its control area. The proposed Reliability Standard also requires that, for the instances where a high voltage direct current (HVDC) tie is on the scheduling path, both sending and receiving balancing authorities have to coordinate with the operator of the HVDC tie.

831. The Commission proposed in the NOPR to approve Reliability Standard INT-003-1 as mandatory and enforceable. In addition the Commission proposed to direct NERC to submit a modification to INT-003-1 that includes Measures and Levels of Non-Compliance.

832. NERC filed INT-003-2 with the Commission on November 15, 2006. This Reliability Standard supersedes the Version 1 Reliability Standard INT-003-1 and adds Measures and Levels of Non-Compliance.

i. Comments

833. APPA states that INT-003-2 fulfills the Commission's proposed directive to include Measures and Levels of Non-Compliance.

ii. Commission Determination

834. INT-003-1 serves an important purpose in requiring receiving and sending balancing authorities to confirm and agree on interchange schedules. With the addition of Measures and Levels of Non-Compliance, INT-003-2 addresses the Commission's only reservation regarding this Reliability Standard. Accordingly, the Commission approves Reliability Standard INT-003-2, as filed with the Commission on November 15, 2006, as mandatory and enforceable.

f. Regional Differences to INT-003-2: MISO/SPP Scheduling Agent and MISO Enhanced Scheduling Agent

835. NERC proposed a regional difference that would provide MISO and SPP with a variance from INT-003-1 to permit a market participant to use a scheduling agent to prepare a transaction Tag on its behalf. [287] In addition, NERC proposed the MISO Enhanced Scheduling Agent Waiver, which creates a variance from INT-003-1 for MISO that permits an enhanced single point of contact scheduling agent.

836. The Commission proposed in the NOPR to approve these two additional regional differences. The Commission explained that, based on the information provided by NERC, the proposed regional differences for this INT Reliability Standard would provide administrative efficiency, and provide equal or greater amounts of information to the appropriate entities as required in MISO's Commission-approved multi-control area energy market. The NOPR stated that the regional difference is appropriate because it is more stringent than the continent-wide Reliability Standard and otherwise satisfies the statutory standard for approval of a Reliability Standard.

i. Comments

837. APPA agrees with the Commission's proposed approval of these regional differences.

838. FirstEnergy states that it would be helpful if NERC clarified the function and effect of these waivers. FirstEnergy states that, where a specific task will be performed by another entity on behalf of the transferor, the transferor entity needs a delegation agreement, whereas in transferring a responsibility, the transferor entity needs a waiver. FirstEnergy states that currently balancing authorities are held accountable by regional reliability organizations for those functions the waivers transfer to the regional reliability organization. FirstEnergy suggests that NERC should clarify that, under these waivers, responsibility for complying with these Reliability Standards should be transferred to the RTOs that actually perform the tasks associated with these requirements.

ii. Commission Determination

839. These two variances from INT-003-2, as filed with the Commission on November 15, 2006, permit a market participant to use a scheduling agent to prepare a transaction tag on its behalf, providing administrative efficiency and providing equal or greater amounts of information to the appropriate entities as required in MISO's Commission-approved multi-control area energy market. This regional difference is appropriate because it is more stringent than the continent-wide Reliability Standard and otherwise satisfies the statutory standard for approval of a Reliability Standard. The Commission therefore approves the MISO/SPP Scheduling Agent Waiver and the MISO Enhanced Scheduling Agent Waiver as mandatory and enforceable regional differences to INT-003-2.

840. FirstEnergy may raise its suggestions in the Reliability Standards development process. However, we find that FirstEnergy's suggestion does not affect our decision to approve these two regional differences.

g. Dynamic Interchange Transaction Modifications (INT-004-1)

841. INT-004-1 seeks to ensure that dynamic transfers are adequately tagged to be able to determine their reliability impact. It requires the sink balancing authority, i.e., the balancing authority responsible for the area where the load or end-user is located, to communicate any change in the transaction. It also requires the updating of Tags for dynamic schedules.

842. In the NOPR, the Commission proposed to approve Reliability Standard INT-004-1 as mandatory and enforceable. The Commission also proposed to direct NERC to submit a modification to INT-004-1 that includes Levels of Non-Compliance.

i. Comments

843. APPA agrees with the Commission that INT-004-1 can be approved as a mandatory and enforceable Reliability Standard. However, it suggests that the missing Levels of Non-Compliance should be developed and submitted for Commission approval before penalties are levied for violations.

ii. Commission Determination

844. As explained in the NOPR, while the Commission has identified concerns with regard to INT-004-1, this proposed Reliability Standard serves an important purpose by setting thresholds on changes in dynamic schedules for which modified interchange data must be submitted. Further, the Requirements set forth in INT-004-1 are sufficiently clear and objective to provide guidance for compliance. Accordingly, the Commission approves Reliability Standard INT-004-1 as mandatory and enforceable. In addition, the Commission directs the ERO to consider adding these Measures and Levels of Non-Compliance to the Reliability Standard.

h. Interchange Authority Distributes Arranged Interchange (INT-005-1)

845. INT-005-1 seeks to ensure the implementation of interchange between source and sink balancing authorities and that interchange information is distributed by an interchange authority to the relevant entities for reliability assessments.

846. The Commission proposed in the NOPR to approve Reliability Standard INT-005-1 as mandatory and enforceable. The Commission also proposed to direct NERC to submit a modification to INT-005-1 that includes Levels of Non-Compliance. Further, the Commission noted that INT-005-1 is applicable to the “interchange authority” and requested that NERC provide additional information regarding the role of the interchange authority so that the Commission can determine whether it is a user, owner or operator of the Bulk-Power System that is required to comply with mandatory Reliability Standards.

i. Comments

847. Comments on the interchange authority have been discussed above under the heading “INT Reliability Standards General Issues.” No other comments on INT-005-1 have been submitted.

ii. Commission Determination

848. The Commission has set forth above its analysis and conclusion on interchange authorities. Our understanding is that, in the interim, source and sink balancing authorities will serve as interchange authorities until the ERO has clarified the role and responsibility of an interchange authority in the modification of the Functional Model and in the registration process.

849. The Commission is satisfied that the Requirements of INT-005-1 are appropriate to ensure that interchange information is distributed timely and available for reliability assessment. Accordingly, the Commission approves Reliability Standard INT-005-1 as mandatory and enforceable. In addition, the Commission directs the ERO to consider adding additional Measures and Levels of Non-Compliance to the Reliability Standard.

i. Response to Interchange Authority (INT-006-1)

850. INT-006-1 applies to balancing authorities and transmission service providers, and requires these entities to evaluate the energy profile and ramp rate of generation that supports interchange transactions in response to a request from an interchange authority to change the status of an interchange from an arranged interchange transaction to a confirmed interchange.

851. The Commission proposed in the NOPR to approve Reliability Standard INT-006-1 as mandatory and enforceable. In addition, the Commission proposed to direct NERC to submit a modification to INT-006-1 that: (1) Makes it applicable to reliability coordinators and transmission operators and (2) requires reliability coordinators and transmission operators to review composite transactions from the wide-area reliability viewpoint and, where their review indicates a potential detrimental reliability impact, communicate to the sink balancing authorities necessary transaction modifications before implementation.

i. Comments

852. APPA agrees that INT-006-1 is sufficient for approval as a mandatory and enforceable reliability standard. However, APPA states that the Commission should merely instruct NERC to respond to the Commission's concerns and refrain from directing NERC to make specific changes to the Reliability Standard; APPA states that while the changes the Commission proposes may be appropriate, it should be left to NERC's expertise and the Reliability Standards development process to address the Commission's concerns.

853. FirstEnergy agrees that it is appropriate for the reliability coordinator to be included in the applicability section. However, it argues that it is impracticable in large organized markets, such as those of MISO and PJM, for a local entity, such as a transmission operator, to review wide-area transactions, and it does not improve reliability to do so. Transactions occurring totally within the market operation are provided as part of network service net scheduled interchange.

854. EEI states that the “wide-area reliability impact” review envisioned by the Commission, which involves review of the composite energy interchange transactions, probably already takes place under Reliability Standards INT-005 through INT-009 in a cost-effective manner. EEI explains that since most transactions submitted by wholesale markets to the transactions tagging process span multiple hours with varying sizes (in MW), and are often submitted days before transaction start times, the wide-area review consists of ensuring that sufficient generator ramping capability exists, as well as examining for limits on transfer capabilities. This review is generally considered sufficient to the extent that analyses are taking place on the basis of projected system conditions. EEI suggests that the Commission-proposed review and validation of composite energy interchange transactions by reliability coordinators might be more effectively addressed through “near real-time” system review. It explains that, at this time, the broad range of system condition parameters is better known, and the reliability coordinators can make use of the TLR process to maintain system reliability.

855. Entergy disagrees with the Commission's proposed modifications. It contends that they will require substantial changes to the tagging specifications. Entergy believes that the Commission's concerns may already be addressed by Reliability Standards INT-005 through INT-009.

856. MISO believes the Reliability Standards and e-Tag specifications already require reliability entities to evaluate and approve e-Tags. It questions the value of specifying reliability coordinators and transmission operators as applicable entities because their responsibilities are already laid out in the Reliability Standards.

857. Northern Indiana contends that the NOPR's discussion of INT-006-1 is unclear and confusing. It states that it does not understand what the Commission means by “validate” when the Commission proposes that reliability coordinators and transmission operators review and validate composite arranged interchanges. Northern Indiana also questions whether both reliability coordinators and transmission operators would be required to validate and approve the Tags and what the basis for approval would be. It questions what falls within the term “potential detrimental reliability impact,” what happens if a Tag is not validated within 20 minutes to the hour, and whether all schedules are canceled outright or passively approved.

858. TVA suggests that the term “composite Tag” should be defined as part of the proposed modifications. CAISO also questions the meaning of “composite Tag” and seeks clarification on that issue. TVA notes that depending on the type of reliability analysis required to validate a “composite Tag,” it may prove impractical to conduct this evaluation for hourly transactions.

859. CAISO states that neither NERC nor the Commission has identified a deficiency in the current interchange reliability assessment process or a pressing reliability need for this Reliability Standard. CAISO also has concerns about meeting the Commission-proposed directives regarding INT-006-1 since reliability coordinators and transmission operators within the Western Interconnection currently do not have a common database from which to draw the information needed to review composite transactions from a wide-area reliability viewpoint. CAISO requests the Commission to consider whether the Western Interconnection should comply with these proposed Requirements at all or whether a transition period is appropriate.

ii. Commission Determination

860. The Commission approves INT-006-1 as mandatory and enforceable. In addition, we direct that NERC develop modifications to the Reliability Standard, as discussed below.

861. The Commission remains convinced that a proactive approach is superior to a reactive approach in maintaining system reliability. While EEI and Entergy claim that reliability coordinators and transmission operators' involvement in reliability reviews of interchange transactions are covered in INT-005 through INT-010, and MISO claims that such review is covered in other Reliability Standards, we note the following: References to reliability coordinator and transmission operator involvement are virtually absent from the INT Reliability Standards. One finds such references only in Requirement R2 of INT-010, which deals with interchange coordination exemptions, and there the involvement of reliability coordinators is restricted to situations that involve current or imminent reliability-related reasons for action. We cannot find any Requirements in the remaining INT Reliability Standards that require a wide-area reliability assessment, regardless of the time periods, by a reliability coordinator; wide-area reliability assessment, moreover, can only be carried out by reliability coordinators.

862. With respect to MISO's comment on the value of applying the Reliability Standard to reliability coordinators and transmission operators given that the Reliability Standards and the e-Tag specification already require evaluation and active approval of reliability entities on e-Tags, we note that none of the INT Reliability Standards have those requirements and that the e-Tag specification is not part of the mandatory Reliability Standards. Like reliability coordinators who are responsible for reliable operation of entire reliability coordinator areas, a transmission operator is the reliability entity responsible for its local area operations. Interchange transactions would be likely to reduce system reliability if those transactions are not reviewed and approved by the appropriate reliability entities before implementation.

863. With respect to the question raised by TVA and CAISO on the definition of “composite Tags,” we expressed our reliability concerns in the NOPR and explained that reliability coordinators and transmission operators should review composite energy interchange transaction information (composite Tags) for wide-area reliability impact. In addition, we stated that when the review indicated a potential detrimental reliability impact, the reliability coordinator or transmission operator should communicate to the sink balancing authority the necessary transaction modifications before implementation. [288] While we did not require a specific notification time prior to actual transactions, this proactive approach should promote system reliability.

864. We agree with FirstEnergy that it is appropriate to include reliability coordinators as applicable entities for purposes of conducting wide-area reliability assessments; in large organized markets transmission operators may not be appropriate for this purpose because they do not have a wide-area view.

865. While we did not address review time frames in the NOPR, we are in general agreement with EEI's suggestion that “near-real time” system review by reliability coordinators may be more practical, while still being efficient and effective in achieving reliability goals. A proactive approach, i.e. one that involves reliability coordinators in a way that permits them to make wide-area assessments of composite interchange transactions for purposes of evaluating reliability impact, including identifying potential IROL violations and mitigating them using TLR procedures before they become actual IROL violations, is far superior to a reactive approach, i.e., one that brings reliability coordinators in after the fact to invoke TLR procedures to avoid an IROL violation or other operating actions to extricate the system from reliability problems such as an actual IROL violation.

866. The Commission stated in Order No. 672 that it expected entities to use the Reliability Standards development process to address their concerns about a Reliability Standard. With respect to CAISO's request that the Commission consider whether the Western Interconnection needs to comply with these Requirements at all or whether a transition period is appropriate, since CAISO did not raise either concern in the Reliability Standards development process, and others in the Western Interconnection have not raised a similar concern, CAISO should raise this issue in the Reliability Standards development process in the first instance. Reliability Standard INT-006-1 will apply to CAISO.

867. Accordingly, the Commission approves Reliability Standard INT-006-1 as mandatory and enforceable. In addition, the Commission directs the ERO to develop a modification to INT-006-1 through the Reliability Standards development process that: (1) Makes it applicable to reliability coordinators and transmission operators and (2) requires reliability coordinators and transmission operators to review energy interchange transactions from the wide-area and local area reliability viewpoints respectively and, where their review indicates a potential detrimental reliability impact, communicate to the sink balancing authorities necessary transaction modifications before implementation. We also direct that the ERO consider the suggestions made by EEI and TVA and address the questions raised by Entergy and Northern Indiana in the course of the Reliability Standards development process.

j. Interchange Confirmation (INT-007-1)

868. Reliability Standard INT-007-1 requires that before changing the status of submitted arranged interchanges to confirmed interchanges, the interchange authority must verify that the submitted arranged interchanges are valid and complete with relevant information and approvals from the balancing authorities and transmission service providers. The Commission proposed in the NOPR to approve INT-007-1 as mandatory and enforceable.

i. Comments

869. APPA agrees with the Commission that INT-007-1 is sufficient for approval as a mandatory and enforceable Reliability Standard, subject to NERC's plans for the registration of entities as interchange authorities.

ii. Commission Determination

870. The Commission approves Reliability Standard INT-007-1 as mandatory and enforceable. The Commission has set forth above its analysis and conclusion on interchange authorities. Our understanding is that in the interim source and sink balancing authorities will serve as interchange authorities until the ERO has clarified the role and responsibility of an interchange authority in the modification of Functional Model and in the registration process.

k. Interchange Authority Distribution of Information (INT-008-1)

871. INT-008-1 requires the interchange authority to distribute information to all balancing authorities, transmission service providers and purchasing-selling entities involved in the arranged interchange when the status of the transaction has changed from arranged interchange to confirmed interchange. The Commission proposed in the NOPR to approve INT-008-1 as mandatory and enforceable.

i. Comments

872. APPA agrees with the Commission that INT-008-1 is sufficient for approval as a mandatory and enforceable Reliability Standard, subject to NERC's plans for the registration of entities as interchange authorities. It suggests that NERC should clarify which reliability entities have the responsibility for ensuring that interchange information is coordinated between the source and sink balancing authorities before implementing the Reliability Standard. APPA also states that NERC should modify this Reliability Standard to make clear what entities it in fact would apply to.

ii. Commission Determination

873. The Commission approves Reliability Standard INT-008-1 as mandatory and enforceable. The Commission has set forth above its analysis and conclusion on interchange authorities. Our understanding is that a source and sink balancing authority will serve as the interchange authority until the ERO has clarified the role and responsibility of an interchange authority in the modification of the Functional Model and in the registration process. Finally, we direct the ERO to consider APPA's suggestions in the Reliability Standards development process.

l. Implementation of Interchange (INT-009-1)

874. Reliability Standard INT-009-1 seeks to ensure that the implementation of an interchange between source and sink balancing authorities is coordinated by an interchange authority. The Commission proposed in the NOPR to approve INT-009-1 as mandatory and enforceable.

i. Comments

875. APPA agrees with the Commission that INT-009-1 is sufficient for approval as a mandatory and enforceable Reliability Standard, subject to NERC's plans for the registration of entities as interchange authorities. It suggests that NERC modify its Functional Model to clarify which reliability entities have the responsibility for ensuring proper implementation of interchange transactions that have received reliability assessments. APPA also suggests that NERC modify this Reliability Standard to make clear what entities it in fact would apply to.

ii. Commission Determination

876. The Commission approves Reliability Standard INT-009-1 as mandatory and enforceable. The Commission has set forth above its analysis and conclusion on interchange authorities. Our understanding is that a source and sink balancing authority will serve as the interchange authority until the ERO has clarified the role and responsibility of an interchange authority in the modification of the Functional Model and in the registration process. Finally, we direct the ERO to consider APPA's suggestions concerning this Reliability Standard in the Reliability Standards development process.

m. Interchange Exemptions (INT-010-1)

877. INT-010-1 allows reliability entities to initiate or modify certain types of interchange schedules under abnormal operating conditions and to be exempt from compliance with other INT Reliability Standards.

878. The Commission explained in the NOPR that Reliability Standard INT-010-1 includes provisions that allow modification to an existing interchange schedule or submission of a new interchange schedule that is directed by a reliability coordinator to address current or imminent reliability-related reasons. The Commission interpreted these current or imminent reliability-related reasons as not including actual IROL violations, since they require immediate action so that the system can be returned to a secure operating state as soon as possible and no longer than 30 minutes after a reliability-related system interruption—a period that is much shorter than the time that is expected to be required for new or modified transactions to be implemented.

879. The Commission proposed to approve INT-010-1, interpreted as set forth above, as mandatory and enforceable.

i. Comments

880. Northern Indiana supports the Commission's interpretation of INT-010-1, but it requests that the Reliability Standard be modified to explicitly state that it does not include actual IROL violations.

881. ISO-NE supports Commission approval of INT-010-1, but does not share the Commission's concerns regarding the initiation or modification of interchange schedules to address SOL or IROL violations. It states that interchange schedules can in certain circumstances provide an additional effective tool to help prevent an SOL and IROL violation. While ISO-NE recognizes that other tools may in certain circumstances be more effective, it states that this neither diminishes the value nor precludes the use of the tools contained in INT-010-1. ISO-NE also notes that section 2.4 of INT-010-1, which describes Level 4 Non-Compliance, should be edited to state that “[t]here shall be a level four non-compliance * * *.“ instead of “[t]here shall be a level three non-compliance * * *.”

882. APPA agrees with the Commission that INT-010-1 is sufficient for approval as a mandatory and enforceable Reliability Standard, but APPA does not agree with the Commission's interpretation of the Reliability Standard. APPA explains that the stated purpose of INT-010-1 is to allow certain types of interchange schedules to be initiated or modified by reliability entities and to be exempt from compliance with other interchange standards under abnormal operating conditions. This Reliability Standard in effect authorizes reliability coordinators to direct, and balancing authorities to take, remedial actions to adjust interchange schedules immediately and then document these actions after the fact. INT-010-1 thus provides the emergency waiver from other INT Reliability Standards that makes adjusting interchange schedules the appropriate response to a SOL or IROL. APPA states that the Commission's proposed interpretation therefore should not be adopted.

883. EEI cautions against adopting the Commission's interpretation of INT-010-1. EEI believes that the existing standard meets the Commission's expectation, i.e., permitting and encouraging immediate action to alleviate an SOL or IROL. EEI explains that without INT-010-1, all interchange scheduling and schedule modifications would go through the normal process contained in INT-005 through INT-009. Only INT-010 would allow a balancing authority to make an immediate interchange action without obtaining a Tag. Within 60 minutes of the action, the balancing authority would follow up with the necessary documentation and carry forward the action, if necessary. In the absence of INT-010-1, a balancing authority taking such action would be in violation of INT-009 for failing to comply with the normal process requirements.

884. EEI notes by way of example that, to relieve an SOL or IROL, a reliability coordinator requires immediate offsetting changes in the net scheduled interchange of ACE equations of source and sink balancing authorities. Within 60 minutes following the action, the reliability authority directs the balancing authority to reflect the schedule change event using an arranged interchange. The tagging activity ensures coordination going forward and provides a written record. All of this takes place after the operational tasks pertaining to the action to alleviate the SOL or IROL, consistent with Commission expectations.

ii. Commission Determination

885. For the reasons and interpretation noted in the NOPR, the Commission approves INT-010-1 as mandatory and enforceable.

886. The Commission believes that our interpretation of INT-010-1 is consistent with the way APPA and EEI understand the Reliability Standards. The Commission believes that making a modification to an existing interchange schedule on paper for current or imminent reliability-related situations involving actual IROL violations is ineffective because its implementation usually takes much longer than the 30-minute period that is allowed in the relevant IRO or TOP Reliability Standards. However, the Commission interprets INT-010-1 as allowing the actual physical transaction to be modified to alleviate an IROL event without first documenting the modification. The interchange schedule would then be modified after the fact to document the physical actions taken.

887. With regard to ISO-NE's statement that interchange schedules can, in certain circumstances, provide an additional effective tool to help prevent SOL and IROL violations while other tools may, in certain circumstances, be more effective, the Commission clarifies that our concern is related to using interchange schedules to address actual IROL violations. We have no concern in using this as a tool help prevent potential SOL and IROL violations as asserted by ISO-NE. We further note that the phrase in Requirements R2 and R3 “current or imminent reliability-related reasons” can be interpreted as potential or actual IROL violations set forth in the comments from Northern Indiana, ISO-NE, APPA and EEI, and therefore modifications to INT-010-1 are needed.

888. Accordingly, the Commission approves Reliability Standard INT-010-1 as mandatory and enforceable. In addition, we adopt the interpretation set forth in the NOPR that these current or imminent reliability-related reasons do not include actual IROL violations, since they require immediate control actions so that the system can be returned to a secure operating state as soon as possible and no longer than 30 minutes after a reliability-related system interruption—a period that is much shorter than the time that is expected to be required for new or modified transactions to be implemented. Finally, we direct the ERO to consider Northern Indiana and ISO-NE's suggestions in the Reliability Standards development process.

7. IRO: Interconnection Reliability Operations and Coordination

889. The Interconnection Reliability Operations and Coordination (IRO) group of Reliability Standards detail the responsibilities and authorities of a reliability coordinator. [289] The IRO Reliability Standards establish requirements for data, tools and wide-area view, all of which are intended to facilitate a reliability coordinator's ability to perform its responsibilities and ensure the reliable operation of the interconnected grid.

a. Reliability Coordination—Responsibilities and Authorities (IRO-001-1)

890. IRO-001-1 requires that a reliability coordinator have reliability plans, coordination agreements and the authority to act and direct reliability entities to maintain reliable system operations under normal, contingency and emergency conditions.

891. In November 2006, NERC submitted IRO-001-1, which includes Measures and Levels of Non-Compliance. [290] In addition, while the Version 0 Reliability Standard applied to reliability coordinators and regional reliability organizations, IRO-001-1 would in addition apply to transmission operators, balancing authorities, generator operators, transmission service providers, LSEs and purchasing-selling entities. The Version 1 Reliability Standard does not modify or add any Requirements, and it appears that the change in applicability corresponds to existing Requirement R8, which provides that transmission operators, balancing authorities, generator operators, transmission service providers, LSEs and purchasing-selling entities “shall comply with Reliability Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory requirements.”

892. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification to Requirement R1 of IRO-001-0 that: (1) Reflects the process set forth in the NERC Rules of Procedures and (2) eliminates the regional reliability organization as an applicable entity.

i. Comments

893. APPA supports the approval of the Reliability Standard but expresses concern that the Version 1 standard does not include Measures that correspond to Requirements R2 and R9. APPA emphasizes the need for Measures corresponding to Requirement R9, which requires the reliability coordinator to act in the interests of reliability for the overall reliability coordinator area and the Interconnection before the interests of any other entity. APPA supports Requirement R8 with the extended applicability, provided that applicability is determined by reference to the NERC compliance registry. APPA agrees that the regional reliability organization should be eliminated as an applicable entity and suggests it be replaced with Regional Entities.

894. FirstEnergy suggests that NERC clarify whether Requirement R8, which requires entities to comply with a reliability coordinator directive “unless such actions would violate safety, equipment or regulatory or statutory requirements,” refers to personnel safety, equipment safety or both. In addition, it suggests the establishment of a chain of command so that, for example, if a generator receives conflicting instructions from a balancing authority and a transmission operator, it can determine which instruction governs.

895. Requirement R3 provides that a reliability coordinator “shall have clear decision-making authority to act and direct actions to be taken” by applicable entities to “preserve the integrity and reliability of the Bulk Electric System and these actions shall be taken without delay but no longer than 30 minutes.” Santa Clara contends that some actions would require driving to a remote site and therefore, mandating completion of the required action within 30 minutes would be unreasonable. Thus, it recommends that NERC modify Requirement R3 to provide that “actions shall commence without delay, but in any event shall commence within 30 minutes.”

896. California Cogeneration comments that the Reliability Standard fails to address the operational limitations of QFs because they have contractual obligations to provide thermal energy to their industrial hosts. It contends that a QF can be directed to change operations only in the case of a system emergency, pursuant to 18 CFR 292.307.

ii. Commission Determination

897. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, as a separate action under section 215(d)(5), the NOPR proposed to direct the ERO to develop modifications to Requirement R1 [291] to substitute “Regional Entity” for “regional reliability organization” and reflect NERC's Rules of Procedure for registering, certifying and verifying entities, including reliability coordinators. Commenters do not raise any concerns regarding the proposed action. Accordingly, for the reasons stated in the NOPR, the Commission approves IRO-001-1 as mandatory and enforceable. In addition, for the reasons discussed in the NOPR, the Commission directs the ERO to develop modifications to the Reliability Standard through the Reliability Standards development process that reflect the process set forth in the NERC Rules of Procedures and eliminate the regional reliability organization as an applicable entity. [292]

898. While APPA, FirstEnergy and California Cogeneration suggest possible changes to IRO-001-1, they do not suggest that the proposed Reliability Standard should not be approved. The ERO should consider the commenters' suggestions when modifying the Reliability Standard pursuant to its Reliability Standards development process. Further, the Commission directs the ERO to consider adding Measures and Levels of Non-Compliance in the Reliability Standard as requested by APPA.

899. However, we disagree with Santa Clara's suggested change regarding the 30-minute limit to implement a corrective control action in Requirement R3. When system integrity or reliability is jeopardized, e.g., exceeding IROLs or SOLs, the relevant reliability entities must take corrective control actions to return the system to a secure and reliable state as soon as possible and in no longer than 30 minutes. This is important to satisfy the relevant Reliability Standards such as IRO-005-0 and TOP-004-0 to minimize the amount of time the system operates in an insecure mode and is vulnerable to cascading outages.

b. Reliability Coordination—Facilities (IRO-002-1)

900. IRO-002-1 establishes the requirements for data, information, monitoring and analytical tools and communication facilities to enable a reliability coordinator to meet the reliability needs of the Interconnection, to act in addressing real-time emergency conditions and to control analysis tools. [293]

901. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification that: (1) Includes Measures and Levels of Non-Compliance and (2) modifies Requirement R7 to explicitly require a minimum set of tools for the reliability coordinator.

i. Comments

902. Dominion agrees with the proposal to require a minimum set of tools for reliability coordinators, explaining that such specificity is needed to ensure that proactive efforts to maintain reliability are being continuously pursued. According to Dominion, a general requirement for “adequate” tools is insufficient and the proposal to modify IRO-002-1 is appropriate since it will ensure that operators have a minimum set of tools with which to perform their duties.

903. In contrast, both APPA and LPPC ask the Commission to reject the proposal to require a minimum set of tools because flexibility is needed to allow change as technology improves over time. LPPC states that the Commission should, instead, require a listing of capabilities that is not tied to a particular product or tool. APPA contends that, because the Measures now require the reliability coordinator to provide specifications to the Regional Entity to be in compliance, the Regional Entity will set the minimum standards for reliability tools. Further, according to APPA, setting a minimum requirement would establish a “lowest common denominator” that might prove counterproductive.

904. MRO states that IRO-002-0 is another Reliability Standard for which it will be difficult to identify Measures and Levels of Non-Compliance because the Requirements include terms like “adequate,” “potential,” “could result” and “as required.”

ii. Commission Determination

905. NERC's November 2006 revision to the Reliability Standard satisfies the proposal to include Measures and Levels of Non-Compliance. While MRO comments that it will be difficult to identify Measures and Levels of Non-Compliance, it does not provide any specific suggestions for changes to NERC's proposal.

906. Further, consistent with the NOPR, the Commission directs the ERO to modify IRO-002-1 to require a minimum set of tools that must be made available to the reliability coordinator. We believe that this requirement will ensure that a reliability coordinator has the tools it needs to perform its functions. Further, as noted by Dominion, such a requirement promotes a more proactive approach to maintaining reliability.

907. With respect to the concerns of APPA and LPPC, the Commission clarifies that the Commission's intent is to have the ERO develop a requirement that identifies capabilities, not actual tools or products. The Commission agrees that the latter approach is not appropriate as a particular product could become obsolete and technology improves over time. We disagree with APPA that our concern is addressed by the new Measures as they neither specify a minimum set of capabilities nor require any uniformity among reliability coordinators or Regional Entities. We do not believe that the identification of minimum capabilities translates to “lowest common denominator” as suggested by APPA. If the Reliability Standards development process results in developing a “lowest common denominator” Reliability Standard that is geared toward guaranteeing compliance and avoiding penalties as opposed to ensuring reliability, the Commission could remand such a Reliability Standard. [294]

908. We disagree with MRO that it will be difficult to identify Measures and Levels of Non-Compliance since the Requirements include terms like “adequate,” “potential,” “could result” and “as required.” Many tariffs on file with the Commission do not specify every compliance detail, but rather provide some level of discretion as necessary to carry out a particular act. This does not mean the tariffs are unenforceable; rather, it means that, if a dispute arises over compliance and there is a legitimate ambiguity regarding a particular fact or circumstance, that ambiguity can be taken into account in the exercise of the Commission's enforcement discretion.

909. As we stated in the NOPR, [295] Reliability Standard IRO-002-1 serves an important purpose in ensuring that reliability coordinators have the information, tools and capabilities to perform their functions. The Measures and Levels of Non-Compliance submitted by NERC further enhance the Reliability Standard. Accordingly, the Commission approves Reliability Standard IRO-002-1 as mandatory and enforceable. In addition we direct the ERO to develop a modification to IRO-002-1 through the Reliability Standards development process that requires a minimum set of tools that should be made available to reliability coordinators.

c. Reliability Coordination—Wide Area View (IRO-003-2)

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

911. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification that includes: (1) Measures and Levels of Non-Compliance and (2) criteria to define the term “critical facilities” in a reliability coordinator's area and its adjacent systems.

i. Comments

912. APPA agrees that IRO-003-2 is sufficient for approval as a mandatory and enforceable Reliability Standard. However, APPA suggests that, instead of merely including criteria to define critical facilities as proposed, NERC and each Regional Entity should establish, document, use and make transparent the methodology, data and procedures they use to determine “critical facilities.”

913. Entergy agrees with the need for the criteria, but cautions that it must be flexible enough to allow for changing conditions experienced in real-time operations. Xcel notes that the term “critical facilities” is not defined and suggests that the Reliability Standard not be approved until the term is defined.

ii. Commission Determination

914. For the reasons stated in the NOPR, [297] the Commission approves proposed Reliability Standard IRO-003-2 as mandatory and enforceable. NERC's November 2006 revision to the Reliability Standard satisfies the proposal to include Measures and Levels of Non-Compliance.

915. Further, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, we adopt in the Final Rule the proposal to direct that the ERO develop a modification to the Reliability Standard through the Reliability Standards development process to create criteria to define the term “critical facilities” in a reliability coordinator's area and its adjacent systems. In developing the required modification, the ERO should consider the suggestions of APPA, Entergy and Xcel.

d. Reliability Coordination—Operations Planning (IRO-004-1)

916. The purpose of IRO-004-1 is to require each reliability coordinator to conduct next-day operations reliability analyses to ensure that the system can be operated reliably in anticipated normal and contingency system conditions. Operations plans must be developed to return the system to a secure operating state after contingencies and shared with other operating entities.

917. In the NOPR, the Commission proposed to approve Reliability Standard IRO-004-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification to IRO-004-1 that requires the next-day analysis to identify effective control actions that can be implemented within 30 minutes during contingency conditions.

i. Comments

918. APPA agrees that IRO-004-1 is sufficient for approval as a mandatory Reliability Standard and that the Requirements are sufficiently clear and objective to provide a basis for issuing a remedial action directive. However, it contends that many Requirements lack Measures and Levels of Non-Compliance, and the ERO and Regional Entities should not assess penalties until additional Measures and Levels of Non-Compliance are developed.

919. Entergy agrees that a mitigation plan for potential operating problems identified in the next-day analysis may be an appropriate requirement, but cautions that it would be inappropriate to penalize an entity that chooses an alternate mitigation strategy when the issues arise in real time based on system conditions prevalent at that time.

920. APPA, in contrast, disagrees with the proposed directive to identify effective control actions in the next-day analysis. It contends that real-time conditions are seldom the same as predicted in the day-ahead schedule, and state estimators using real-time operating conditions are much more accurate than analyses based on day-ahead schedules.

921. FirstEnergy contends that IRO-004-1 should require a day-ahead planning process and reflect activities inherent within a market operation.

922. Northern Indiana contends that the Commission's proposed directive is unclear. It asks whether the Commission is requiring the reliability coordinator to secure the system to an N-2 state, rather than an N-1 state within the next-day planning analysis. It contends that currently the Reliability Standard is N-1, and requests clarification that the Commission did not intend to mandate an increase in security from N-1 to N-2 in the NOPR.

923. California PUC agrees that there is merit in requiring system operators to assess the outlook for the following day, but nevertheless is concerned with the Commission's proposed directive. Its main concern is that the list of identified control actions can be too long or too generic to be effective to address the myriad potential system contingencies that could arise on the next day.

924. California Cogeneration states that the proposed Reliability Standard allows reliability coordinators to require data on gross load and generation behind the site boundary meter, which is contrary to a prior Commission order. [298]

ii. Commission Determination

925. For the reasons stated in the NOPR, [299] the Commission approves proposed Reliability Standard IRO-004-1 as mandatory and enforceable. In addition, the Commission directs the ERO to develop modifications to the Reliability Standard, as discussed below.

926. We agree with Entergy that system operators must make their decision to use the most effective control action based on the prevailing system conditions, to return the system to a secure state following a contingency. Therefore, the chosen control action may be different than those identified in next-day operations planning. We reiterate that our intent is to require a comprehensive next-day operations planning study that includes identification of effective solutions to aid system operators in real-time operations.

927. We disagree with APPA's comment that day-ahead planning to identify effective control actions would not enhance system reliability because we believe this is also the intent of the ERO for including such a Requirement in this Reliability Standard. [300] Our proposed directive is to augment the Requirement that the plans to alleviate SOL and IROL violations are assessed to ensure that the control actions can be implemented and effective within 30 minutes after a contingency.

928. We agree with APPA that state estimators and real-time contingency analyses using real-time operating conditions produce more accurate study results compared to those from next-day operations planning analyses that are based on day-ahead schedules and forecast conditions. However, we remain convinced that a proactive approach that includes identification of effective operating solutions to deal with contingencies is far superior to a reactive approach that identifies solutions when the system conditions prevail in real-time operations. The former can identify solutions that may not be otherwise available to the system operators—e.g. certain planned generation or transmission outages are approved conditional upon re-affirmation prior to their removal from service or a short recall time subject to certain system conditions developing in real-time operations.

929. We disagree with FirstEnergy that IRO-004-1 should include the day-ahead planning process and reflect activities inherent in a market operation because day-ahead planning includes financial activities that may not occur in real-time. The Commission believes that, for reliability purposes, the simulation should include only what will actually occur.

930. The proposed Reliability Standards IRO-005-1 and TOP-004-0 require that in the event of an IROL violation, i.e. power flow on an interface exceeding its IROL, the system must be returned to a secure state within 30 minutes regardless of the cause of the violation, so that the system is once again capable of withstanding the next contingency without resulting in cascading failures.

931. In response to Northern Indiana, our intent is not to mandate an increase in security from N-1 to N-2, but rather is to ensure there is no reliability gap in the IROL-related Reliability Standards. To do this, the Commission believes it is necessary to provide operators with control actions needed to mitigate an IROL violation while within the 30-minute period after a first contingency. We are not requiring an increase to N-2, which would require planning the system for any two contingencies at all times.

932. With respect to California PUC's comment, we note that it is just as important for day-ahead operation planners to review and derive system operating limits to deal with a myriad of contingencies for different system configurations and generation dispatches, as it is for them to assess the feasibility of returning the system to a secure operating state after these contingencies have occurred. Similar to reviewing and deriving SOLs and IROLs to ascertain that system reliability will be maintained based on the most onerous forecast conditions and critical contingencies, identifying corrective control actions would not encompass each and every contingency and system condition. This is because previous operating experiences and established operating practices would have covered a significant portion of the contingencies and the corresponding control actions already.

933. We further note that for those few IROL contingencies under the forecast and most onerous system conditions, if operation planners equipped with a suite of off-line analytical tools, but without any burden, distraction or interference from real-time operations, cannot identify the effective control actions, it can be argued that it would be unrealistic to expect system operators to do so with an additional requirement—i.e. identification and implementation of an effective control action all within 30 minutes. In addition, the control actions identified in the next-day analysis may quite often provide relevant information to the system operators of the control options they have available.

934. We believe that our use of NERC's definition of bulk electric system in combination with its registration process should assuage California Cogeneration's concerns.

935. In response to APPA's concern that NERC did not provide a Measure for each Requirement, we reiterate that it is in the ERO's discretion whether each Requirement requires a corresponding Measure. The ERO should consider this issue through the Reliability Standards development process.

936. Accordingly, we approve Reliability Standard IRO-004-1 as mandatory and enforceable. Further, we direct the ERO to modify IRO-004-1 through the Reliability Standards development process to require the next-day analysis to identify control actions that can be implemented and effective within 30 minutes after a contingency. The Commission also directs the ERO to consider adding Measures and Levels of Non-Compliance to the Reliability Standard as requested by APPA.

e. Reliability Coordination—Current Day Operations (IRO-005-1)

937. IRO-005-1 ensures energy balance and transmission reliability for the current day by identifying tasks that reliability coordinators must perform throughout the day.

938. In the NOPR, the Commission proposed to approve Reliability Standard IRO-005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification to IRO-005-1 that includes Measures and Levels of Non-Compliance. The Commission proposed that the Measures and Levels of Non-Compliance specific to IROL violations should be commensurate with the magnitude, duration, frequency and causes of the violation. Further, the Commission proposed to direct the ERO to conduct a survey on IROL practices and actual operating experiences, and indicated that it may propose further modifications to IRO-005-1 based on the survey results. [301]

i. Comments

939. FirstEnergy supports the approval of the proposed Reliability Standard as mandatory and enforceable as interpreted by NERC (i.e., that exceeding IROL for less than 30 minutes is not a violation), pending further action through the NERC Reliability Standards development process.

940. MidAmerican supports the Commission's proposed survey and notes that based on its experience, IROL violations have been faithfully reported across NERC.

941. The CAISO urges the Commission to proceed with caution if headed in the direction of absolute compliance with IROL. However, it supports the survey to determine the extent to which systems are actually “drifting” in and out of IROL limits.

942. APPA indicates its support of the Commission's directive to undertake a survey regarding IROL practices and experiences. However it feels that it should be NERC's role to decide on the survey. It contends that, based on the survey results and using the Reliability Standard development process, NERC would decide what modifications to IRO-005-2 are appropriate.

943. Entergy agrees that it is appropriate to use a mitigation plan to resolve an SOL or IROL violation when the actual contingency that causes an SOL or IROL violation is experienced. However, with an acceptable mitigation plan, it is not necessary to require transmission operators to keep facility loading below a level where a potential SOL or IROL violation would occur assuming a low probability of the contingency. Entergy requests clarification that the Commission's guidance is not intended to preclude the use of such alternative procedures. The Commission should be cautious not to restrictively define SOL or IROL in a manner that causes the system operator to take preemptive action through this Reliability Standard to address events that may technically be SOL or IROL violations, but which have a low probability of occurrence and can be mitigated through other proven procedures.

944. ISO-NE agrees that NERC should promptly address the ambiguities in the current definition of an IROL. It has a concern that the phrase “The Transmission Service Provider shall respect these SOLs and IROLs” in Requirement R14 may cause confusion that this entity is expected to respect SOLs and IROLs in the operating time frame. [302]

945. TAPS raises an issue with Requirement R13 that states in part “[i]n instances where there is a difference in derived limits,* * * Load-Serving Entities * * * shall always operate the Bulk Electric System to the most limiting parameter.” TAPS further states that, since LSEs do not operate the system within SOLs or IROLs, the only thing such entities, particularly small ones, can do is shed load. It contends that if the Reliability Standard is mandatory, it should apply only within the parameters proposed by NERC—subject to its Bulk Electric System definition and its June registry criteria. Further, given the apparent error in the Reliability Standard, the Commission should ask NERC to re-examine it.

ii. Commission Determination

946. The Commission approves proposed Reliability Standard IRO-005-1 as mandatory and enforceable. In addition, the Commission directs the ERO to develop modifications to the Reliability Standard through the Reliability Standards development process, as discussed below.

947. The Commission clarifies the intent of and need for the proposed survey. We reiterate that the intent is to learn about the operating experiences and practices of operating entities; specifically, how they operate their systems to respect IROLs in the normal system conditions, i.e. prior to a contingency. The survey results will facilitate future development and modifications of IROL-related Reliability Standards to better clarify and eliminate potential multiple interpretations of respecting IROLs that may exist in the proposed Reliability Standards. [303] In addition, the survey will identify the reliability risks and the frequency and number of operating practices involving drifting in and out of IROL. [304] The survey results will also provide guidance on the frequency, duration and magnitude of IROL violations, their causes and whether these IROL violations occur during normal or contingency conditions.

948. We note the support from FirstEnergy, MidAmerican, CAISO and APPA for our proposed survey. Regarding MidAmerican's comment that reporting on IROL violations is a routine practice, we note that the proposed Reliability Standards only require reporting on those violations that have exceeded IROLs for longer than 30 minutes. The current reporting requirements and results will not provide an adequate assessment of the existing operating practices regarding IROLs and the reliability risks and the extent of drifting in and out of IROLs.

949. In response to Entergy, the Commission believes that operating the system within IROL under normal system condition and exceeding IROL only after a contingency and subsequently returning the system to a secure condition as soon as possible, but no longer than 30 minutes, may be appropriate. This mode of operation will minimize the system risk of being one contingency away from potential cascading failures.

950. ISO-NE asks that the ERO should promptly clarify the current definition for IROL violations. However, we do not share ISO-NE's concern that transmission service providers may be responsible for respecting SOLs and IROLs in real-time operation. Requirement R14 only requires a transmission service provider to use the SOLs and IROLs provided by the reliability coordinator in its tariff, it does not require any action in the operating time frame.

951. We do not share TAPS' concern regarding LSEs initiating load shedding as their own control action to respect IROLs or SOLs. The appropriate control actions to respect IROLs and SOLs are the responsibilities of a reliability coordinator and transmission operator. If load shedding is required, it is the responsibility of a reliability coordinator or a transmission operator to direct the appropriate entities including LSEs to carry it out. However, we urge the ERO to provide further clarification in this regard and include TAPS' concern in developing the modification of this Reliability Standard.

952. Accordingly, the Commission approves Reliability Standard IRO-005-1 as mandatory and enforceable. Further, because IRO-005-1 has no Measures or Levels of Non-Compliance, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to IRO-005-1 through the Reliability Standards development process that includes Measures and Levels of Non-Compliance. The Commission further directs that the Measures and Levels of Non-Compliance specific to IROL violations must be commensurate with the magnitude, duration, frequency and causes of the violations and whether these occur during normal or contingency conditions. Finally, the Commission directs the ERO to conduct a survey on IROL practices and actual operating experiences by requiring reliability coordinators to report any violations of IROL, their causes, the date and time, the durations and magnitudes in which actual operations exceeds IROLs to the ERO on a monthly basis for one year beginning two months after the effective date of the Final Rule. We may propose further modifications to IRO-005-1 based on the survey results.

f. Reliability Coordination—Transmission Loading Relief (IRO-006-3)

953. IRO-006-3 ensures that a reliability coordinator has a coordinated method to alleviate loadings on the transmission system if it becomes congested to avoid limit violations. IRO-006-3 establishes a detailed Transmission Loading Relief (TLR) process for use in the Eastern Interconnection to alleviate loadings on the system by curtailing or changing transactions based on their priorities and according to different levels of TLR procedures. [305] The proposed Reliability Standard includes a regional difference for reporting market flow information to the Interchange Distribution Calculator rather than tagged transaction information for the MISO and PJM areas. It also includes by reference the equivalent Interconnection-wide congestion management methods used in the WECC and ERCOT regions.

954. In the NOPR, the Commission proposed to approve Reliability Standard IRO-006-3 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a modification to IRO-006-3 that: (1) Includes a clear warning that a TLR procedure is an inappropriate and ineffective tool to mitigate IROL violations; (2) identifies in a Requirement the available alternatives to use of the TLR procedure to mitigate an IROL violation and (3) includes Measures and Levels of Non-Compliance that address each Requirement. In addition, the Commission proposed to approve the WECC and ERCOT load relief procedures as superior to the national standard.

i. Comments

955. APPA agrees that IRO-006-3 is sufficient for approval as a mandatory Reliability Standard. It suggests that the ERO should consider development of detailed Measures and Levels of Non-Compliance that address each Requirement in IRO-006-3. Until then, penalties should not be imposed except for egregious violations and the associated penalties should be imposed by the Commission.

956. APPA, Entergy and MidAmerican agree that the TLR procedure is an inappropriate and ineffective tool to mitigate actual IROL violations and that a clear warning to that effect should be included. MidAmerican specifically suggests that the warning must also apply to actual emergency situations in addition to actual IROL violations.

957. Similarly, ISO-NE supports the Commission's conclusions with regard to reliance on TLRs to address actual IROL violations. Further, it supports the Commission's proposal that the ERO should modify the Reliability Standard to provide flexibility for ISOs and RTOs to rely on redispatch as a means to mitigate an IROL violation.

958. Xcel suggests that instead of the proposed modification of a clear warning, it should include a requirement that TLR procedures should not be used for alleviating actual IROL violations. It asserts that the latter approach would be more measurable than the Commission's proposed modification.

959. Entergy and MidAmerican believe that TLR procedures can be an effective mechanism to avoid potential SOL and IROL violations or potential emergency situations.

960. In contrast, Progress Energy disagrees with the Commission's reasoning on the ineffectiveness of using TLR procedures to alleviate actual IROL violations.

ii. Commission Determination

961. The Commission approves IRO-006-3 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to the Reliability Standard as discussed below.

962. The Commission remains convinced, based on Blackout Recommendation No. 31, [306] the submissions from APPA, Entergy, MidAmerican, ISO-NE and Xcel, and NERC's comments on the Staff Preliminary Assessment, [307] that proposed directives to include a clear warning that a TLR procedure is an inappropriate and ineffective tool to mitigate IROL violations and to identify the available alternatives to use of the TLR procedure to mitigate an IROL violation are the appropriate improvements to address the deficiencies in using TLR procedures to mitigate actual IROL violations or actual emergency situations. The Commission endorses Blackout Recommendation No. 31.

963. The Commission agrees with Entergy and MidAmerican that TLR procedures can be an effective mechanism to avoid potential IROL violations and potential emergencies. Regarding this, we reiterate that our concerns have always been on the use of TLR to mitigate actual IROLs or actual emergencies, and not on potential IROLs or emergencies, as indicated in the Blackout Report, Staff Assessment and the NOPR.

964. We do not understand Progress Energy's disagreement because no reason is provided.

965. Accordingly, in addition to approving the Reliability Standard, the Commission directs the ERO to develop a modification to IRO-006-3 through the Reliability Standards development process that (1) includes a clear warning that the TLR procedure is an inappropriate and ineffective tool to mitigate actual IROL violations and (2) identifies in a Requirement the available alternatives to mitigate an IROL violation other than use of the TLR procedure. In developing the required modification, the ERO should consider the suggestions of MidAmerican and Xcel. In addition, the Commission approves the WECC and ERCOT load relief procedures as superior to the national Reliability Standard. As identified in the NOPR, the Commission directs the ERO to modify the WECC and ERCOT procedures to ensure consistency with the standard form of the Reliability Standards including Requirements, Measures and Levels of Non-Compliance. [308]

g. Regional Difference to IRO-006-3: PJM/MISO/SPP Enhanced Congestion Management (Curtailment/Reload/Reallocation)

i. Background

966. As explained in the NOPR, IRO-006-003 provides for a regional difference for MISO, PJM and SPP. [309] According to NERC, the regional difference is needed to allow RTO market practices, simplify transaction information requirements for market participants, and provide reliability coordinators with appropriate information for security analysis and curtailments, reloads, reallocations and redispatch requirements.

967. The regional difference to IRO-006-3 applies the congestion management process included in Joint Operating Agreements filed by MISO, PJM and SPP and specified in seams agreements reached among MISO, PJM, and their neighboring non-market areas during the RTOs' market formation and expansions. Under the congestion management process in the waiver, each RTO calculates an amount of energy (market flow) flowing across coordinated flowgates. These market flows are separated into their appropriate priorities based on the RTO's schedules and reservations and are available for curtailment under the appropriate TLR Levels in the NERC interchange distribution calculator. Under the TLR method for curtailing interchange transactions and in the per generator method for generation-to-load impacts, NERC uses a five percent curtailment threshold, but in the waiver, the RTO's market flows with an impact of greater than zero percent on a coordinated flowgate are represented and made available for curtailment under the appropriate TLR priorities.

968. In their comments on the Staff Preliminary Assessment, MISO-PJM contended that there is unduly discriminatory treatment of the market flows of MISO and PJM versus the generation-to-load impacts of non-market entities because the waiver subjects the RTOs to curtailment (and the corresponding redispatch costs) in circumstances where the non-market entities would not be subject to curtailment.

969. In the NOPR, the Commission did not propose to approve or remand this regional difference.

ii. Comments

(a) Application of the Regional Difference

970. MISO-PJM contends that there is unduly discriminatory treatment against market flows of MISO and PJM during the application of the TLR Standard. The RTOs argue that NERC should modify IRO-006-3 and the MISO and PJM regional difference to require modifying the market flow threshold used by the interchange distribution calculator to assign relief obligations to MISO, PJM, and SPP from zero to a standard percentage that is technically feasible to implement on a non-discriminatory basis, netting of market flow impacts, tag impacts, and generation-to-load impacts, and reporting to the interchange distribution calculator all net generation-to-load impacts for both market and non-market transmission providers. Constellation supports MISO-PJM's argument that there is unduly discriminatory treatment of the MISO and PJM market flows compared to the generation-to-load impacts of non-market entities in the application of the TLR standard.

971. MISO-PJM indicates that they have raised the equity issue with the NERC Operating Reliability Subcommittee (Operating Subcommittee), that their markets currently are being asked to curtail market flow impacts down to zero percent while tagged transactions and generation-to-load impacts during TLR 5 are being asked to curtail impacts that are five percent or greater. MISO-PJM states that the NERC Operating Subcommittee has indicated that they will address reliability issues only and that they are not the appropriate group to address equity issues.

(b) Seams Agreements

972. Several entities argue that the Commission should not overturn the existing IRO-006-3 regional difference. MidAmerican states that MISO and PJM should continue to pursue a negotiated solution to the issues outlined in MISO-PJM's filings. Mid-Continent states that the Commission should reject the MISO-PJM proposal to require NERC to allow them to report only the transactions with five percent or greater impacts on flowgates rather than report all transactions for curtailments, since MISO and PJM offered to report all transactions to avoid negative impacts on the reliability of the transmission system. Mid-Continent argues that not doing so would impact the reliability of the transmission system.

973. Mid-Continent asks the Commission to not implement MISO and PJM's proposal to modify NERC's procedures and to not override seams agreements. MidAmerican claims that MISO-PJM comments amount to an abrogation of existing seams agreements. MidAmerican states that the seams agreements were negotiated in a give-and-take process between the parties resulting in the existing waiver which was proposed by PJM and MISO in response to Commission orders. MidAmerican states that if any changes are sought to these waivers, they should be addressed in negotiation with the appropriate parties. MidAmerican suggests that any changes should be requested by way of the NERC process for developing Reliability Standards and that any negotiated agreements should be presented to the Commission for approval. Mid-Continent claims that MISO-PJM have not provided valid reasons to replace the current Reliability Standards or to take actions that would modify existing seams agreements signed by MISO and PJM. Mid-Continent asks the Commission not to short-circuit the NERC Reliability Standards process which will give full consideration to the reliability implications of MISO's and PJM's proposal.

974. APPA agrees with the Commission's proposed approach in allowing MISO, PJM, NERC and other “relevant entities” to continue their negotiations regarding this regional difference. APPA cautions that any agreement reached by NERC and approved by the Commission regarding a regional difference for this Reliability Standard should be governed by reliability considerations and should not permit market design considerations to override NERC's Reliability Standards. MidAmerican suggests a process where the RTOs invite parties to reconsider the seams agreements, the parties negotiate changes, the Commission approves new agreements and waivers are then sought from NERC to the extent necessary. MidAmerican argues that since the RTOs do not allege any reliability problem there is no need to reject or upend the existing NERC waiver.

(c) Modifying the Congestion Management Process and Alternatives for Temporary Application of the Waiver

975. Mid-Continent states that it agrees with the Commission's proposal to not adopt MISO and PJM's request to instruct NERC to modify the current waiver to the TLR in the RTOs and believes that instead the Commission should direct NERC to address these issues through the Reliability Standards development process with input from neighboring systems. Mid-Continent states that changes to the waiver must not discriminate against non-market regions; must not negatively impact the reliability of neighboring systems and must be consistent with seams agreements signed by the RTOs.

976. NRECA claims that issues associated with market flows and generation-to-load impacts have not been resolved and is concerned that MISO-PJM's suggestion that “consensus” has been reached on the issues is premature. NRECA is also concerned that implementation of the MISO and PJM proposal could increase reliance on TLRs. NRECA urges the Commission to not short circuit or circumvent the Reliability Standards development process or the RTO stakeholders process and states that the Commission should permit the stakeholders to reach full consensus.

977. MISO-PJM indicates that they have been working with both the NERC Operating Subcommittee and the Congestion Management Process Working Group (Congestion Working Group) to achieve a consensus on these changes, and that based on this, the Commission stated in the NOPR that it prefers that MISO, PJM and others continue negotiations to resolve these issues rather than imposing a solution on market participants. MISO-PJM state that they have held extensive discussions with a group composed of NERC Operating Subcommittee and Congestion Working Group participants. MISO-PJM indicates that detailed analyses has been performed to evaluate the effect of changing the market flow threshold from zero percent to five percent in one percent increments and that the NERC Operating Subcommittee has recommended that the market flow threshold used by the interchange distribution calculator to assign relief obligations to the MISO, PJM, and SPP be changed from zero percent to three percent for a 12 month interim period. MISO-PJM assert that at the end of the 12 months, a decision will be made whether to recommend a permanent change to the market flow threshold from zero percent to three percent or a change to some other value. MISO-PJM state that according to the NERC Operating Subcommittee, this recommendation is to only address the reliability issue raised by MISO, PJM and SPP so that they are able to meet their relief assignment during TLR.

978. MISO-PJM also states that to receive congestion management process Council endorsement and support for the change being developed by the NERC Operating Subcommittee group, it requires unanimous approval by the congestion management process Council and that, though the 12 month field test to change the market flow threshold from zero percent to three percent has the support of MISO, PJM, SPP and TVA, it does not have the unanimous approval of all signatories to the seams agreements. MISO-PJM states that MAPPCOR (MAPP) has not agreed to the field test recommended by the NERC Operating Subcommittee and that MAPP has asserted that MISO should continue to honor their contractual obligation and report market flow impacts down to zero percent for relief assignments as specified in the MISO-MAPP Seams Operating Agreement. MISO is concerned that once the field test is complete and the NERC Operating Subcommittee recommends the use of a three percent threshold or some other threshold to address the reliability issue, the MISO may still have a contractual obligation with MAPP to use market flows down to zero percent for relief assignments. MISO-PJM states that this contractual obligation can only be altered if MISO and MAPP can agree on a change to the Seams Operating Agreement but expects resistance to change the Seams Operating Agreement. MISO and PJM do not believe they can address the equity issue by continuing discussions with the NERC Operating Subcommittee.

979. MISO-PJM also state that by continuing to use market flows down to zero percent for relief assignments on reciprocally coordinated flowgates between MISO and MAPP, there will be situations where MISO is unable to meet its relief obligation. MISO-PJM states that they have sought unsuccessfully to execute redispatch agreements with those parties who have direct counter-flow on the identified flowgates where the MISO is unable to meet its relief obligation. MISO-PJM believe that the Commission should address this continuing discriminatory treatment of the market impacts on flowgates. MISO-PJM state that of the three areas where MISO-PJM raised comments on discriminatory treatment of the markets, only one area (changing the market flow threshold for a 12 month field test) has resulted in steps being taken to address the discriminatory treatment and that even this one area can only be considered a partial success because there is only a solution to address the reliability issue, but not the equity issue.

980. MISO-PJM explain in their supplemental comments that NERC has demonstrated a willingness to consider the reliability issue by authorizing a 12 month field test allowing PJM, MISO and SPP market flows to use a three percent threshold, to observe the impact on reliability, but will not address what it refers to as “equity issues.” MISO-PJM explains the field test has been approved by all the reciprocal entities that have signed seams agreements except MAPP. MISO-PJM state that, at the end of the 12 months, a decision will be made whether to use a three percent threshold or some other threshold to address the reliability concerns. MISO-PJM explain that the same entities that make up the Mid-Continent objected to the field test because they asserted MISO has a contractual obligation under the MAPP Seams Operating Agreement to continue reporting its market flows down to zero percent. MISO-PJM contend that because the MISO has agreed to honor its contractual obligation during the field test and will continue to use a zero percent threshold for all flowgates that are reciprocal between MISO and MAPP, this means that the flowgates under the control of the Mid-Continent parties will not participate in the field test and NERC will have no data to show the impact of changing the market flow threshold to three percent on these flowgates.

981. MISO-PJM state that as long as the regional difference does not become a mandatory standard during the field test, they are satisfied that appropriate steps are being taken to address reliability.

(d) Reporting of Generator to Load Impacts by Non Market Areas

982. MISO-PJM supports modifications to the TLR process that would require all participants (both market and non-market) to report their market flow impacts and generator-to-load impacts to the interchange distribution calculator and honor their allocations when they report their firm versus their non-firm usage. MISO-PJM believes that taking this step would also address the threshold equity issue and the netting issue because all entities would be subject to the same treatment. MISO-PJM requests that the Commission to either direct NERC to initiate a process to modify the interchange distribution calculator such that market flows and generator-to-load impacts from non-market areas are both reported to the interchange distribution calculator and are subject to curtailment based on their priorities from the allocations or that the Commission take action to do so.

983. MISO-PJM states that the reporting of generator-to-load impacts by the non-market entities is the one area that is not currently under discussion with a stakeholder group. MISO-PJM explains that both the market and non-market entities receive an allocation on flowgates and that both the market entities and the non-market entities use the allocations when selling firm transmission service. MISO-PJM states that only the market entities report their market flows to the interchange distribution calculator and use their allocations to determine what portion of market flows will be considered firm and believe that the non-market entities could also report their firm and non-firm generator-to-load usage to the interchange distribution calculator and receive relief assignments based on this usage. MISO-PJM indicates that this would remove the assumption that all generator-to-load impacts from the non-market entities represent firm usage. MISO-PJM states that reporting relief obligations by one group of participants and not reporting by the other results in conflicting actions during the TLR process because market entities suffer the financial consequences of redispatch at the same time reliability is not being accomplished due to off-setting actions by non-market entities.

984. MISO-PJM states that, to address the discriminatory treatment of the markets, the Commission could order the TLR Reliability Standard to be modified to have the market entities discontinue reporting their market flows to the interchange distribution calculator. MISO-PJM believes that instead of this order, the preference is to have the market entities continue reporting their market flow impacts and the non-market entities report their generator-to-load impacts to the interchange distribution calculator. The allocations would be used to set the priority of these impacts.

985. Mid-Continent states that the regional difference requiring PJM and MISO to report all flows instead of net flows was part of the commitments MISO and PJM made to meet NERC's tagging requirements. Mid-Continent contends that it is appropriate to treat MISO-PJM market flows differently because they are greater than the system flows that resulted from control area-based system operation. Mid-Continent further claims that MISO cannot achieve the redispatch the interchange distribution calculator requires because of MISO's own actions since MISO does not report actual flows to the interchange distribution calculator and MISO and PJM's congestion management tools do not utilize all redispatch options.

(e) Accounting for Counter Flows During TLR

986. MISO-PJM state that there have been discussions at the NERC Operating Subcommittee about taking into account counter-flows during TLR when assigning relief. MISO-PJM contends that by considering counter-flows, those entities that are responsible for the loading problem on a net basis will be responsible for fixing the loading problem during TLR. MISO-PJM states that the MISO, PJM and SPP markets operate on a net flow basis and, therefore, have additional reasons for wanting to consider counter-flows. MISO-PJM expects that by summer 2007, the Task Force will have a recommendation on netting in the interchange distribution calculator for the NERC Operating Subcommittee to consider. MISO-PJM state that it is premature to speculate on the outcome of the discussions with the NERC Operating Subcommittee at this time. MISO-PJM clarifies that they are not asking the Commission to take any action on this issue but to let the NERC Operating Subcommittee address the technical merits of netting impacts in the interchange distribution calculator.

987. Mid-Continent states that eliminating the requirements to report flows in both directions may adversely impact reliability because the interchange distribution calculator will not have enough information to assign responsibilities to the contributors of a constraint.

iii. Commission Determination

988. The Commission will not approve or remand this regional difference. The treatment of the market flows of MISO-PJM versus the generation-to-load impacts of non-market entities in the application of the TLR standard has been addressed by the Commission in a number of cases. [310] In approving the plans of various transmission owning utilities to join PJM, the Commission attached several conditions including a requirement that certain non-market utilities be held harmless from effects of loop flow and congestion resulting from the utilities' RTO choices. [311] Further, during MISO's market start up, [312] the Commission determined that the markets could not start without the MISO having at least a specific, transparent plan for how it will handle the interface of multiple transmission tariffs and market-to-non-market seams [313] and required the MISO to file any resolution of seams, or a status report of progress on seams resolution including detailed plans as to how MISO will address seams absent agreements, within 60 days of the date of the order. The regional difference to IRO-006-3 applies the congestion management process that was included in the Joint Operating Agreement filed by MISO, PJM and SPP and that was specified in the seams agreements reached between MISO, PJM, and their neighboring non-market areas in order to meet the Commission's requirements described above. [314]

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

990. The Commission concludes that the issues described by MISO-PJM (i.e., defining the obligation of a certain region to provide redispatch when a flowgate becomes congested) are best handled through seams agreements rather than being subject to the NERC processes. We recognize that the two areas of seams agreements and Reliability Standards could overlap if the agreements reached do not allow for reliable outcomes where parties can achieve the relief assigned. As such, the Commission will neither approve nor remand the waiver of the regional difference to IRO-006-3 while the 12-month field test allowing PJM, MISO and SPP market flows to use a three percent threshold is being conducted. After the 12-month field test is complete, the Commission will reexamine approving the waiver as a mandatory and enforceable Reliability Standard.

991. The Commission instructs the RTOs to continue working with the non-market regions to develop revised seams agreements that allow for equitable and feasible treatment of market flows in the NERC TLR/redispatch process. The solution should not harm system reliability and should not subject either non-RTO transmission owners or the RTO markets to unreasonable redispatch responsibilities. We note that if consensus cannot be reached, the RTOs may file a section 205 or section 206 proposal to revise the terms and conditions of the congestion management process if the terms agreed on in the seams agreements and Joint Operating Agreement have become unjust or unreasonable or may file to terminate the agreements as allowed in the seams agreements.

992. The Commission will not adopt MISO-PJM's proposal to require non-market entities to report their generator-to-load impacts to the interchange distribution calculator with the allocations used to set the priority of these impacts in this Reliability Standards process. If NERC determines that this information and corresponding curtailment options are needed for reliability, NERC should file to modify IRO-006-3 to include these additions. However, the economic implications of the reporting of generator-to-load impacts by non-market entities are not in the scope of the reliability process and are better addressed on a case-by-case basis or, as appropriate, in the proceeding on RTO Border Utility Issues. [315]

993. In addressing MISO-PJM's claim that the ERO should modify IRO-006-3 and the MISO-PJM regional difference to require netting generation-to-load impacts to recognize counterflow, we will let the ERO Operating Subcommittee address the technical merits of netting flow impacts in the interchange distribution calculator.

h. Procedures, Processes, or Plans To Support Coordination Between Reliability Coordinators (IRO-014-1)

994. The stated purpose of IRO-014-1 is to ensure that each reliability coordinator's operations are coordinated so that they will not have an adverse reliability impact on other reliability coordinator areas and to preserve the reliability benefits of interconnected operation. Specifically, IRO-014-1 ensures energy balance and transmission by requiring a reliability coordinator to have operating procedures, processes or plans for the exchange of operating information and coordination of operating plans.

995. In the NOPR, the Commission proposed to approve IRO-014-1 as mandatory and enforceable.

i. Comments

996. APPA agrees with the Commission's proposed approval of IRO-014-1 as mandatory and enforceable.

ii. Commission Determination

997. For the reasons stated in the NOPR, the Commission approves IRO-014-1 as mandatory and enforceable.

i. Notifications and Information Exchange Between Reliability Coordinators (IRO-015-1)

998. IRO-015-1 establishes Requirements for a reliability coordinator to share and exchange reliability-related information among its neighbors and participate in agreed-upon conference calls and other communication forums with adjacent reliability coordinators.

999. In the NOPR, the Commission proposed to approve IRO-015-1 as mandatory and enforceable.

i. Comments

1000. APPA agrees with the Commission's proposed approval of IRO-015-1 as mandatory and enforceable.

ii. Commission Determination

1001. For the reasons stated in the NOPR, the Commission approves IRO-015-1 as mandatory and enforceable.

j. Coordination of Real-Time Activities Between Reliability Coordinators (IRO-016-1)

1002. IRO-016-1 establishes Requirements for coordinated real-time operations, including: (1) Notification of problems to neighboring reliability coordinators and (2) discussions and decisions for agreed-upon solutions for implementation. It also requires a reliability coordinator to maintain records of its actions.

1003. In the NOPR, the Commission proposed to approve IRO-016-1 as mandatory and enforceable.

i. Comments

1004. APPA agrees with the Commission's proposed approval of IRO-015-1 as mandatory and enforceable. However, it indicates that it is unclear in Level of Non-Compliance 2.1, how a reliability coordinator can demonstrate that it coordinated with other reliability coordinators without having retained evidence such as detailed logs or telephone recordings of having done so. [316]

ii. Commission Determination

1005. For the reasons stated in the NOPR, the Commission approves IRO-016-1 as mandatory and enforceable.

1006. We construe Level of Non-Compliance 2.1 as requiring evidence of coordination, but allowing flexibility on the type of evidence.

8. MOD: Modeling, Data, and Analysis

1007. The Modeling, Data and Analysis group of Reliability Standards is intended to standardize methodologies and system data needed for traditional transmission system operation and expansion planning, reliability assessment and the calculation of available transfer capability (ATC) in an open access environment. The 23 MOD Reliability Standards may be grouped into four distinct categories. The first category covers methodology and associated documentation, review and validation of Total Transfer Capability (TTC), ATC, Capacity Benefit Margin (CBM) and Transmission Reliability Margin (TRM) calculations. [317] The second category covers steady-state and dynamics data and models. [318] The third category covers actual and forecast demand data. [319] The fourth category covers verification of generator real and reactive power capability. [320]

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

i. Comments

1009. ISO/RTO Council and ISO-NE agree with the Commission's proposal to neither approve nor remand the 13 MOD Reliability Standards until NERC supplies additional information. ISO/RTO Council and ISO-NE also recommend that the Commission go further and defer its approval of the MOD Reliability Standards that incorporate references to the 13 fill-in-the-blank Reliability Standards until those 13 are approved unconditionally. ISO/RTO Council and ISO-NE believe that the following Reliability Standards are dependent upon the 13 fill-in-the-blank standards: MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, MOD-018-0, MOD-019-0, and MOD-021-0 and as such, the Commission should not approve and make them enforceable at this time. ISO-NE warns that these listed standards share the same infirmities as the 13 the Commission found it could not yet approve. ISO-NE cautions that until the missing information is provided in the 13 cross-referenced standards, it will be impossible for the affected entities to determine what criteria they are expected to satisfy.

1010. EPSA, in contrast to ISO/RTO Council and ISO-NE, expresses its concern with the Commission's proposal not to act on the 13 fill-in-the-blank standards. EPSA considers the fill-in-the-blank standards vitally important to reliability and competitive markets and worries that progress may be lost while the regions endeavor to file the additional required information.

ii. Commission Determination

1011. The Commission will adopt the NOPR proposal and retain the same disposition of the MOD Reliability Standards that it proposed there. We confirm in this Final Rule that one out of 23 MOD standards is approved unconditionally, nine are approved with direction for modification and 13 remain pending with direction for modification. We will discuss our rationale for this decision in the Commission Determination section for each particular Reliability Standard.

1012. We reject ISO/RTO Council and ISO-NE's request that we defer our approval of Reliability Standards from the MOD group that incorporate references to the 13 fill-in-the-blank standards. While we understand ISO/RTO Council and ISO-NE's concern about cross-referencing pending Reliability Standards, the data that is needed will be provided as described in the Common Issues section. [322] In the interim, compliance with the pending Reliability Standards should continue on a voluntary basis, and the Commission considers compliance with them a matter of good utility practice. The Commission believes, moreover, that the blanks will be filled in in a timely manner, since in this rule we require the ERO to develop a Work Plan and submit a compliance filing describing the process for collection of the information set forth in the deferred standards.

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

b. MOD Standards Related to ATC, TTC, CBM and TRM

i. OATT Reform and the MOD Standards

1014. As pointed out in the NOPR, the Commission has been considering ATC, TTC, CBM and TRM calculation issues in Docket Nos. RM05-17-000 and RM05-25-000, and addressed them in Order No. 890. In order to maintain a consistent approach with regard to ATC issues, we confirm here the determinations made in Order No. 890. Each such determination is addressed below.

1015. In Order No. 890, the Commission addressed the potential for undue discrimination by requiring industry-wide consistency and transparency of all components of ATC calculation methodology and certain definitions, data and modeling assumptions. The Commission also indicated there that the lack of consistent, industry-wide ATC calculation standards poses a threat to the reliable operation of the Bulk-Power System, particularly with respect to the inability of one transmission provider to know with certainty its neighbors' system conditions affecting its own ATC values. As a result of this reliability component, the Commission asserted that the proposed ATC reforms are also supported by FPA section 215, through which the Commission has the authority to direct the ERO to submit a Reliability Standard that the Commission considers appropriate to implement FPA section 215. [324]

1016. In Order No. 890, the Commission directed public utilities, working through NERC and NAESB, to develop Reliability Standards and business practices to improve the consistency and transparency of ATC calculations. The Commission required public utilities, working through NERC, to modify the ATC-related Reliability Standards within 270 days of publication of Order No. 890 in the Federal Register. The Commission also directed public utilities to work through NAESB to develop business practices that complement NERC's new Reliability Standards within 360 days of publication of Order No. 890 in the Federal Register. Finally, the Commission directed NERC and NAESB to file a joint status report on standards and business practices development, and a Work Plan for completion of this task, within 90 days of publication of Order No. 890 in the Federal Register.

1017. The electric utility industry has also acknowledged this problem and has taken steps to address the lack of consistency and transparency in the way ATC is calculated. NERC formed a Long-Term Available Flowgate Capacity Task Force to review NERC's standards on ATC, which issued a final report in 2005. [325] Based on the recommendations in the NERC Report, NERC has begun two Standards Authorization Request proceedings to revise the standards on ATC. [326] NAESB has also begun a proceeding to develop business practice standards to enhance the processing of transmission service requests that affect ATC calculation. Following the issuance of the OATT Reform NOPR on May 19, 2006, and the Reliability Standards NOPR on October 19, 2006, NERC accelerated development of these standards in accordance with the guidelines provided in these NOPRs. NERC and NAESB representatives participated in the Commission's Technical Conference held on October 12, 2006, and informed the Commission on the status of Reliability Standards development. [327] NERC posted the Draft Standard MOD-001-1, proposing ATC/TTC/AFC (Available Flowgate Capability) revisions, on its Web site on February 15, 2007. [328]

(a) Comments

1018. EPSA commends the Commission for recognizing the direct connection between the MOD group of Reliability Standards and the initiative to reform Order No. 888 to address existing opportunities to discriminate against competitive power suppliers in access to the transmission system. TAPS and EPSA note that in both the OATT Reform NOPR and the Reliability Standards NOPR, the Commission has articulated serious concerns about the lack of clarity, transparency and uniformity in the critical calculations pertaining to one of the most fundamental aspects of the wholesale bulk power transmission system, and urge the Commission to make these calculations transparent, consistent, and better yet, regional. TAPS agrees with Staff's concerns raised in the NOPR about ATC, TTC, CBM and TRM standards. Constellation particularly supports the proposed changes to MOD-001-0, MOD-004-0, MOD-006-0 and MOD-007-0 because these Reliability Standards, as modified, will provide more information to users regarding ATC, TTC, existing transmission commitments (ETC), AFC, CBM and TRM, and that information will begin the process of providing consistent standards for their calculation.

1019. Constellation agrees with EPSA and cautions that it will take time for NERC to develop, and for the Commission to definitively approve, ATC-related standards. Constellation therefore proposes that the Commission should, upon issuance of a Final Rule, require transmission providers to post the information that the Commission directs regarding these values, even if work toward more consistency is not yet complete. Constellation believes that this will aid in ensuring that users request and receive more reliable transmission service on a nondiscriminatory basis.

1020. Contrary to the majority of commenters that support Commission action regarding ATC issues, MISO states that a Reliability Standard is not the place to address perceived comparability issues. MISO states that NERC is responsible for Reliability Standards, but not for tariffs and business practices that deal with market and equity issues.

(b) Commission Determination

1021. We agree with the many commenters that recognize the direct connection between the MOD group of Reliability Standards and available transfer capability methodologies addressed in Order No. 890, in which we developed policies to lessen, if not fully eliminate, opportunities to discriminate against competitive power suppliers in access to the transmission system.

1022. We recognize the concerns raised by EPSA and Constellation that opportunities for discrimination and related reliability concerns may remain during the interim Reliability Standards modification process, in part because of the discretion that transmission service providers will retain in calculating ATC values. We point out, however, that all transmission providers are required to file a modified Attachment C to their OATTs detailing their ATC calculation methodologies in advance of the development of the new Reliability Standards. All transmission providers are required to comply with their OATTs, and are subject to the filing of a complaint or Commission-initiated enforcement action if discrimination occurs. Regarding Constellation's recommendation that the Commission act in advance, and require transmission service providers to post the information that the Commission directs regarding ATC values, even if work toward more consistency is not yet complete, we clarify that we will require transmission service providers to comply with existing ATC-related posting obligations on OASIS as supplemented by Order No. 890. These requirements are not subject to standardization by the ERO, and will be effective in accordance with the timeline stated in Order No. 890.

1023. We disagree with MISO's contention that the Reliability Standards are an inappropriate venue for addressing ATC comparability issues. ATC raises both comparability and reliability issues, and it would be irresponsible to take action under FPA section 206 to require consistency in ATC calculations without considering the reliability impact of those decisions. Therefore, the Commission in Order No. 890 provided direction to public utilities, working through NERC and NAESB, regarding development of the ATC-related Reliability Standards and business practices, and we repeat that direction here.

c. Documentation of Total Transfer Capability and Available Transfer Capability Calculation Methodologies (MOD-001-0)

1024. The purpose of MOD-001-0 is to promote the consistent and uniform application of transfer capability calculations among transmission system users. The Reliability Standard requires each regional reliability organization to develop a regional TTC and ATC methodology in conjunction with its members and to post the most recent version of its TTC and ATC methodologies on a Web site accessible by NERC, the regional reliability organization, and transmission users.

1025. In the NOPR, the Commission identified MOD-001-0 as a fill-in-the- blank standard that requires each regional reliability organization to develop its respective methods for determining TTC and ATC and to make those methodologies available to others for review. The NOPR stated that the Commission would not propose to approve or remand MOD-001-0 until the ERO submits additional information.

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

i. Comments

1027. APPA agrees with the Commission that MOD-001-0 in its current form is a fill-in-the-blank standard, is not sufficient in its current form and should not be accepted for approval as a mandatory Reliability Standard until the accompanying regional procedures are submitted and approved.

ii. Commission Determination

1028. The Commission adopts the NOPR proposal not to approve or remand MOD-001-0 until the ERO submits additional information. Consistent with Order No. 890, and comments received in response to the NOPR, the Commission directs the ERO to consider modifications of MOD-001-0 through the Reliability Standards development process as discussed below.

iii. Provide a Framework for ATC, TTC and ETC Calculation

(a) Comments

1029. APPA supports the Commission's proposal that NERC modify MOD-001-0 to, at a minimum, provide a framework for ATC, TTC and ETC calculation.

(b) Commission Determination

1030. We continue to believe that MOD-001-0 should, at a minimum, provide a framework for ATC, TTC and ETC calculations. This framework should consider industry-wide consistency of all ATC components and certain data inputs and exchange, modeling assumptions, calculation frequency, and coordination of data relevant for the calculation of ATC. Consistent with Order No. 890, we do not require a single computational process for calculating ATC for several reasons. First, it is not our intent to require transmission providers to incur the expense of developing and adopting a new one-size-fits-all software package to calculate ATC without proven benefits. More importantly, we find that the potential for discrimination and decline in reliability level does not lie primarily in the choice of an ATC calculation methodology, but rather in the consistent application of its components, and input and exchange data, along with modeling assumptions. Consistent and transparent ATC calculation will provide equivalent results between regions and will therefore prevent transmission service providers from overselling transfer capability that can stress conditions on their own and adjacent systems, and jeopardize reliability. In addition, we are especially concerned with the lack of data exchange between neighboring transmission service providers, which is a prerequisite for accurate calculation of ATC.

1031. The Commission understands that the ERO currently is developing three ATC calculation methodologies (contract or rating path ATC, network ATC, and networkAFC). [331] If all of the ATC components, and certain data inputs and assumptions are consistent, the three ATC calculation methodologies will produce predictable and sufficiently accurate, consistent, equivalent and replicable results. It is therefore not necessary to require a single industry-wide ATC calculation methodology.

1032. In addition, consistent with Order No. 890, we note that there is neither a definition of AFC/TFC (Total Flowgate Capability) in the ERO's glossary nor an existing Reliability Standard that discusses AFC. Consistent with our approach to achieving consistency and transparency, we direct the ERO to develop AFC/TFC definitions and requirements used to identify a particular set of transmission facilities as flowgates. We extend the same requirements for industry-wide consistency of all AFC components and certain data inputs and exchange, modeling assumptions, calculation frequency, and coordination of data relevant for the calculation of AFC as we stated above for ATC. However, we remind transmission providers that our regulations require the posting of ATC values associated with a particular path, not AFC values associated with a flowgate. Accordingly, transmission providers using an AFC methodology must convert flowgate (AFC) values into path (ATC) values for OASIS posting. In order to display consistent posting of ATC and TTC values on OASIS, we direct the ERO to develop a Requirement in the Reliability Standard for conversion of AFC into ATC values for use by transmission providers that currently apply flowgate methodology.

1033. We underscore Order No. 890's objective of greater consistency in ETC calculations. The Commission directs the ERO to develop a consistent approach for determining the amount of transfer capability a transmission provider may set aside for its native load and other committed uses. We expect that the ERO will address ETC through the MOD-001-0 Reliability Standard rather than through a separate Reliability Standard. By using MOD-001-0, the ETC calculation principles can be adjusted to apply to each of the three ATC methodologies being developed by the ERO. In order to provide specific direction to public utilities and the ERO, we determine that ETC should be defined to include committed uses of the transmission system, including: (1) Native load commitments (including network service); (2) grandfathered transmission rights; (3) firm and non-firm point-to-point reservations; (4) rollover rights associated with long-term firm service and (5) other uses identified through the ERO process. ETC should not be used to set aside transfer capability for any type of planning or contingency reserve; these are to be addressed through CBM and TRM. [332] In addition, in the short-term ATC calculation, all reserved but unused transfer capability (non-scheduled) must be released as non-firm ATC.

1034. We reiterate the finding in Order No. 890 that including all requests for transmission service in ETC is likely to overstate usage of the system and understate ATC. Accordingly, we find that reservations that have the same point of receipt (POR) (generator) but different point of delivery (POD) (load), for the same time frame, should not be modeled in the ETC calculation simultaneously if their combined reserved transmission capacity exceeds the generator's nameplate capacity at a POR. This will prevent unrealistic use of transmission capacity associated with power output from a generator identified as a POR. One approach that could be used is examining historical patterns of actual reservation use during a particular season, month, or time of day.

1035. In summary, we direct the ERO to modify MOD-001-0 to provide a framework for ATC, TTC and ETC calculation that, consistent with the discussion above: (1) Requires industry-wide consistency of all ATC components and certain data inputs and exchange, modeling assumptions, calculation frequency, and coordination of data relevant for the calculation of ATC; (2) provides predictable and sufficiently accurate, consistent, equivalent, and replicable ATC calculations regardless of the methodology used by the region; (3) provides the definition of AFC and method for its conversion to ATC; (4) lays out clear instructions on how ETC should be defined and (5) identifies to whom MOD-001-0 Reliability Standards apply, i.e., users, owners and operators of the Bulk-Power System.

iv. Require Disclosure of Algorithms and Processes Used in ATC Calculation

(a) Comments

1036. APPA supports the Commission's proposal that NERC modify MOD-001-0 to require documentation including mathematical algorithms, process flow diagrams, data inputs and identification of flowgates.

(b) Commission Determination

1037. The Commission adopts the proposal from the NOPR to direct the ERO to modify Reliability Standard MOD-001-0 to require disclosure of the algorithms and processes used in ATC calculation. In addition, consistent with Order No. 890, the Commission believes that further clarification is necessary regarding the ATC calculation algorithm for firm and non-firm ATC. [333] Currently, the ERO has no specifications for calculating non-firm ATC. We find that the same potential for discrimination exists for non-firm transmission service as for firm service, and greater uniformity in both firm and non-firm ATC calculations will substantially reduce the remaining potential for undue discrimination. Therefore, we direct the ERO to modify Reliability Standard MOD-001-0 to require disclosure of the algorithms and processes used in ATC calculation, and also to implement the following principles for firm and non-firm ATC calculations: (1) For firm ATC calculations, the transmission provider shall account only for firm commitments and (2) for non-firm ATC calculations, the transmission provider shall account for both firm and non-firm commitments, postbacks of redirected service, unscheduled service and counterflows.

v. Identify a Detailed List of Information To Be Exchanged Among Transmission Providers for the Purposes of ATC Modeling

(a) Comments

1038. APPA supports the Commission's proposal that NERC modify MOD-001-0 to require applicable entities to identify a detailed list of information to be shared.

(b) Commission Determination

1039. The Commission adopts the NOPR proposal and reiterates the requirement in Order No. 890 that the ERO must revise the MOD Reliability Standards to require the exchange of data and coordination among transmission providers. We direct the ERO to modify MOD-001-0 to ensure that the following data, at a minimum, be exchanged among transmission providers for the purposes of ATC modeling: (1) Load levels; (2) transmission planned and contingency outages; (3) generation planned and contingency outages; (4) base generation dispatch; (5) existing transmission reservations, including counterflows; (6) ATC recalculation frequency and times and (7) source/sink modeling identification. [334] The Commission concludes that the exchange of such data is necessary to support the reforms requiring consistency in the determination of ATC adopted in this Final Rule. As explained above, transmission providers are required to coordinate the calculation of TTC/TFC and ATC/AFC with others, and this requires a standard means of exchanging data.

vi. Include Requirements That the Assumptions Used in ATC and AFC Calculations Should Be Consistent, to the Maximum Extent Practicable, With Those Used for Planning the Expansion or Operation of the Bulk-Power System

(a) Commission Determination

1040. The Commission adopts the NOPR's proposal to require transmission providers to use data and modeling assumptions for short- and long-term ATC calculations that are consistent with those used for the planning of operations and system expansion, to the maximum extent practicable. This includes, for example: (1) Load levels; (2) generation dispatch; (3) transmission and generation facilities maintenance schedules; (4) contingency outages; (5) topology; (6) transmission reservations; (7) assumptions regarding transmission and generation facility additions and retirements and (8) counterflows, which must be the same in the models used in the transmission operational and planning studies performed for the transmission providers' native load. We find that requiring consistency in the data and modeling assumptions used for ATC calculation will remedy the potential for undue discrimination by eliminating discretion and ensuring comparability in the manner in which a transmission provider operates and plans its system to serve native load, and the manner in which it calculates ATC for service to third parties.

1041. We clarify that we require consistent use of assumptions underlying operational planning for short-term ATC and expansion planning for long-term ATC calculation. We also clarify that there must be a consistent basis for or approach to determining load levels in each of these sets of calculations. For example, one approach may be for transmission providers to calculate load levels using an on- and off-peak model for each month when evaluating yearly service requests and calculating yearly ATC. The same (peak- and off-peak) or alternative approaches may be used for monthly, weekly, daily and hourly ATC calculations. Regardless of the ultimate choice, it is imperative that all transmission providers use the same approach to modeling load levels to eliminate undue discrimination and enable the meaningful exchange of data among transmission providers. Accordingly, we direct the ERO to develop consistent requirements for modeling load levels in MOD-001-0.

1042. With respect to modeling of generation dispatch, we direct the ERO to develop requirements in MOD-001-0 specifying how transmission providers should determine which generators should be modeled in service, including guidance on how independent generation should be considered. Accordingly, we direct the ERO to revise Reliability Standard MOD-001-0 by specifying that base generation dispatch will model: (1) All designated network resources and other resources that are committed to or have the legal obligation to run, as they are expected to run and (2) all uncommitted resources that are deliverable within the control area, economically dispatched as necessary to meet balancing requirements.

1043. Regarding transmission reservations modeling, we direct the ERO to develop requirements in Reliability Standard MOD-001-0 that specify: (1) A consistent approach on how to simulate reservations from points of receipt to points of delivery when sources and sinks are unknown and (2) how to model existing reservations.

1044. Consistent with Order No. 890, the Commission directs the ERO to modify Reliability Standard MOD-001-0 to require ATC to be updated by all transmission providers on a consistent time interval and in a manner that closely reflects the actual topology of the system, e.g., generation and transmission outages, load forecasts, interchange schedules, transmission reservations, facility ratings and other necessary data. This process must also consider whether ATC should be calculated more frequently for constrained facilities.

1045. In conclusion, we direct the ERO to modify MOD-001-0 to require that: (1) Assumptions used for short-term ATC calculations be consistent with those used for operation planning to the maximum extent practicable; (2) assumptions used for long-term ATC calculations be consistent with those used for system planning to the maximum extent practicable and (3) ATC be updated by all transmission providers on a consistent time interval.

vii. Include a Requirement That Applicable Entities Make Available Assumptions and Contingencies Underlying ATC and TTC Calculations

(a) Comments

1046. APPA supports the Commission's proposal that NERC modify MOD-001-0 to include a requirement that applicable entities make available a comprehensive list of assumptions and contingencies underlying ATC and TTC calculations.

(b) Commission Determination

1047. We adopt the NOPR's proposal that this Reliability Standard should include a requirement that applicable entities make available a comprehensive list of assumptions and contingencies underlying ATC/AFC and TTC/TFC calculations. While we require the submission of contingency files under MOD-010-0, here we only direct the ERO to consider development of a requirement that the transmission service provider declare what type of contingencies it uses for specific calculations of ATC/AFC and TTC/TFC, and release the contingency files upon request if not submitted with the data filed with the ERO in compliance with MOD-010-0.

1048. In order to increase the transparency of ATC calculations, we adopt the NOPR's proposal and direct the ERO to develop in MOD-001-0 a requirement that each transmission service provider provide on OASIS its OATT Attachment C, in which Order No. 890 requires transmission providers to include a detailed description of the specific mathematical algorithm the transmission provider uses to calculate both firm and non-firm ATC for various time frames such as: (1) The scheduling horizon (same day and real-time), (2) operating horizon (day ahead and pre-schedule) and (3) planning horizon (beyond the operating horizon). In addition, a transmission provider must include a process flow diagram that describes the various steps that it takes in performing the ATC calculation.

viii. Address Only ATC While TTC Should Be Addressed UnderFAC-012-1

(a) Comments

1049. APPA concurs with the NOPR's proposal that TTC should be standardized under FAC-012-1, and that there appears to be little or no distinction between the definitions for TTC (MOD-001-0) and TC (FAC-012-1). APPA anticipates that this distinction will either be clarified or eliminated through ongoing Reliability Standards development activity.

1050. Conversely, MidAmerican notes that the transfer capability covered by FAC-012-1 may not relate to the TTC that is the subject of the MOD-001-0 standard. MidAmerican opines that the purpose of the FAC-012-1 standard is to ensure that each reliability coordinator and planning authority documents the methodology used to develop inter- and intra-regional transfer capabilities used in the reliable planning and operation of the Bulk-Electric System. MidAmerican further details that transfer capabilities that are covered by FAC-012-1 could be used by a reliability coordinator to operate the system in a temporary situation or by the planning authority as the basis for a sensitivity case. It adds that in neither of these cases would these transfer capabilities necessarily be included in calculations for ATC that would be used for offering transmission capacity for sale.

(b) Commission Determination

1051. We adopt the NOPR proposal and require that TTC be addressed under the Reliability Standard that deals with transfer capability such as FAC-012-1, rather than MOD-001-0. The FAC series of standards contain the Reliability Standards that form the technical and procedural basis for calculating transfer capabilities. FAC-008-1 provides the basis for determining the thermal ratings of facilities while FAC-009-1 provides the basis for communicating those ratings. FAC-010-1 and FAC-011-1 provide the system operating limits methodologies for the planning and operational horizon respectively and FAC-014 provides for the communication of those ratings. [335]

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

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

ix. Identify the Entities To Whom the MOD Standards Apply

(a) Comments

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

1055. In addition, APPA states that under the statutory framework established in FPA section 215, as interpreted by the Commission in Order No. 672, it is clear that the compliance monitor within each region is the Regional Entity, and the Regional Entity is not a user, owner or operator of the Bulk-Power System. APPA notes that while regional delegation agreements may be used to impose certain reliability compliance functions upon Regional Entities and their affiliates, no Regional Entity should be charged with enforcing compliance against itself. Ultimately, APPA is concerned that the quality of regional modeling and technical assessments will be diminished if the collaborative efforts used for the past 50 years of interconnected operations are displaced due to pressures to identify a single entity or class of entities with direct compliance responsibilities for regional modeling standards. APPA states that identifying all users, owners and operators as responsible entities does not answer the question either. APPA expresses its intention that it will work with NERC and with other stakeholders to ensure that this industry-based expertise is maintained and enhanced, while ensuring that responsible entities are identified in this and other NERC standards.

(b) Commission Determination

1056. APPA is suggesting that respective regional organizations, their technical staff, and committees of users, owners and operators of the Bulk-Power System be charged with developing the methodologies. We disagree. These Reliability Standards should be developed through the Commission-approved Reliability Standards development process which will identify the entities that should implement the Reliability Standards, the Requirements necessary to achieve the goals identified in Order No. 890, and the Measures necessary to monitor compliance.

1057. The Commission agrees with APPA that the collaborative efforts and knowledge developed over decades of interconnected operation should not be wasted. We do not believe that will happen through the Reliability Standards development process and that all of the applicable entities will have significant roles to play in achieving the goal the Commission has set out in Order No. 890. Therefore, we adopt the proposal in the NOPR and direct the ERO to modify MOD-001-0 to reflect the users, owners and operators to which the Reliability Standard will apply.

x. Summary of Commission Determination

1058. Accordingly, the Commission neither accepts nor remands MOD-001-0 until the ERO submits additional information. Although the Commission does not propose any action with regard to MOD-001-0, we address above a number of concerns regarding the Reliability Standard, consistent with those set forth in Order No. 890. We direct the ERO to develop modifications to the Reliability Standard through the Reliability Standards development process that: (1) Provide a framework for ATC, TTC and ETC calculation, developing industry-wide consistency of all ATC components; (2) require disclosure of algorithms, for both firm and non-firm ATC and processes used in the ATC calculation; (3) identify a detailed list of information to be exchanged among transmission providers for the purposes of ATC modeling; (4) include a requirement that the assumptions used in ATC and AFC calculations should be consistent with those used for planning the expansion or operation of the Bulk-Power System to the maximum extent practicable; (5) include a requirement that ATC be updated by all transmission providers on a consistent time interval; (6) include a requirement that applicable entities make available assumptions and contingencies underlying ATC and TTC calculations; (7) address only ATC/AFC while TTC/TFC should be addressed under transfer capability standards such as FAC-012-1 and (8) identify the applicable entities in terms of users, owners and operators of the Bulk-Power System.

d. Review of Transmission Service Provider Total Transfer Capability and Available Transfer Capability Calculations and Results (MOD-002-0)

1059. MOD-002-0 concerns the review of transmission service providers' compliance with the regional methodologies for calculating TTC and ATC. It requires that the regional reliability organization: (1) Develop and implement a procedure to periodically review and ensure that the TTC and ATC calculations and resulting values developed by transmission service providers comply with the regional TTC and ATC methodology and applicable regional criteria; (2) document the results of its periodic review and (3) provide the results of its most current reviews to NERC upon request.

1060. In the NOPR, the Commission identified MOD-002-0 as a fill-in-the-blank standard that requires each regional reliability organization to develop and implement a procedure to periodically review and ensure that a transmission service provider's TTC and ATC calculations comply with regional TTC and ATC methodologies and criteria. The NOPR stated that the Commission would not propose to approve or remand MOD-002-0 until the ERO submits additional information.

i. Comments

1061. APPA agrees that MOD-002-0 is a fill-in-the-blank standard. It is not sufficient in its current form and should not be approved as a mandatory Reliability Standard until the accompanying regional procedures are submitted and approved.

ii. Commission Determination

1062. The Commission adopts the NOPR proposal not to approve or remand MOD-002-0 until the ERO submits additional information. Because the regional procedures have not been submitted to the Commission, it is not possible to determine at this time whether MOD-002-0 satisfies the statutory requirement that a proposed Reliability Standard be “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” Accordingly, the Commission neither approves nor remands this Reliability Standard until the regional procedures are submitted. In the interim, compliance with MOD-002-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice.

e. Regional Procedure for Input on Total Transfer Capability and Available Transfer Capability Methodologies and Values (MOD-003-0)

1063. MOD-003-0 requires each regional reliability organization to: (1) Develop and document a procedure on how a transmission user can present its concerns or questions regarding TTC and ATC calculations including the TTC and ATC values, and how these concerns will be addressed and (2) make its procedure for receiving and addressing these concerns available to other regional reliability organizations, NERC and transmission users on its Web site.

1064. In the NOPR, the Commission identified MOD-003-0 as a fill-in-the-blank standard that requires each regional reliability organization to develop and document a procedure on how a transmission user can present its concerns regarding the TTC and ATC methodologies of a transmission service provider. The NOPR stated that the Commission would not propose to approve or remand MOD-003-0 until the ERO submits additional information.

i. Comments

1065. APPA agrees that MOD-003-0 is a fill-in-the-blank standard. It notes that it is not sufficient in its current form and should not be approved as a mandatory Reliability Standard until the accompanying regional procedures are submitted and approved. In addition, APPA hopes that if NERC develops the MOD-001-0 Reliability Standard properly, it will include a reporting procedure for addressing shortcomings in information for all transmission customers (LSE, generator owner and purchasing-selling entity) in the MOD-001-0 Standard. APPA argues that, as a result, MOD-003-0 may be redundant and should be eliminated.

ii. Commission Determination

1066. The Commission adopts the NOPR proposal not to approve or remand MOD-003-0 until the ERO submits additional information. Because the regional procedures have not been submitted to the Commission, it is not possible to determine at this time whether MOD-003-0 satisfies the statutory requirement that a proposed Reliability Standard be “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” Accordingly, the Commission neither accepts nor remands this Reliability Standard until the regional procedures are submitted. In the interim, compliance with MOD-003-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice.

1067. We direct the ERO to consider APPA's suggestion that MOD-003-0 may be redundant and should be eliminated if the ERO develops a modification to the MOD-001-0 Reliability Standard through the Reliability Standards development process that includes reporting requirements.

f. Documentation of Regional Reliability Organization Capacity Benefit Margin Methodologies (MOD-004-0)

1068. MOD-004-0 requires each regional reliability organization to: (1) Develop and document a regional CBM [340] methodology in conjunction with its members and (2) post the most recent version of its CBM methodology on a Web site accessible by NERC, regional reliability organizations and transmission users.

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

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

i. Comments

1071. APPA agrees with the Commission that MOD-004-0 should not be approved as a mandatory Reliability Standard until the relevant regional procedures are submitted and approved. [341]

1072. FirstEnergy states that transmission capacity margins such as CBM and TRM are vitally important to the reliability of the system, and any methodology that would unduly limit these margins could create a danger of limiting transmission capacity over interconnected facilities that would limit the ability of balancing authorities and others to obtain generation reserves needed from the grid during contingency events. In contrast, TAPS questions how TRM or, especially, CBM, can be viewed as Reliability Standards if they are optional for the transmission provider.

1073. MidAmerican supports greater uniformity of CBM definitions and calculations and states that the revised standard and/or new standards should support transparency and uniformity by encouraging increased availability of information and consistent data input and modeling assumptions. EEI emphasizes that additional data and information-sharing requirements would improve the transparency of various calculations and assumptions related to CBM, including this standard and the other CBM-related standards. EEI believes that, similar to the peer review processes of the planning studies carried out under the TPL standards, industry participants are best suited to developing the totality of assumptions, system conditions and other input variables that support the calculations.

1074. EEI notes that, with respect to the Commission's particular concern about criteria in determining resources and loads used in the CBM methodology, NERC's “ATC Definitions and Determination” [342] document clearly delineates the purpose and intent of the calculation of CBM and TRM. EEI states that CBM is intended to provide generation reliability, and TRM is intended to provide transmission reliability. EEI believes that, to the extent capacity capable of supplying CBM is located in the vicinity of the designated facility experiencing an outage, transmission may or may not be available under the native load reservation normally used for the facility. Therefore, EEI argues, CBM may be needed on an interface where capacity is available for use as CBM, and not allowing all generation to be considered in this manner may unduly increase the generation reserve requirement within the transmission provider's system.

1075. EEI agrees with the Commission's concern about double-counting TRM for those transmission providers who do not opt to use CBM. However, EEI argues that for transmission providers who do opt to use CBM, it may be appropriate in some circumstances to use the same generation unit outage to determine the impact on both generation and transmission reliability because the impacts are different. EEI cautions that artificially restricting such use is not appropriate, especially before NERC's development of TRM and CBM standards and their presentation to FERC through the Reliability Standards development process. EEI recommends that the Commission encourage transmission providers to make CBM and TRM capacity available to wholesale markets for purchase on a non-firm basis, because doing so would ensure that both CBM and TRM capacity are available to the transmission provider during system emergencies, as intended. EEI notes that at other times the transfer capability associated with TRM and CBM would be available to the market, alleviating the concern of possible double-counting. MidAmerican also supports the Commission's conclusion that double-counting would be inappropriate, although MidAmerican states that it is not aware of any cases of double-counting of margins.

1076. TAPS notes the significant potential for abuse [343] that could result from the current flexibility afforded transmission providers in the calculation of CBM and TRM, and proposes innovative approaches [344] to take CBM and (to the extent it is intended to cover transmission required for reserve sharing) TRM out of the hands of individual transmission providers, and to therefore reduce the opportunity for abuse.

ii. Commission Determination

1077. The Commission adopts the NOPR proposal not to approve or remand MOD-004-0 until the ERO submits additional information. Because the regional procedures have not been submitted to the Commission, it is not possible to determine at this time whether MOD-004-0 satisfies the statutory requirement that a proposed Reliability Standard be “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” Accordingly, the Commission neither accepts nor remands this Reliability Standard until the regional procedures are submitted. In the interim, compliance with MOD-004-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice. Consistent with Order No. 890 and comments received in response to the NOPR, the Commission directs the ERO, through the Reliability Standards development process, to modify MOD-004-0 as discussed below.

1078. We agree with FirstEnergy that CBM is important for system reliability by allowing the LSEs to meet their historical, state, RTO or regional generation reliability criteria requirement such as reserve margin, loss of load probability, loss of largest units, etc. We agree with EEI and MidAmerican that transparency of the studies supporting CBM determination will reduce the opportunity for transmission service providers to overestimate the amount of CBM and misuse transfer capability. We therefore direct the ERO to develop Requirements regarding transparency of the generation planning studies used to determine CBM values. We also clarify that CBM should only be set aside upon request of any LSE within a balancing area to meet its verifiable historical, state, RTO or regional generation reliability criteria requirement such as reserve margin, loss of load probability, loss of largest units, etc. We expect verification of the CBM values to be part of the Requirements with appropriate Measures and Levels of Non-Compliance.

1079. We continue to believe this Reliability Standard should be modified to include a provision ensuring that CBM, TRM and ETC cannot be used for the same purpose, such as loss of the identical generating unit. In order to limit misuse of transfer capability set aside as CBM, we direct the ERO to provide more specific requirements for how CBM should be determined and allocated across transmission paths or flowgates. As we stated in Order No. 890, we do not mandate a particular methodology for allocating CBM to paths or flowgates. For example, one approach could be based on the location of the outside resources or spot market hubs that a LSE has historically relied on during emergencies resulting from an energy deficiency, but we agree with EEI that flexible rules should be allowed to prevent unnecessary increase of the generation reserve requirement within the transmission provider's system. Therefore, we support flexibility, but expect that the ERO, using its Reliability Standards development process, will adequately approach these complex technical issues and propose a new version of MOD-004-0 that addresses the methods for CBM determination and allocation on paths that will reduce reliability and discrimination concerns.

1080. In response to TAPS's question asking how CBM can be viewed as a Reliability Standard if it is optional to the transmission provider, our understanding is that transmission providers that have opted not to use CBM have instead set aside transmission margin (needed to bring in outside power to meet generation reliability criteria) either through ETC or TRM. CBM is not the only way to reserve transmission capacity for a margin. However, if the Reliability Standard is not clear regarding the method of calculating transmission margins, it may cause double-counting of transmission margins and reduction of ATC. As we stated in Order No. 890, we find that clear specification of the permitted purposes for which entities may reserve CBM and TRM will virtually eliminate double-counting of TRM and CBM. Therefore, we direct the ERO to modify its standard in order to prevent setting aside transfer capability for the same purposes.

1081. We share TAPS's concern that there is a significant potential for abuse as a result of the current flexibility afforded to transmission providers in the calculation of both CBM and TRM. In response to TAPS's concern, we clarify that in accordance with the OATT Reform Final Rule and the ERO CBM definition, each LSE has the right to request CBM be set aside and use it to meet its verifiable historical, state, RTO or regional generation reliability criteria requirement such as reserve margin, loss of load probability, loss of largest units, etc. As such, the LSEs that request CBM be set aside must be identified as applicable entities with identified Requirements, including Requirements on generation studies to verify the set aside, Measures and Levels of Non-Compliance. We direct the ERO to modify the Reliability Standard accordingly.

1082. We agree with TAPS that there is a need for clearer requirements in the standard regarding to whom and how to submit a request for CBM set-aside, and what the transmission service provider should do if the sum of all CBM requirements exceeds the amount of available transfer capability. We direct the ERO to address the reliability aspects in the Reliability Standards development process and explore with NAESB whether business practices would be required.

1083. Accordingly, the Commission neither accepts nor remands MOD-004-0 until the ERO submits additional information. In the interim, compliance with MOD-004-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice. Although the Commission did not propose any action with regard to MOD-004-0, it addressed above a number of concerns regarding the Reliability Standard, consistent with those set forth in Order No. 890. Therefore, we direct the ERO to develop modifications to the Reliability Standard through the Reliability Standards development process to: (1) Clarify that CBM shall be set aside upon request of any LSE within a balancing area to meet its verifiable historical, state, RTO or regional generation reliability criteria; (2) develop requirements regarding transparency of the generation planning studies used to determine CBM value; (3) modify the current Requirements to make clear the process for how CBM is allocated across transmission paths or flowgates; (3) modify its standard in order to prevent setting aside CBM and TRM for the same purposes; (4) modify the standard by adding LSE as an applicable entity and (5) coordinate with NAESB business practice standards.

1084. We direct the ERO to consider APPA's suggestion that MOD-004-0 may be redundant and should be eliminated if the ERO develops a modification to the MOD-002-0 Reliability Standard that includes reporting requirements

g. Procedure for Verifying Capacity Benefit Margin Values (MOD-005-1)

1085. MOD-005-1 specifies the requirements regarding the periodic review of a transmission service provider's adherence to the regional reliability organization's CBM methodology. It requires each regional reliability organization to: (1) Develop and implement a procedure to review at least annually the CBM calculations and the resulting values determined by member transmission service providers; (2) document its CBM review procedure and (3) make the results of the most current CBM review available to NERC upon request.

1086. In the NOPR, the Commission identified MOD-005-0 as a fill-in-the-blank standard that requires each regional reliability organization to develop and implement a procedure to review CBM calculations and the resulting values and to make the documentation of the results of the CBM review available to NERC and others. The NOPR stated that because the regional procedures had not been submitted, the Commission would not propose to approve or remand MOD-005-0 until the ERO submits the additional information.

i. Comments

1087. APPA agrees that MOD-005-0 is a fill-in-the blank standard, and that in its current form, it is not sufficient and should not be accepted for approval as a mandatory Reliability Standard until the necessary regional procedures have been submitted and approved. APPA suggests that NERC modify MOD-006-0, so that MOD-004-0 and MOD-005-0 could be eliminated.

ii. Commission Determination

1088. The Commission adopts the NOPR proposal not to approve or remand MOD-005-0 until the ERO submits additional information. Because the regional procedures have not been submitted to the Commission, it is not possible to determine at this time whether MOD-005-0 satisfies the statutory requirement that a proposed Reliability Standard be “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” Accordingly, the Commission neither accepts nor remands this Reliability Standard until the regional procedures are submitted. In the interim, compliance with MOD-005-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice.

1089. As to APPA's comment on incorporating MOD-004 and MOD-005 into MOD-006, we direct the ERO to consider those comments through the Reliability Standards development process.

h. Procedure for Use of Capacity Benefit Margin Values (MOD-006-0)

1090. The purpose of MOD-006-0 is to promote the consistent and uniform use of transmission CBM calculations among transmission system users. MOD-006-0 requires that each transmission service provider document its procedure for the scheduling of energy against a CBM reservation and make the procedure available on a Web site accessible by the regional reliability organization, NERC and transmission users.

1091. In the NOPR, the Commission proposed to approve Reliability Standard MOD-006-0 as mandatory and enforceable. In addition, the Commission proposed to direct NERC to submit a modification to MOD-006-0 that: (1) Includes a provision that will ensure that CBM and TRM are not used for the same purpose; (2) modifies Requirement R1.2 so that concurrent occurrence of generation deficiency and transmission constraints is not a required condition for CBM usage; (3) modifies Requirement R1.2 to define “generation deficiency” based on a specific energy emergency alert level and (4) expands the applicability section to include the entities that actually use CBM, such as LSEs.

1092. In addition, the Commission proposed that NERC should clarify the requirements to address when and how CBM can be used to reduce transmission provider discretion with regard to CBM usage. The Commission provided guidance expressing its belief that CBM should be used only when the LSE's local generation capacity is insufficient to meet balancing Reliability Standards, and that CBM should have a zero value in the calculation of non-firm ATC.

i. Comments

1093. APPA supports the Commission's proposal to approve MOD-006-0. Moreover, APPA agrees with the Commission's proposed directives [345] that the standard should address the use of CBM and TRM for the same purpose. However, APPA believes that the specificity of the Commission's proposed directives to NERC, if implemented, would undermine NERC's role as the approved ERO with the technical expertise to develop and revise standards for the Commission's subsequent review. APPA therefore suggests that the Commission in its Final Rule make clear to NERC its concerns about MOD-006-0, but then let NERC address those concerns through its Reliability Standard development process.

1094. Regarding the Commission's proposal that MOD-006-0 R1.2 be modified “so that concurrent occurrence of transmission constraints and a generation deficiency is not a requirement for CBM usage,” WEPCO asserts that the Commission is misinterpreting CBM. WEPCO states that if there is no transmission constraint then there is no need to use CBM. In that case, transmission capacity exists for a LSE to import energy. If there is a transmission constraint, CBM reserves transmission capacity that the LSE can use to import energy for reliability needs.

1095. EEI points out that the explicit intention for CBM is that it be used only during conditions where there are emergency generation deficiencies. However, EEI emphasizes that the Commission's recommendation does not consider that the LSE's supply and demand balance varies season to season, over time, and with supply and demand uncertainties. EEI says that the development of CBM quantities must be carried out in a manner that sets aside transmission capability for forecasted conditions and uncertainties much like the native load reservations necessary for serving reasonably-forecasted native load. An argument may be made that during a period of time when a LSE's expected reserves are substantially greater than its targeted reserves, the need for CBM set-aside decreases. However, should the LSE foresee that this “excess” would occur substantially in the future, a reduction in CBM would not be warranted since substantial uncertainties still exist.

1096. Additionally, regarding the Commission's proposal that a LSE that “has sufficient generation resources within its balancing authority to meet the balancing Reliability Standards, should not need to preserve capacity for CBM at all,” WEPCO argues that just because the balancing authority has sufficient generation does not mean that there is sufficient transmission capacity to deliver the energy to the LSE. WEPCO states that the LSE may be remote from the bulk of the balancing authority, so there may be occasions when a LSE that has sufficient generation resources within its balancing authority to meet the balancing Reliability Standards may still need to reserve capacity for CBM. In addition, EEI argues that the Commission's viewpoint does not take into account the availability of these resources unless they are under contract with the LSE to provide this service. EEI contends that the implication of this suggestion is to unduly restrict the sources of generation capacity available for CBM during times of generation shortage, which results in the LSE's being captive to local generation that is available and does not allow access to the market outside of the LSE's balancing authority. Additionally, EEI cautions that this action may require the LSE to develop contractual agreements with local generation and thus increase costs to the LSE's rate payers.

1097. Given the strong direction on CBM issues in the OATT Reform NOPR, TAPS assumes that the Commission would not be approving the Version 0 standards on these competitively crucial issues, but would continue to address them forcefully in the OATT Reform proceeding. TAPS notes that, although that is the course largely adopted by the NOPR in this proceeding, the NOPR [346] proposes to approve MOD-006-0 and MOD-007-0, with directions to improve these standards. TAPS notes that such action is inconsistent with the Commission's general approach to ATC/TTC/TRM/CBM standards in this docket and the OATT Reform NOPR. TAPS further states that, given the absence of clear access of non-transmission owner LSEs to CBM, the proposed expansion of MOD-007-0 to include such LSEs in the NOPR [347] seems bizarre.

ii. Commission Determination

1098. The Commission adopts the NOPR proposal to approve MOD-006-0 as mandatory and enforceable. Consistent with Order No. 890 and comments received in response to the NOPR, the Commission directs the ERO to modify MOD-006-0 as discussed below.

1099. Consistent with the views of many commenters, we adopt the NOPR proposal that requires a provision that will ensure that CBM and TRM are not used for the same purpose. As discussed under MOD-004-0 concerning the reservation of transfer capacity, we believe that if the Reliability Standard is not clear regarding the conditions specifying both the reservation and the use of CBM, it may cause double-counting. Such double-counting will lead to an unnecessary reduction of ATC, and create opportunities for discrimination. Therefore, we direct the ERO to modify its standard to prevent use of CBM and TRM for the same purposes. We agree with APPA that the ERO should use its Reliability Standards development process to address the double-counting problem.

1100. We adopt the NOPR's proposal and direct the ERO to modify Requirement R1.2 so that a transmission constraint is not a required condition for CBM usage. The glossary definition and the use as defined in Order No. 890 is that CBM “is intended to be used by the LSE only in time of emergency generation deficiencies.” [348] Therefore we direct the ERO to modify the standard in the manner proposed in the NOPR.

1101. We adopt the NOPR proposal that requires modification of Requirement R1.2 to define “generation deficiency” based on a specific energy emergency alert level. This approach will provide clarity as to when the use of CBM may be permitted. We therefore direct the ERO to modify the Reliability Standard to include a specific energy emergency alert level that will trigger CBM usage.

1102. We also reiterate the direction in Order No. 890 that CBM should have a zero value in the calculation of non-firm ATC because non-firm service may be curtailed so that CBM can be used. CBM is reserved as part of the firm transfer capability so that it is available when needed for energy emergencies. We determine that each LSE should be permitted to call for use of CBM, provided all of the other Requirements of R1.1 are met. We direct that CBM may be implemented up to the reserved value when a LSE is facing firm load curtailments.

1103. We adopt the NOPR proposal that CBM should be used only when the LSE's local generation capacity is insufficient to meet balancing Reliability Standards, with the clarification that the local generation is that generation capacity that is either owned or contracted for by the LSE. We disagree with WEPCO that just because the balancing authority has sufficient generation does not mean that there is transmission capacity to deliver the energy to the LSE. The Commission finds that such a scenario would violate existing transmission operating and transmission planning Reliability Standards. There is an explicit requirement in the transmission operating standards that generation reserves must be deliverable to load. [349] Also, there is an explicit requirement in the transmission planning standards that all firm load must be supplied under various system conditions with and without contingencies. [350] The Commission is not prescribing how these requirements should be met. There are a variety of approaches to do so, including adequate transmission capability, local or dynamic generation transfers into the area or DSM. To clarify for EEI, our proposal does not take into account the availability of these resources unless they are under contract with the LSE to provide this service. We developed our NOPR proposal on the rationale derived from the CBM concept, and believe that if there are enough resources to meet generation reliability criteria within the balancing authority, there is no need to request CBM.

1104. We also adopt the NOPR proposal to require the applicability section to include the entities that actually use CBM, such as LSEs. The current CBM definition in the NERC glossary determines that LSEs are users of CBM. Load-serving entities determine when to use CBM, initiate CBM use and call for its end. Load-serving entities therefore have to comply with the standard requirements that specify the conditions under which CBM will be used. We direct the ERO to modify the standard accordingly.

1105. With regard to TAPS's comments concerning its assumption that the Commission would not be approving the Version 0 standards on these issues, but would continue to address them in the OATT Reform proceeding, the Commission finds that MOD-006-0 and MOD-007-0 do not establish CBM values, but rather address CBM implementation and documentation. The implementation of CBM has critical implications for the reliable operation of the Bulk-Power System and we find that these Reliability Standards should be mandatory and enforceable. The competitively significant issue is to assure that there is no double-counting of CBM and to determine the magnitude of CBM which is addressed in other Reliability Standards that the Commission has not approved or remanded.

1106. The Commission approves MOD-006-0 as mandatory and enforceable. In addition, the Commission directs the ERO to develop a modification to Reliability Standard MOD-006-0 through the Reliability Standards development process that: (1) Includes a provision that will ensure that CBM and TRM are not used for the same purpose; (2) provides that CBM should be used for emergency generation deficiencies; (3) modifies Requirement R1.2 to define “generation deficiency” based on a specific energy emergency alert level; (4) includes a provision that CBM should have a zero value in the calculation of non-firm ATC and (5) expands the applicability section to include the entities that actually use CBM, such as LSEs.

i. Documentation of the Use of Capacity Benefit Margin (MOD-007-0)

1107. MOD-007-0 requires transmission service providers that use CBM to report and post its use.

1108. In the NOPR, the Commission proposed to approve Reliability Standard MOD-007-0 as mandatory and enforceable. In addition, the Commission proposed to direct NERC to submit a modification to MOD-007-0 that expands the applicability section to include the entities that actually use CBM, such as LSEs.

i. Comments

1109. APPA supports the Commission's proposed approval of MOD-007-0. However, it believes that the issue of whether LSEs should be made subject to MOD-007-0 should be left to NERC in the first instance to decide. In so doing, NERC should consider expanding MOD-007-0 to cover not only LSEs, but also balancing authorities. Under NERC's Functional Model, the balancing authority is the entity that would schedule energy over transmission capacity reserved as CBM. Moreover, it is the balancing authority that would know the information necessary to report an incident during which the balancing authority had to import energy from outside the balancing authority's own area from a resource designated as operating reserves and change the net scheduled interchange with the neighboring balancing authorities to allow the energy to flow into the balancing authority's area.

ii. Commission Determination

1110. The Commission approves MOD-007-0 as mandatory and enforceable. Consistent with the comments received in response to the NOPR, the Commission directs the ERO to modify the standard as discussed below.

1111. We also adopt the NOPR's proposal to require the applicability section to include the entities that actually use CBM and report on their CBM use, such as LSEs. The current CBM definition in the NERC glossary determines when a LSE is a CBM user. The LSE determines how much CBM will be set aside, when CBM use will start and when it will end. The LSE must therefore comply with the standard requirements that require reporting and posting of CBM use. We direct the ERO to modify the standard to include the entities that actually use CBM, such as LSEs. In addition, we agree with APPA that the Reliability Standard should apply to balancing authorities and direct the ERO to include balancing authorities within the entities to which this standard is applicable.

1112. Accordingly, the Commission approves MOD-007-0 as mandatory and enforceable. In addition, the Commission directs the ERO to develop a modification through its Reliability Standards development process that expands the applicability of MOD-007-0 to include the entities that actually use CBM, such as LSEs and balancing authorities.

j. Documentation and Content of Each Regional Transmission Reliability Margin Methodology (MOD-008-0)

1113. MOD-008-0 requires the development and posting of a regional methodology for TRM, which is transmission capacity that is reserved to provide reasonable assurance that the interconnected transmission network will remain secure under various system conditions. The Reliability Standard requires each regional reliability organization to: (1) Develop and document a regional TRM methodology in conjunction with its members and (2) post on a Web site the most recent version of its TRM methodology.

1114. In the NOPR, the Commission identified MOD-008-0 as a fill-in-the-blank standard, proposing that because the regional methodologies had not been submitted, the Commission would not propose to approve or remand MOD-008-0 until the ERO submitted the additional information. The Commission expressed concern about the lack of: (1) Clear requirements on how TRM should be calculated and allocated across paths and (2) consistent criteria and clarity with regard to the entity on whose behalf TRM had been set aside.

1115. The Commission requested comment in the NOPR on how TRM is currently calculated and allocated across paths, and what would be a recommended approach for the future.

i. Comments

1116. APPA agrees that MOD-008-0 is a fill-in-the-blank standard, is not sufficient as currently drafted, and should not be approved as a mandatory Reliability Standard until NERC and the regional reliability organizations and regional entities develop the necessary regional methodologies and the Commission approves them.

1117. MISO adds that there should be a consistent framework to be followed by entities in determining TRM. It states that relevant MOD standards should be revised if such a framework is not clearly delineated. However, MISO cautions that a Reliability Standard should not be used to address a perceived equity concern. MidAmerican also supports greater uniformity of TRM definitions and calculations, and proposes that a revised standard and/or new standards should encourage transparency with increased availability of information, consistent data input and certain modeling assumptions. International Transmission agrees and proposes that TRM consistency should be addressed either on a regional basis or on an Interconnection-wide basis.

1118. In response to the Commission's request for comments on the current calculation of TRM, and recommended approaches for the future, International Transmission provides a description of the MISO approach to TRM. International Transmission states that during the operating horizon (next 48 hours), TRM is limited to a reserve sharing component which only applies to flowgates that are not based on transmission outages (unit tripping and transmission outages are considered a double contingency). International Transmission states that the logic behind this approach is that there are fewer uncertainties in the operating horizon because schedules and market flows are known. International Transmission explains that during the planning horizon (next 48 hours), a two percent TRM component for uncertainty is used on all flowgates, including those requiring reserve sharing TRM. In addition, other assumptions regarding the sale of transmission service enter into the need for TRM to cover “uncertainties.” In addition, International Transmission cautions that MISO's minimal two percent margin may not be sufficient for long-term planning horizon requests (i.e., over 13 months) if planning “assumptions” are not reasonable. International Transmission argues that MISO must also employ proper sensitivity studies to other system variables for a two percent margin to be sufficient. TRMs in the five to ten percent range are not necessarily unreasonable if a wide range of potential system operating conditions is not studied. Regardless of the ultimate approach adopted in future standards, International Transmission proposes that all entities follow a consistent framework when calculating TRM.

1119. MidAmerican responds with a discussion of its current approach to TRM calculation, which has been performed in accordance with MAPP-approved methodologies. MidAmerican states that these methodologies include an amount to allow for both the delivery of operating reserves and for uncertainties. Since delivery of operating reserves keeps the interconnected network in service, benefiting all market participants, MidAmerican contends that it is appropriate for TRM to include an amount to allow for the delivery of operating reserves. The allowance for uncertainty is calculated as a percentage of TTC required to protect reliability. All market participants benefit from the provision of an appropriate margin for uncertainty because the reliability of the interconnected network is maintained and service interruptions are reasonably minimized.

1120. With respect to applicable entities, APPA proposes the addition of two new functional entities. Specifically, APPA believes that NERC should expand the applicability section of MOD-008-0 to include planning authorities and reliability coordinators. APPA points out that these are the only entities that can evaluate the amount of error in their transfer capability predictions.

1121. ERCOT states that the Commission's concerns about TRM do not apply to ERCOT, because ERCOT has a balanced grid in which all transmission is firm, no transmission is reserved and there are no transmission paths.

ii. Commission Determination

1122. The Commission does not approve or remand MOD-008-0 until the ERO submits additional information. Consistent with Order No. 890 and comments received in response to the NOPR, the Commission directs the ERO to modify MOD-008-0 through the Reliability Standards development process, as discussed below.

1123. Consistent with the NOPR proposal and Order No. 890, the Commission directs the ERO to modify standard MOD-008-0 to clarify how TRM should be calculated and allocated across paths or flowgates. We understand that the standards drafting process is underway as a joint project with NAESB. We agree with International Transmission, MidAmerican and MISO about the need for more uniformity and transparency in TRM calculation methodology and use, in order to eliminate potential reliability and discrimination concerns. Consistent with Order No. 890, the Commission directs the ERO to specify the parameters for entities to use in determining uncertainties for which TRM can be set aside and used, such as: (1) Load forecast and load distribution error; (2) variations in facility loadings; (3) uncertainty in transmission system topology; (4) loop flow impact; (5) variations in generation dispatch; (6) automatic reserve sharing and (7) other uncertainties as identified through the NERC Reliability Standards development process. We find that clear specification in this Final Rule of the permitted purposes for which entities may reserve CBM and TRM will also virtually eliminate double-counting of TRM and CBM. Therefore, we direct the ERO to determine clear requirements regarding permitted uses for TRM through its Reliability Standards development process.

1124. We agree with the commenters that the percentage reduction of line rating can be one way to establish an appropriate maximum TRM if thermal considerations are the only limiting factors. While this is a relatively simple method, it ignores limitations relative to voltage or stability limitations which are the more typical reasons for transmission limitations. If adopted as the Reliability Standard method, it should not restrict a transmission provider from using a more sophisticated method that may allow for greater ATC without reducing overall reliability. However, we disagree with the use of an arbitrary percentage over a long time frame that is not based on either proven historical need or sensitivity studies that support that determination. Therefore, consistent with our OATT Reform Final Rule, we direct the ERO to develop requirements regarding transparency of the documentation that supports TRM determination.

1125. We agree with APPA that NERC should revise the applicability section of this standard to add planning authorities and reliability coordinators, and in addition, any other entities that may be identified in the Reliability Standards development process.

1126. Regarding ERCOT's statement that TRM does not apply to ERCOT, we reiterate our position that any request for a regional exemption from the applicable Reliability Standards must take place in the Reliability Standards development process.

1127. The Commission neither accepts nor remands MOD-008-0 until the ERO submits additional information. In the interim, compliance with MOD-008-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice. Although the Commission did not propose any action with regard to MOD-008-0, it addressed above a number of concerns regarding the Reliability Standard, consistent with those proposed in Order No. 890. Accordingly, we direct the ERO to develop modifications to the Reliability Standard through the Reliability Standards development process including: (1) Clear requirements on how TRM should be calculated, including a methodology for determining the maximum TRM value, and allocated across paths; (2) clear requirements for permitted purposes for which TRM can be set aside and used; (3) clear requirements for availability of documentation that supports TRM determination and (4) expanding the applicability to add planning authorities and reliability coordinators and any other appropriate entity identified in the Reliability Standards development process.

k. Procedure for Verifying Transmission Reliability Margin Values (MOD-009-0)

1128. MOD-009-0 requires each regional reliability organization to develop and implement a procedure to review TRM calculations and the resulting values determined by member transmission providers to ensure compliance with the regional TRM methodology.

1129. In the NOPR, the Commission identified MOD-009-0 as a fill-in-the-blank standard that requires each regional reliability organization to develop a procedure for review of TRM calculations and the resulting values. In the NOPR, the Commission stated that because the regional procedures had not been submitted, the Commission would not propose to approve or remand MOD-009-0 until the ERO submits the additional information.

i. Comments

1130. APPA agrees that MOD-009-0 is a fill-in-the-blank standard, is not sufficient as currently drafted, and should not be approved as a mandatory Reliability Standard until NERC and the regional reliability organizations and regional entities develop the necessary regional methodologies and the Commission approves them.

ii. Commission Determination

1131. The Commission will not approve or remand MOD-009-0 until the ERO submits additional information. Because the regional procedures have not been submitted to the Commission, it is not possible to determine at this time whether MOD-009-0 satisfies the statutory requirement that a proposed Reliability Standard be “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” Accordingly, the Commission neither approves nor remands this Reliability Standard until the regional procedures are submitted. In the interim, compliance with MOD-009-0 should continue on a voluntary basis, and the Commission considers compliance with the Reliability Standard to be a matter of good utility practice.

l. Steady-State Data for Modeling and Simulation of Interconnected Transmission System (MOD-010-0)

1132. The purpose of this Reliability Standard is to establish consistent data requirements, reporting procedures and system models for use in reliability analysis. MOD-010-0 requires the transmission owner, transmission planner, generator owner and resource planner to provide stea