E7-14340. Mandatory Reliability Standards for the Bulk-Power System

Issued July 19, 2007.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule; order on rehearing.

SUMMARY:

The Commission denies rehearing and otherwise reaffirms its determinations in Order No. 693. 72 FR 16,416 (April 4, 2007). We further clarify certain portions of the Preamble to that order. Order No. 693 approved 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, which the Commission has certified as the Electric Reliability Organization (ERO) responsible for developing and enforcing mandatory Reliability Standards. Order No. 693 also required the ERO to submit significant improvements to 56 of the 83 Reliability Standards that are being approved as mandatory and enforceable. Finally, Order No. 693 provided that the remaining 24 Reliability Standards will remain pending at the Commission until further information is provided. Order No. 693 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 website for public inspection.

DATES:

Effective Date: The final rule became effective on June 18, 2007.

FOR FURTHER INFORMATION CONTACT:

Jonathan First (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

Christy Walsh (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

Robert Snow (Technical Information), Office of Energy Markets and Reliability, Division of Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

SUPPLEMENTARY INFORMATION:

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

Order on Rehearing

	Paragraph
I. Introduction	1
A. Summary of Order No. 693	3
B. Procedural Matters	4
II. Discussion	7
A. Applicability Issues	7
1. Bulk-Power System v. Bulk Electric System	7
2. NERC Registry	20
3. Use of the NERC Functional Model	48
B. Mandatory Reliability Standards	57
1. Prioritizing Modifications to Reliability Standards	57
2. Trial Period	61
C. Common Issues Pertaining to Reliability Standards	65
1. Blackout Report Recommendation on Liability Limitations	65
2. Fill-in-the-Blank Standards	70
D. Discussion of Individual Reliability Standards	82
1. EOP-001-0	82
2. EOP-002-2	86
3. EOP-008-0	90
4. FAC-003-1	95
5. IRO-001-1	100
6. IRO-005-1 and IRO-005-2	120
7. MOD-013-1	123
8. PRC-007-0, PRC-008-0, and PRC-009-0	132
9. TOP-008-1	153
III. Information Collection Statement	156
IV. Document Availability	157

I. Introduction

1. On March 16, 2007, the Commission issued a Final Rule (Order No. 693) ^[1] approving, pursuant to section 215 of the Federal Power Act (FPA),^[2] 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. However, the Commission stated that, although it believed it is in the public interest to make these Reliability Standards mandatory and enforceable, it also found that much work remains to be done. Specifically, it stated that many of these Reliability Standards require significant improvement to address, among other things, the recommendations of the Blackout Report.^[3] Therefore, pursuant to section 215(d)(5), we required the ERO to submit significant improvements to 56 of the 83 Reliability Standards that are being approved as mandatory and enforceable. The Commission stated that the remaining 24 Reliability Standards will remain pending at the Commission until further information is provided.

2. Order No. 693 added 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. Summary of Order No. 693

3. In Order No. 693, the Commission stated that there were four possible courses of action that it would 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. As mentioned above, the Commission approved 83 Reliability Standards and directed NERC to develop modifications to 56 of the approved Reliability Standards. In approving the Reliability Standards, Order No. 693 stated that, for an initial period, the Commission would rely on the NERC definition of bulk electric system, rather than the statutory Bulk-Power System, 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.^[4] Further, while the Commission did not institute a formal “trial period,” it directed the ERO and Regional Entities to “focus their resources” on the “most serious violations” during an initial period through December 31, 2007.^[5]

B. Procedural Matters

4. The following entities have filed timely requests for rehearing or for clarification of Order No. 693: American Public Power Association (APPA); Avista Corporation, Portland General Electric Company, and Puget Sound Energy, Inc. (collectively, Avista); City of Santa Clara, California (Santa Clara); Cogeneration Association of California and the Energy Producers and Users Coalition (California Cogeneration); ISO-New England, Inc. (ISO-New England); Midwest Independent Transmission System Operator, Inc. (Midwest ISO); National Association of Regulatory Utility Commissioners (NARUC); National Rural Electric Cooperative Association (NRECA); Pacific Northwest Security Coordinator (PNSC); Transmission Agency of Northern California (TANC); and Xcel Energy Services, Inc. (Xcel).

5. PNSC's rehearing request is deficient because it fails to include a Statement of Issues section separate from its arguments, as required by Rule 713 of the Commission's Rules of Practice and Procedure.^[6] Rule 713(c)(2) requires that a rehearing request must include a separate section entitled “Statement of Issues” listing each issue presented to the Commission in a separately enumerated paragraph that includes representative Commission and court precedent on which the participant is relying.^[7] Under Rule 713, any issue not so listed will be deemed waived. Accordingly, we will dismiss PNSC's rehearing request.^[8]

6. In any event, PNSC's arguments on rehearing are beyond the scope of this proceeding. PNSC asks the Commission to clarify that PNSC is in compliance with IRO-001 because it has written agreements delineating the responsibilities and authority of the operating personnel who staff its reliability center. Whether any one entity is in compliance with a Reliability Standard is not an issue in the rulemaking.

II. Discussion

A. Applicability Issues

1. Bulk-Power System v. Bulk Electric System

7. Section 215 of the FPA defines the term “Bulk-Power System” as follows:

(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.

8. 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.

9. In Order No. 693, the Commission stated that, for an initial period, it would rely on the NERC definition of bulk electric system 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.^[9] However, the Commission stated that it was concerned about the need to address the potential for gaps in coverage of facilities. The Commission intends to address this matter in future proceedings. As a first step in enabling the Commission to understand the reach of the Reliability Standards, we directed the ERO 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).

10. However, the Commission disagreed with commenters who suggested that there is no intentional distinction between Bulk-Power System and bulk electric system. This distinction was evidenced by the fact that “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.” ^[10] Thus, the Commission “confirmed” that the Bulk-Power System reaches farther than those facilities that are included in NERC's definition of the bulk electric system, although choosing to rely on the NERC definition for determining the immediate applicability of the approved Reliability Standards. The Commission indicated that it remained concerned about potential gaps in coverage of facilities and that any change in applicability would be addressed in future Commission proceedings.

a. Requests for Rehearing

11. NRECA asks that the Commission clarify that it has not definitively decided that the term Bulk-Power System as defined in section 215 of the FPA encompasses more than NERC's definition of bulk electric system. Rather, NRECA understands that the Commission deferred on determining whether its jurisdiction expands beyond the bounds of the bulk electric system. NRECA is concerned that Order No. 693 may suggest that the Bulk-Power System is broader than the bulk electric system out of a misapprehension that NERC's definition imposes a rigorous 100 kV “cutoff” when, according to NRECA, it actually provides for more flexibility. Alternatively, if the Commission has definitively interpreted the term Bulk-Power System to encompass more than the bulk electric system, NRECA seeks rehearing.

12. In support of its request for rehearing, NRECA raises three arguments that the Commission erred in determining that the statutory definition of Bulk-Power System is broader than NERC's definition of bulk electric system. First, it contends that such a determination violates a rule of law that the parts of a statute should be construed in accordance with the statute's overall legislative purpose.^[11] NRECA explains that section 215 was intended to replace the prior voluntary reliability standards with a mandatory scheme but, to the best of NRECA's knowledge, no participant in the drafting of the legislation expressed the view that Congress intended to expand NERC's scope.^[12] NRECA states that, if the issue had been presented, it would have prompted a legislative record. The absence of such record confirms that an intent to expand NERC's scope was never expressed.

13. Second, NRECA contends that an expansive definition of Bulk-Power System is contrary to the text of section 215, which narrows the Commission's reach. Specifically, NRECA contends that the statutory definition of Bulk-Power System makes clear that the term does not encompass all transmission facilities but, rather, only those facilities and control systems “necessary for operating an interconnected electric energy transmission network.” It also points to the statutory definitions of Reliability Standard and Reliable Operation that refer to protecting the system from instability, uncontrolled separation or cascading failures. NRECA infers from this that there is no reason to conclude that Congress included in the definition of Bulk-Power System any facilities other than those that could materially contribute to instability, uncontrolled separation or cascading outages.

14. Third, NRECA posits that, if Congress borrows a term of art that has an established meaning, the established meaning is to apply.^[13] NRECA claims that the terms Bulk-Power System and bulk electric system have been used interchangeably for decades and cites examples from both industry documents and Commission orders. According to NRECA, Congress did not adopt NERC's exact definition of bulk electric system because it was insufficiently specific for legislation. NRECA asserts that “Congress used more and different words than NERC in order to provide clarity, but the definition of Bulk-Power System incorporated the exact same facilities as NERC and the regions had always included in their working definition of bulk electric system * * *” ^[14]

15. NARUC seeks clarification that the Commission will “continue relying on NERC's definition of Bulk-Power System” and NERC's registration process beyond the initial period during which mandatory Reliability Standards are in effect.^[15] It states that section 215 of the FPA was enacted based on an industry consensus that it would apply to facilities and entities covered by the historical definition of Bulk-Power System. According to NARUC, the term applies to higher-voltage, network facilities that integrate regional transmission networks to ensure the reliability of interconnected system operations. NARUC states that NERC's definition of Bulk-Power System is consistent with section 215 and that a broader interpretation is inconsistent with Congressional intent because such a definition could sweep in facilities such as load centers and local transmission facilities that do not have a material impact on system reliability.

16. NARUC also seeks clarification that, if the Commission determines that NERC's current definition requires revision, NERC should revise the definition using its American National Standards Institute (ANSI)-accredited process. Further, NARUC expresses concern that the Commission has directed the ERO to submit a complete set of regional definitions of bulk electric system and, thus, asks the Commission to clarify that it will continue to defer to the ERO's and Regional Entities' determinations concerning which facilities and entities materially affect the reliability of the interconnected transmission network and should be included in the compliance registry.

b. Commission Determination

17. The Commission will grant NRECA's request for clarification, and thus dismisses its request for rehearing. We agree with NRECA that NERC's definition of bulk electric system does not impose a 100 kV cutoff and provides some flexibility in its application.^[16] Although Order No. 693 stated that the Commission believes that the Bulk-Power System reaches farther than those facilities that are included in NERC's definition of the bulk electric system, the Commission has not definitively defined the extent of the facilities covered by the Bulk-Power System. As we stated in Order No. 693, the Commission intends to address concerns regarding the scope of the term Bulk-Power System in future proceedings. NRECA and others will not be legally precluded from presenting arguments in such a proceeding that the terms Bulk-Power System and bulk electric system encompass the same facilities.

18. The Commission notes NRECA's assertion that the Commission's determination that the Bulk-Power System reaches farther than the bulk electric system is contrary to the text of section 215 of the FPA. Because the Commission has not definitively defined the extent of the facilities covered by the Bulk-Power System, the Commission believes that this determination is best made in the context of a Commission proceeding determining the extent of the Bulk-Power System. We make no finding on the matter at this time. The Commission defers judgment on this matter to a later proceeding so that the Commission can develop a record on which to base its final determination.

19. In response to NARUC, the Commission will continue to rely on NERC's definition of bulk electric system, with the appropriate regional differences, and NERC's registration process until the Commission determines in future proceedings the extent of the Bulk-Power System. The requirement that the ERO file a complete set of regional differences was to enable the Commission to understand the current reach of the Reliability Standards. However, we do not agree with NARUC that NERC should be allowed to define Bulk-Power System using its American National Standards Institute (ANSI)-accredited process. The statutory term Bulk-Power System defines the jurisdiction of the Commission. Although the Commission has chosen to defer, for the time being, to the ERO as to which entities must comply with Reliability Standards, the fundamental matter of determining the extent of Commission's jurisdiction cannot and will not be delegated to the ERO.

2. NERC Registry

20. Order No. 693 accepted the ERO's compliance registry process as an appropriate approach to identify the set of entities that are responsible for compliance with a particular Reliability Standard.^[17] Further, Order No. 693 explained that NERC has developed 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. NERC's compliance registry process identifies and registers entities based on categories of functions within the Bulk-Power System and related Commission-approved Reliability Standards. For example, NERC plans to register individual generator 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.” The Commission accepted the Statement of Compliance Registry Criteria, stating that “[w]e believe that NERC has set reasonable criteria for registration* * *”.^[18]

21. Further, Order No. 693 noted that the Commission's regulations then exempted most qualifying facilities (QFs) from specific provisions of the FPA including section 215.^[19] The Commission, however, expressed concerned whether it is appropriate to grant QFs a complete exemption from compliance with Reliability Standards that apply to other generator owners and operators, and noted that the Commission was concurrently issuing a notice of proposed rulemaking proposing to amend the Commission's regulation that exempts most QFs from section 215 of the FPA. The Commission has since issued a final rule eliminating the exemption of QFs from the requirements of section 215 of the FPA.^[20]

c. Requests for Rehearing

22. California Cogeneration argues that the Commission improperly relied on the ERO's compliance registry process. It contends that the Commission, rather than determining who the “users” of the Bulk-Power System are, has improperly delegated this task to the ERO and Regional Entities. California Cogeneration notes that the NERC registry criteria were submitted for information purposes only. Further, it contends that these criteria are being applied inconsistently among the Regional Entities, noting in particular that Western Electricity Coordinating Council (WECC) has developed supplemental criteria that may result in the registration of entities not captured by the ERO criteria.^[21] It also points to discrepancies in ERCOT's registration process.

23. California Cogeneration also argues that Reliability Standards that are not clear in how they are applied or are applied inconsistently are not just and reasonable. It contends that the examples of regional variation in the registration process demonstrate a lack of required clarity and consistency.

24. NRECA asks the Commission to clarify that, in expanding the applicability of certain Reliability Standards,^[22] it has not departed from the compliance registry concept or sought to dictate actions by the ERO. Alternatively, the Commission should grant rehearing. According to NRECA, it appears possible, even likely, that the Commission was not specifying that additional entities register, but was merely specifying that the ERO should consider whether entities otherwise required to register (because they meet or exceed specified thresholds, or because they had been to shown to have a material impact on grid reliability) should also be subject to these particular Reliability Standards.^[23] If that is the Commission's intended meaning, NRECA requests that the Commission specify the requested clarification and resolve the matter (subject to subsequent consideration by the ERO). However, if the Commission intends to impose a broader obligation, i.e., to encompass additional entities in the Reliability Standards, then NRECA seeks rehearing.

25. Further, NRECA argues that the Commission should not, as it recognized in Order No. 672-A, prescribe either the text or the substance of a Reliability Standard, including which entities are subject to the Reliability Standards, because that responsibility is reserved to the ERO, subject to the Commission's review. NRECA maintains that the Commission lacks the authority to dictate what a Reliability Standard requires or who it encompasses, as the Commission has recognized previously in Order No. 672-A. NRECA notes that Order No. 693 states that 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 * * *. 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.” ^[24]

26. Beyond that, NRECA asserts that the Reliability Standards should not apply at all to entities whose scope of activities is too limited to have a material impact on grid reliability. In other words, the specific Reliability Standards should not apply to a distribution provider or a load-serving entity just because it is a distribution provider or a load-serving entity; instead, the Reliability Standards at issue, as well as the Reliability Standards generally, should not apply unless an entity has a material impact on grid reliability. According to NRECA, this concept is central to NERC's compliance registry, and the Commission has not articulated a sound basis for departing from it, notwithstanding the Commission's lack of authority to do so.

27. With respect to COM-001-1 or some replacement standard addressing black start capability, and COM-002-2, for example, NRECA asserts that some entities are functionally irrelevant for black start activities. It argues that having to coordinate black start operations with a large number of small entities, most, if not all, of which are served through interconnections with larger and bigger entities in the hierarchy of the Functional Model, would hinder, rather than facilitate, black start operations. NRECA maintains that the Commission should defer to the ERO's technical expertise.

28. NRECA raises similar concerns with respect to TOP-003-1. According to NRECA, read literally, the Commission appears to recommend delegating the determination of whether entities that fall below the threshold of NERC's definition of bulk electric system should be subject to the standard to “the opinion of the transmission operator, balancing authority, or reliability coordinator.” If so, NRECA asserts that this approach would appear to override both the compliance registry and the ERO, and the Commission would effectively delegate authority that it does not have to entities that could well face incentives to favor their own interests over those of load-serving entities that could be made subject to the Reliability Standards. The Commission cannot delegate authority it does not have in the first place, and the determination should be that of the ERO and the Regional Entity. While NRECA agrees that the ERO and the Regional Entities may and should take the views of the transmission operators, balancing authorities, and reliability coordinators into account, it argues that this is considerably different than simply abdicating the matter to them.

29. NRECA has similar concerns with the treatment of VAR-001-1 with respect to the Commission's “direct[ing] the ERO to address the reactive power requirements of load-serving entities on a comparable basis with purchasing-selling entities.” While NRECA agrees that this may be an appropriate matter for the ERO to consider, it argues that the Commission should not be dictating a particular action, nor should the Commission be overriding the compliance registry approach that it elsewhere endorses in its Final Rule.

30. Accordingly, NRECA requests the Commission to clarify that it has not overridden the compliance registry with respect to COM-001-1, COM-002-2, and TOP-003-0, nor dictated specific changes to those Reliability Standards. Alternatively, NRECA seeks rehearing. Absent the requested clarification, NRECA asserts that the Commission has sought to prescribe the substance of a Reliability Standard in excess of its statutory authority under section 215, contrary to its own recognition of the limitations on its authority in Order No. 672-A, and contrary to Order No. 693 itself. NRECA maintains that the proposed changes could undermine rather than enhance reliability for the reasons stated, and thus involve matters where the Commission should and is required to defer to the ERO's technical expertise.

31. Xcel notes that, pursuant to NERC's registry criteria, NERC will generally register individual generator units of 20 MVA or greater that are directly connected to the bulk electric system. According to Xcel, under NERC's criteria, generators that are connected to distribution facilities are generally exempt from registration as they are not connected to the Bulk-Power System. Xcel seeks rehearing of the Commission's decision to accept this aspect of the ERO's registration process, contending that generating facilities that are connected at a distribution voltage but deliver energy to the transmission system can affect transmission system reliability and, thus, should be subject to mandatory Reliability Standards. Further, Xcel contends that the exclusion of facilities connected at a distribution level creates inappropriate incentives for entities to interconnect generating facilities at the distribution level rather than the transmission level.

32. TANC requests clarification of the Commission's statement that:

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.[^[25] ]

33. According to TANC, this statement seems to require all entities subject to the Reliability Standards to register for each requirement applicable to transmission owners, which it states is inconsistent with the Commission's goal of preventing overlap and negates the transmission owner classification in the NERC Functional Model. Therefore, TANC asks the Commission to clarify that only those entities that meet the description of transmission owner provided in NERC's compliance registry and the NERC Functional Model descriptions are required to register as responsible entities for the Requirements applicable to transmission owners.

34. TANC asks that the Commission specify that, where an existing contract between two parties provides that one is the transmission owner, but the other has agreed to perform the TOP functions, the latter entity be listed in the compliance registry as the responsible entity for the TOP Reliability Standards. Further, TANC maintains that the transmission owner should not be the default entity ultimately responsible for compliance with the TOP Reliability Standards. According to TANC, only the entity accepting responsibility to perform the tasks delegated to it in the agreement should be accountable for the responsibilities assigned to it in the agreement. TANC asserts that, where entities have assigned responsibilities by contract, there is no reason to register those responsibilities to another entity.

35. California Cogeneration claims that Order No. 693 failed to adequately address the unique characteristics of QFs. It states that reliance on the registry process, which is based on the 14 functions identified in the NERC functional model, does not adequately distinguish among different types of generators, including size and location, and their impact on reliability. California Cogeneration states that the Commission, as a remedy to these infirmities, should direct NERC to immediately initiate a stakeholder process to revise the Reliability Standards to identify in greater detail the entities that are responsible for compliance and revise requirements to recognize the operational constraints of different generators. It states that this process should be completed before Reliability Standards become enforceable. Further, California Cogeneration states that the stakeholder process should also develop criteria for determining whether an entity has a “material impact” on reliability.

36. Finally, California Cogeneration states that the Commission was not responsive to issues raised by California Cogeneration in its rulemaking comments regarding individual Reliability Standards that apply to generator owners and operators and needed revisions if they are to be applied to cogenerators. It states that some of these Reliability Standards seem to require information regarding gross generation or load behind the customer's point of interconnection, contrary to an earlier Commission order.^[26] While the Commission directed the ERO to consider these concerns during its three-year Work Plan to review each Reliability Standard, California Cogeneration contends this approach does not suffice because cogenerators must comply with the Reliability Standards in the interim.

d. Commission Determination

37. The Commission denies California Cogeneration's request for rehearing concerning the definition of users of the Bulk-Power System. The Commission has not improperly delegated this definition to the ERO and Regional Entities. While NERC proposed the registry criteria, the Commission reviewed the criteria and approved them as appropriate under section 215 of the FPA. Further, the Commission has provided a method by which any 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.^[27] Therefore, the Commission has the ultimate ability to determine whether an entity should be on the NERC registry.

38. With regard to the fact that certain Regional Entities have created supplemental criteria to determine which entities should be on the registry, we agree with California Cogeneration that this is not appropriate.^[28] Order No. 693 accepted NERC's compliance registration process “to provide as much certainty as possible regarding the applicability and responsibility of specific entities under the approved standards.” ^[29] NERC's Statement of Compliance Registry does not reference supplemental compliance registries created by Regional Entities. While both the Commission and the ERO have made it clear that an entity that falls below the minimum registry criteria may be included on the compliance registry on a facility-by-facility basis, nonetheless NERC's compliance registry places the burden on the Regional Entity to reasonably demonstrate that the organization is a user, owner or operator of the Bulk-Power System.^[30] This language contemplates a case-by-case registration of entities outside the NERC criteria, provided that a reasonable demonstration of the need to register the entity ^[31] is made by the Regional Entity.^[32]

39. In response to NRECA, in directing the ERO to expand the applicability of certain Reliability Standards, the Commission did not intend to expand the applicability beyond those entities that are on the compliance registry. Rather, we indicated where the Commission believed there was a reliability concern in not applying certain Reliability Standards to a category of registered entities. For example, in COM-001-0, where the Commission directed the ERO to add distribution providers that are essential to the implementation of a black start plan to the Applicability section, this would include only those distribution providers that are on the compliance registry.

40. The Commission agrees with NRECA to the extent that we do not wish that a direction for modification be so overly prescriptive as to preclude the consideration of viable alternatives in the ERO's Reliability Standards development process. However, as stated in Order No. 693, 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, the ERO might not know how to respond adequately to a Commission proposal to modify a Reliability Standard.^[33] Thus, in some instances, while we provided specific details regarding the Commission's expectations, we intended by doing so to provide useful guidance to assist in the Reliability Standards development process, not to impede it.

41. With respect to the specific Reliability Standards cited by NRECA, the Commission first notes that NRECA does not appear to request rehearing on the substance of the directed modifications, but argues that the Commission was too prescriptive procedurally. In many instances, the Commission provided guidance to the ERO and stated that it could develop an alternative to our direction, so long as the alternative is as effective and efficient as the Commission's proposal. However, with respect to the Reliability Standards cited by NRECA, the Commission has identified specific concerns about the gap in applicability in the Reliability Standard. For example, as to COM-001-1 and COM-002-2, the Commission was concerned about having a reliability gap during normal and emergency operations. Section 215(d)(5) of the FPA states:

The Commission, upon its own motion or upon complaint, may order the Electric Reliability Organization to submit to the Commission a proposed reliability standard or a modification to a reliability standard that addresses a specific matter if the Commission considers such a new or modified reliability standard appropriate to carry out this section.

In the instances cited by NRECA, the Commission has identified a deficiency in the applicability of the Reliability Standard. To correct this deficiency, the ERO must add the specific entity to the Applicability section of the Reliability Standard.

42. TOP-003-0 contains Requirements that can have a significant impact on both the reliability of the Bulk-Power System and on competition with regard to available transfer capability (ATC). The Commission's approval of TOP-003-0 does not override either the compliance registry or the ERO. The planning authority or transmission planner should inform its Regional Entity if it is not receiving cooperation in getting the information it requires. We note that section 39.2(d) of our regulations requires each user, owner or operator of the Bulk-Power System to provide the Commission, the ERO and the applicable Regional Entity such information as is necessary to implement section 215 of the FPA. If a problem arises in obtaining information necessary to calculate ATC, the Commission may revisit this matter in the future. For example, if entities are unable to obtain the required information under TOP-003-0, the Commission might require the ERO, through the Reliability Standards development process, to develop a provision to ensure that all jurisdictional entities that must provide information pursuant to TOP-003-0 because of a particular reliability need are added to the registry, even if only to meet the requirements of TOP-003-0.

43. The Commission denies Xcel's request for rehearing. As noted by Xcel, NERC's registry criteria state that the ERO and Regional Entities will “generally” register generators greater than 20 MVA and will “generally” exempt generators that are connected to distribution facilities. The use of the term “generally” allows the ERO and Regional Entities flexibility to register a generator meeting those descriptions if the ERO or a Regional Entity determines that the facility is needed for Bulk-Power System reliability. Further, Order No. 693 specifically provided for such an outcome.^[34] Therefore, those generating facilities that Xcel is concerned about, which are connected at a distribution voltage but deliver energy to the transmission system, may be required to comply with Reliability Standards depending on a possible case-by-case determination by the ERO or a Regional Entity. Xcel does not provide any support for its claim that this general exclusion of facilities connected at a distribution level creates inappropriate incentives for entities to interconnect generating facilities at the distribution level rather than the transmission level.

44. In response to TANC's concern that Order No. 693 appears to require all entities subject to the Reliability Standards to register for each requirement applicable to transmission owners, we disagree. This statement was made only to ensure that there are no gaps or unnecessary redundancies with regard to the entity or entities responsible for compliance. The Commission did not intend to imply that each user, owner and operator of the Bulk-Power System must comply with those Reliability Standards which apply to transmission owners. Rather, the Commission intended for the ERO to ensure that there is clarity in the registering of entities and that the registration process results in no gaps or unnecessary redundancies.

45. Further, the Commission clarifies that it did not intend to change existing contracts, agreements or other understandings as to who is responsible for a particular function under a Reliability Standard.^[35] The Commission believes that allowing an organization to accept compliance responsibility on behalf of its members should cover TAPS' concerns regarding a situation in which two entities have a contract regarding which will perform functions under the Reliability Standards.^[36] NERC has filed procedures for allowing such agreements in Docket No. RM06-16-003. The Commission will rule on the particulars of those procedures in that proceeding.

46. The Commission denies California Cogeneration's request for rehearing with respect to exemption of QFs from compliance with mandatory Reliability Standards. As stated in Order No. 696, for reliability purposes, there is no meaningful distinction between QF and non-QF generators that would warrant generic exemption of QFs from mandatory Reliability Standards.^[37] Therefore, we disagree with California Cogeneration that Order No. 693 failed to adequately address the unique characteristics of QFs.

47. Whether a generation facility should be subject to Reliability Standards should depend on whether electric energy from the generation facility is needed to maintain the reliability of the Bulk-Power System. The registration criteria adopted by NERC and approved by the Commission, as well as the compliance registry process adopted by NERC and approved by the Commission, are designed to ensure that only those facilities needed to maintain the reliability of the Bulk-Power System are subject to the Reliability Standards. The ultimate decision with respect to individual generation units or plants is, and must be, made on a case-by-case basis. Thus, whether a particular QF or type of QF should be exempt from Reliability Standards is an issue that is more appropriately raised in the context of NERC's establishment of registry criteria for owners and operators of generators, and in the context of NERC's compliance registry process. The reliability of the Bulk-Power System will be better protected by addressing this issue in the NERC compliance registry process, which will ensure that no generator that is needed to maintain the reliability of the Bulk-Power System will be exempt from Reliability Standards, while excusing those generators that are not needed to maintain reliability. Therefore, the Commission rejects California Cogeneration's request that it direct NERC to immediately initiate a stakeholder process to revise the Reliability Standards to identify in greater detail the entities that are responsible for compliance and revise requirements to recognize the operational constraints of QF generators.

3. Use of the NERC Functional Model

48. Order No. 693 explained that 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. While the Commission had proposed to require that NERC file future revisions to the Functional Model, Order No. 693 determined that such filing was not necessary.^[38] The Commission made this determination based on 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, the Commission agreed with commenters that the applicability section of a particular Reliability Standard should be the ultimate determinant of applicability of each Reliability Standard. While some commenters asked that all revisions to the Functional Model be developed through NERC's ANSI-accredited process, the Commission left to the discretion of the ERO the appropriate means of allowing stakeholder input when revising the Functional Model.

e. Requests for Rehearing

49. TANC requests rehearing of the Commission's determination that future modifications of the Functional Model do not need to be submitted to the Commission for approval. TANC contends that the Functional Model is more than just a guidance document and, rather, is fundamental to determining the applicability of each Reliability Standard. It asserts that the ERO's compliance registry process that is used to identify users, owners and operators of the Bulk-Power System that must comply with Reliability Standards relies on the Functional Model. Thus, according to TANC, a change in the Functional Model affects the applicability and enforcement of each Reliability Standard.

50. Further, TANC contends that the Reliability Standards are not “complete,” a quality objective identified by NERC in the development of Reliability Standards, because the Reliability Standards are dependent on an external document. TANC is concerned that revising the Functional Model could result in additional entities having to comply with Reliability Standards without affording these entities adequate notice of what is expected of them. It notes that terms used in the Functional Model are also defined in the NERC glossary, which was approved by the Commission. Thus, TANC requests that the Commission require the ERO to submit revisions to the Functional Model for Commission approval, either as revisions to the Functional Model or revised terms in the NERC glossary, after development through the ERO's full Reliability Standards development process.

51. Midwest ISO contends that the Commission erred in failing to require NERC to define the distinct roles of the “planning coordinator” and “planning authority.” According to Midwest ISO, while NERC used the term planning authority when it developed the “Version 0” Reliability Standards, it was recognized that there was “[no] common understanding of who or what the Planning Authority was.” ^[39] Further, Midwest ISO explains that many Reliability Standards describe roles for both the planning authority and transmission planner. Midwest ISO states that, while the latest revision to the Functional Model substitutes the term “planning coordinator” for “planning authority,” this has not resolved the problem because the responsibilities of the planning coordinator “are both more limited and wide-area in nature” and may not be simply substituted for those of planning authority. Midwest ISO notes that certain Regional Entities are registering entities based on the planning authority function as previously defined, and Midwest ISO asks rhetorically whether the ERO can hold a company accountable to a set of Reliability Standards applicable to an entity that it no longer recognizes as valid.

52. Midwest ISO maintains that the Commission did not adequately address Midwest ISO's concerns when it stated in Order No. 693 that the ERO can address such concerns as it updates and revises the Functional Model. According to Midwest ISO, the Reliability Standards state that regions should work closely with the planning coordinators on a common understanding of roles and responsibilities, but such a process will be lengthy and perhaps futile without Commission guidance. Further, Midwest ISO states that, while NERC will address this issue in the long term, the Commission's failure to provide interim clarification or direct NERC to specify the role of the planning coordinator is an error.

f. Commission Determination

53. The Commission denies TANC's request for rehearing. The Commission disagrees with TANC that the Commission-approved Reliability Standards are incomplete. As stated in Order No. 693, the applicability section of a particular Reliability Standard should be the ultimate determinant of applicability of each Reliability Standard.^[40] Further, the Commission notes that we required the ERO to update the Glossary of Terms Used in Reliability Standards through the Reliability Standards development process whenever a new or revised Reliability Standard includes a new defined term.^[41]

54. The Commission disagrees with TANC that the Functional Model is used to identify users, owners and operators of the Bulk-Power System that must comply with Reliability Standards. The compliance registry criteria are used to determine which entities must be listed on the compliance registry, and therefore must comply with Reliability Standards. Changes in the Functional Model cannot require additional entities to comply with Reliability Standards. Consistent with our explanation in Order No. 693, if an entity is registered as a result of a change that emanated from a revision of the Functional Model, the entity would have an opportunity to seek review by the ERO and the Commission. Accordingly, we deny the request for rehearing and will not require NERC to file revisions to the Functional Model.

55. Further, we reject Midwest ISO's contention that the Commission erred in failing to provide guidance in directing NERC to define the distinct roles of the planning authority and planning coordinator. First, as recognized by Midwest ISO, NERC will address this issue as part of its long range plan. This is consistent with the Commission's statement in Order No. 693 that “given that the Functional Model is an evolving guidance document, the ERO can address such concerns as it updates and revises the Functional Model.” ^[42] Midwest ISO has provided insufficient support for its contention that addressing this matter may be lengthy and futile without Commission intervention. Moreover, consistent with Order No. 693, any ambiguity regarding roles and the responsibility of a particular entity for compliance with a particular Reliability Standard is a matter that should be addressed in the registration of a particular entity.

56. Finally, we disagree with Midwest ISO's suggestion that it is inappropriate to register entities as planning authorities given that the applicability provisions of the Commission-approved Reliability Standards refer to the planning authority and not the planning coordinator. Consistent with our discussion above, revisions to the Functional Model do not convey rights and responsibilities but, rather, the modification to the applicability provision of a Reliability Standard or NERC glossary ultimately determines an entity's obligations.

B. Mandatory Reliability Standards

1. Prioritizing Modifications to Reliability Standards

57. In Order No. 693, the Commission directed the ERO to submit a revised Work Plan to: (1) Reflect modification directives contained in Order No. 693; (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. The Commission required that the ERO set specific delivery dates, explaining that “[a] Work Plan with specific target dates will provide a valuable tool and incentive to timely address the modifications directed in this Final Rule.” ^[43] Further, Order No. 693 stated that:

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 [the] 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.[^[44] ]

g. Requests for Rehearing

58. NRECA asks for clarification, or alternatively rehearing, that Order No. 693 does not allow the imposition and enforcement of deadlines that preclude the ERO from satisfying the due process requirements set forth in section 215 of the FPA or applying its own expertise. NRECA states that a deadline “may be reasonable or unreasonable, and its reasonableness needs to be determined within context” taking into account the complexity of the matter and other considerations.^[45] NRECA contends that the imposition and enforcement of an unreasonable deadline conflicts with section 215 as well as Order No. 672. Thus, NRECA seeks clarification that the Commission's assertion of authority to establish deadlines for ERO action represents no more than the authority to “exhort” the ERO to move expeditiously, consistent with its statutory due process obligations. “However, if the Commission is purporting in the Final Rule to reserve the power to specify an unreasonable deadline, that undermines due process and ignores the ERO's technical expertise in contravention of the requirements of section 215, then NRECA seeks rehearing of the Commission's determination.” ^[46]

h. Commission Determination

59. The Commission agrees that it should not impose deadlines that preclude the ERO from satisfying the due process requirements set forth in section 215 of the FPA, and has provided in several previous orders that, in complying with a deadline, NERC must also meet the requirements of the FPA and the Commission's regulations. In our January 2007 Compliance Order, we made it clear that a revision to NERC's expedited Reliability Standards development process must “make it clear that the Commission can order expedited standard development in a specific time frame and that NERC must adhere to that time frame and still allow for due process.” ^[47] On rehearing, we further clarified that “any ERO process that provides ‘reasonable notice and opportunity for comment, due process, openness, and balance of interests’ as required by section 215(c)(2)(D) of the FPA, and that also can meet a Commission-imposed deadline pursuant to section 39.5(g) of the Commission's regulations, will comply with this directive.” ^[48]

60. Finally, in Order No. 693, the Commission stated that the ERO should make every effort to meet Commission-ordered delivery dates. However, we acknowledged that “there may be certain cases in which the ERO is not able to meet [the] 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.” ^[49]

2. Trial Period

61. In Order No. 693, while the Commission did not institute a formal “trial period,” it directed the ERO and Regional Entities to “focus their resources” on the “most serious violations” during an initial period through December 31, 2007.^[50] Order No. 693 stated that this use of enforcement discretion should apply to all users, owners and operators of the Bulk-Power System. The Commission explained 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 places Bulk-Power System reliability at risk. This approach would 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.

i. Requests for Rehearing

62. Xcel states that, while it supports the Commission's decision that the ERO and Regional Entities should have the enforcement discretion to calculate but not collect penalties during an initial period, it asks that the Commission provide greater clarity and guidance regarding the circumstances when penalties should be collected and when they should not. It asks that the Commission be as specific as possible in defining the circumstances under which the ERO and Regional Entities should exercise their enforcement discretion. It suggests that the Commission clarify that to assess a penalty a violation must be, at a minimum, (i) an intentional violation of a well-understood Reliability Standard and (ii) a violation that causes substantial harm.

j. Commission Determination

63. The Commission denies Xcel's request for clarification. First, the Commission believes that Xcel's requested clarification would not always capture the most serious violations. Moreover, the Commission in Order No. 693 intentionally declined to develop a threshold that would place limits on the ERO's and Regional Entities' exercise of enforcement discretion; and we decline to do so here as well. Although we clearly allowed for “the ERO or a Regional Entity to take an enforcement action against an entity whose violation causes a significant disturbance,” we also provided that the ERO and Regional Entities can assess a monetary penalty in a situation where, for example, an entity's non-compliance places Bulk-Power System reliability at risk.^[51] We did not require that there be actual harm to the Bulk-Power System for the ERO to assess a penalty during the transition period.

64. The Commission believes that it is better to allow the ERO and Regional Entities to use their expertise in determining which violations constitute the most serious. Likewise, the ERO and Regional Entities are in the best position to know how to best use their finite enforcement resources. This will require case-by-case analysis of the circumstances surrounding a situation. Therefore, we will not stipulate a single set of circumstances under which the ERO and Regional Entities should use their enforcement discretion for the initial transition period.

C. Common Issues Pertaining to Reliability Standards

1. Blackout Report Recommendation on Liability Limitations

65. In Order No. 693, consistent with Order No. 890, the Commission did not adopt new liability protections.^[52] The Commission stated that it did not believe any further action is needed to implement Blackout Report Recommendation No. 8 because the Task Force found that no further action is needed.^[53] Further, the Blackout Report indicated that some states already have appropriate protection against liability suits.^[54] Finally, the Commission stated that, in Order No. 888, as affirmed by Order No. 890, 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.^[55]

k. Requests for Rehearing

66. Avista seeks rehearing on the Commission's determination not to provide further liability limitations and questions whether it is fair, just and reasonable to deny transmission operators that are not regional transmission organizations (RTOs) or independent system operators (ISOs) the protections afforded to RTOs and ISOs and at the same time impose mandatory Reliability Standards with significant fines and penalties as an enforcement mechanism.^[56] Avista argues that the Commission has limited the scope of liability in the pro forma open access transmission tariff (OATT) to instances of gross negligence or intentional misconduct and also limited damages by excluding consequential, indirect or punitive damages for RTOs and ISOs. According to Avista, not providing these same limitations to other transmission operators is, on its face, arbitrary, and may have unintended adverse consequences to the ratepayers of any transmission operator whose operating employee's decisions initiate a large cascading outage, if available insurance is not adequate to cover the risk. Avista argues that enforcement of mandatory Reliability Standards should not depend both on risk of massive liability exposure and upon multi-million dollar civil fines and penalties.

l. Commission Determination

67. The Commission denies rehearing. The Commission has already ruled that the liability standard the Commission has approved for RTOs and ISOs is not appropriate for other transmission providers.^[57] Further, we also found without merit assertions that increased liability protections in the pro forma OATT should be viewed as a necessary element of the implementation of the Commission's reliability authority.^[58] In the Reliability Policy Statement,^[59] the Commission stated that it would consider, on a case-by-case basis, proposals by public utilities to amend their OATTs to include limitations on liability. The Commission further noted that, while this issue has not been resolved on a standardized basis, the Commission has entertained RTO transmission providers' specific proposals to amend their OATTs to include provisions addressing limitations on liability.^[60]

68. In subsequent orders, the Commission found that the gross negligence and intentional wrongdoing indemnification and liability standard is appropriate for RTOs and ISOs. However, the Commission has declined to extend this protection to all transmission providers. In Southwest Power Pool, Inc., the Commission explicitly stated “that our acceptance here of the gross negligence and intentional wrongdoing indemnity standard is limited to SPP, in its role as an RTO, and its TOs; we do not intend to extend such protection to all transmission providers.” ^[61] In Southern Company Services, Inc., the Commission stated that:

Having considered Southern Companies' proposed limitation on liability and indemnification provisions pursuant to our Reliability Policy Statement cited above, we find that Southern Companies have not shown that they are similarly situated to the RTOs/ISOs they cite in support. While Southern Companies claim that they ‘may not be protected by any State-regulated limitations on liability,' Southern Companies offer no evidence to support this concern. The Commission has provided such liability protection to RTOs/ISOs because they were created by and solely regulated by the Commission, and otherwise would be without limitations on liability. Southern Companies have proffered no evidence of any change in circumstances vis-à-vis their liability exposure post-Order No. 888.^[62]

69. Further, we disagree with Avista that there is a risk of massive liability exposure. It offers no new arguments that demonstrate that non-RTO and non-ISO transmission providers are unable to rely on state laws, i.e., the state laws provide inadequate protection. Avista has not persuaded us to change our policy regarding liability protections applicable to non-RTO and non-ISO transmission providers. Therefore, we deny rehearing.

2. Fill-in-the-Blank Standards

70. In Order No. 693, the Commission required supplemental information for any Reliability Standard that currently requires a regional reliability organization to fill in missing criteria or procedures.^[63] The Commission explained that, where important information has not yet been provided, it would not approve or remand such Reliability Standards until the ERO submits further information. Until such information is provided, compliance with the so-called 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. Further, the Commission stated:

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. 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.^[64]

m. Requests for Rehearing

71. While APPA believes that Order No. 693 correctly deferred consideration of the “fill-in-the-blank” standards, it requests rehearing of the Commission's approval of other Reliability Standards that incorporate the “fill-in-the-blank” standards. APPA argues that the Commission cannot, lawfully, approve Reliability Standards for immediate enforcement that incorporate those same unreviewed and unapproved regional Reliability Standards.

72. According to APPA, approving a Reliability Standard that references an unapproved fill-in-the-blank standard requires compliance with regional Reliability Standards that the Commission has not reviewed or approved. APPA asserts that the Commission cannot determine if a Reliability Standard that references a pending Reliability Standard is “just, reasonable, not unduly discriminatory or preferential, and in the public interest” for the same reasons that the Commission articulated in determining that it lacked important information needed to evaluate “fill-in-the-blank” standards.

73. APPA also argues that the approved Reliability Standards that reference a fill-in-the-blank standard do not promote uniformity and consistency as required by Order No. 672. APPA asserts that the Commission cannot determine if such Reliability Standards are justified, because the regional standard is more stringent than continent-wide Reliability Standards or is necessitated by a physical difference in the Bulk-Power System, without reviewing the regional standard in question to determine whether one of those two findings is appropriate. APPA also maintains that the Commission cannot conclude that the processes by which the regional practices involved in the referenced fill-in-the-blank standards were developed meet statutory requirements. APPA raises concerns about due process and fundamental fairness, asserting that small entities have often not been included in past regional processes, and may not have received prior notice of the standards with which they must now comply.

74. APPA also argues the Commission is incorrect 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.” According to APPA, Reliability Standards may sweep in many small entities that have not been members of regional reliability organizations and have not necessarily complied with standards on a voluntary basis.

75. APPA argues that the Commission's approval of Reliability Standards that make enforceable unreviewed “fill-in-the-blank” standards could trigger registration of a large number of small entities. According to APPA, unless it can be assumed that no change in the scope or content of the fill-in-the-blank standards will result from the ongoing process NERC and the Regional Entities are undertaking to fill in the blanks, mandatory enforcement of the “before” version is likely to sweep in different entities and subject them to different standards than will the “after” version. Further, APPA asserts that, by posing the potential to sweep a large number of small entities onto the compliance registry before the applicable regional standard is approved, the Commission's decision calls into question its adherence in Order No. 693 to the Regulatory Flexibility Act requirements because, absent review of the undisclosed incorporated “fill-in-the-blank” standards, the Commission cannot estimate the number of small systems these Reliability Standards will affect. Further, APPA maintains that the Commission cannot make the requisite determination that a small entity's compliance with an unapproved “fill-in-the-blank” standard has a material impact on reliability, and the Commission cannot find such compliance necessary for Bulk-Power System reliability.

76. Finally, APPA maintains that, even though the Commission stated that the fact that a Reliability Standard references a fill-in-the-blank standard “may be considered in an enforcement action,” ^[65] the Commission should not have approved such Reliability Standards. According to APPA, the ability of an entity to raise this issue in an enforcement action occurs too late to avoid the harm to many small entities in being required to register and comply with what it calls unapproved regional underfrequency load shedding (UFLS) programs that have not been developed through Commission-approved processes meeting the statutory standard, and which may well differ from the final standard that the Commission approves to fill in the blanks. Nor, according to APPA, does the ability to raise issues relating to fill-in-the-blank standards in an enforcement action avoid the potential for significant distraction of NERC and Regional Entities from more crucial reliability-related duties to instead deal with compliance by numerous small entities that have no material impact on the grid with regional standards that are in a state of flux. APPA also asserts that this statement cannot overcome the fundamental legal deficiency with approving a Reliability Standard that references a fill-in-the-blank standard—that the Commission lacks authority to approve regional reliability standards that require compliance with regional UFLS standards it has neither reviewed nor approved.

77. Xcel contends that the statement that the Commission does not intend to enforce, as an OATT violation, compliance with any Reliability Standard that has not been approved by the Commission under section 215 is confusing. By stating that the Commission does not intend to enforce as an OATT violation compliance with a Reliability Standard that has not been approved by the Commission under section 215, Xcel is concerned that the Commission may intend to enforce as an OATT violation non-compliance with a Reliability Standard that has been approved by the Commission under section 215. Xcel seeks clarification or rehearing on this issue.

n. Commission Determination

78. The Commission denies APPA's request for rehearing and provides further clarification. The Commission continues to believe that the fact that a Reliability Standard simply references a Reliability Standard that was not approved or remanded in Order No. 693 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 the Reliability Standard. Further, we clarify that, in an enforcement proceeding, such a reference can be considered regarding whether a particular Requirement or part of a Requirement in an otherwise approved Reliability Standard is enforceable.^[66] The Commission did not err in approving Reliability Standards that reference a pending Reliability Standard because they 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. We will discuss the issue raised by APPA in regard to the Protection and Control Systems (PRC) group of Reliability Standards in our discussion of individual Reliability Standards below.

79. In approving a Reliability Standard that references a fill-in-the-blank standard, the Commission is not requiring compliance with the unapproved Reliability Standard. Therefore, it is immaterial how the regional differences discussed in the unapproved Reliability Standard were created. Rather, as addressed more fully in our discussion on the PRC group of Reliability Standards below, the Commission, ERO and Regional Entities will only enforce the data requirements and any requirement that can be independently enforced in those Reliability Standards, and will not enforce compliance with regional criteria created by a regional reliability organization pursuant to an unapproved fill-in-the-blank standard.^[67]

80. APPA's contention that approving a Reliability Standard that references a fill-in-the-blank standard could trigger additional small entity registration is speculative. At this time, registration is governed by NERC's definition of bulk electric system and its compliance registry criteria. Nothing in a Reliability Standard can cause an entity to be registered if it would otherwise not be required to do so.

81. In response to Xcel, the Commission clarifies that it does not intend to enforce as a violation of good utility practice non-compliance with a Reliability Standard that has been approved by the Commission under section 215. However, where the OATT contains a specific requirement that may be related to a Reliability Standard, for example, an independent obligation under the OATT to calculate transmission capacity, the Commission does not limit its ability to take enforcement action separately against a violation of a Reliability Standard and a violation of a specific OATT provision. Such determinations will be based on the facts of a specific circumstance.

D. Discussion of Individual Reliability Standards

1. EOP-001-0

82. 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.

83. Order No. 693 approved Reliability Standard EOP-001-0. In addition, the Commission directed the ERO to develop a modification to EOP-001-0 that, among other things, includes the reliability coordinator as an applicable entity. In pertinent part, the Commission found the reliability coordinator to be a necessary entity under EOP-001-0 and directed the ERO to modify the Reliability Standard to include the reliability coordinator as an applicable entity.^[68] Recognizing the importance NERC attributes to the reliability coordinator in connection with matters covered by EOP-001-0, the Commission was 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. The Commission reasoned that, 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 a wide-area view.

o. Requests for Rehearing

84. Midwest ISO disagrees with the Commission's mandate to the ERO to make EOP-001-0 applicable to the reliability coordinator. It notes that the Commission correctly did not provide guidance on the reliability coordinators' role in the emergency planning process and appears to have left this issue up to the industry experts. Midwest ISO argues that the industry had already addressed any potential role of the reliability coordinator in emergency planning by declining to make the reliability coordinator an applicable entity in EOP-001-0.

p. Commission Determination

85. The Commission affirms its determination to mandate that the ERO make EOP-001-0 applicable to the reliability coordinator function because it is the highest level of authority responsible for reliable operation of the Bulk-Power System and has a wide-area view. Midwest ISO has not substantively disputed that Requirements for mitigation of emergencies will benefit from including a role for the entity with a wide-area view. The ERO may consider other equivalent alternatives and consider industry concerns in its modification of EOP-001-0.

2. EOP-002-2

86. EOP-002-2 applies to balancing authorities and reliability coordinators and is intended to ensure that they are prepared for capacity and energy emergencies. This Reliability Standard requires that balancing authorities have the authority to bring all necessary generation on line, communicate about energy and capacity emergencies 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 load-serving entity.

87. Order No. 693 approved Reliability Standard EOP-002-2. In addition, the Commission directed the ERO to develop a modification to EOP-002-2 that, among other things, would modify the Reliability Standard to ensure that the Transmission Loading Relief (TLR) procedure is not used to mitigate actual Interconnection Reliability Operating Limit (IROL) violations. The Commission found that the TLR procedure may be appropriate and effective for use in managing potential IROL violations, but that the TLR procedure is an inappropriate and ineffective tool for mitigating actual IROL violations or for use in emergency situations as called for in EOP-002-2. Accordingly, the Commission directed the ERO to modify the Reliability Standard to ensure that the TLR procedure is not used to mitigate actual IROL violations.^[69]

q. Requests for Rehearing

88. Midwest ISO requests that the Commission clarify which of the following conditions constitutes a “potential IROL” violation for purposes of EOP-002-2: (1) The operating limit has been exceeded, but 30 minutes has not elapsed and the operator may yet return the system to normal; or (2) the operating limit has not been exceeded, but appears that it may be if action is not taken quickly. Midwest ISO believes that the second circumstance is the one the Commission identified as being appropriate for TLR mitigation, but reasons that the terminology can be interpreted differently by different operators applying historically different operating practices.

r. Commission Determination

89. The Commission clarifies that a potential IROL violation refers to the second circumstance provided by Midwest ISO, in which “the operating limit has not been exceeded, but appears that it may be if action is not taken quickly.” In such a situation, use of TLR procedures may be appropriate depending on the circumstances. Moreover, actions undertaken under the TLR procedure are not fast and predictable enough for use in situations in which an operating security limit is being violated.

3. EOP-008-0

90. 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.

91. Order No. 693 approved Reliability Standard EOP-008-0. In addition, the Commission directed the ERO to develop a modification to EOP-008-0 that, among other things, includes a Requirement that provides for backup capabilities that, at a minimum, requires transmission operators and balancing authorities that have operational control over significant portions of generation and load to have minimum backup capabilities, but may do so through contracting for these services instead of through dedicated backup control centers.^[70]

s. Requests for Rehearing

92. Midwest ISO supports the outcome of Order No. 693 with regard to Commission mandates in EOP-008-0. However, it notes that ambiguities and potential misunderstandings could result from imprecise adjectives in the Reliability Standards. Specifically, for purposes of EOP-008-0, Midwest ISO advocates that the Commission should define an amount of load or generation that constitutes a “significant” portion of generation and load that would require entities to have minimum backup capabilities through backup control centers. Alternatively, Midwest ISO proposes that NERC could be directed to create a “safe-harbor” limit below which a system would not be considered significant unless found to be so by the Regional Entity or the ERO.

t. Commission Determination

93. The Commission reiterates its direction in Order No. 693 that the goal of this Reliability Standard is to provide the continuation of Reliable Operation and the maintenance of situational awareness in the event that the primary control center is no longer operational.^[71] To that end, every registered reliability coordinator, balancing authority, transmission operator, and centrally dispatched generator operator should have a plan and means of achieving the outcome of the plan upon the loss of their respective control centers. The Commission has identified three requirements as a minimum for the plans—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. The Reliability Standard should provide specific Requirements, based on the size or impact to Reliable Operation, to achieve the Commission's requirements.

94. The Commission declines to define a “safe harbor” limit requested by Midwest ISO. We directed the ERO, through the Reliability Standards development process, to identify what Requirements are necessary on which size entities to achieve the Commission's directives and the goal of this Reliability Standard. Since there are many equally efficient ways of achieving the Commission's direction, we will not identify any specific method or safe harbor.

4. FAC-003-1

95. FAC-003-1 addresses vegetation management on transmission rights-of-way. As proposed, 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 developed for the geographical area and specific design configurations of the transmission owner's system.

96. Order No. 693 approved Reliability Standard FAC-003-1. In addition, while we did not direct the ERO to submit a modification to the general limitation on applicability to facilities above 200 kV, we required the ERO to address Commission concerns regarding the applicability threshold through the ERO's Reliability Standards development process.^[72] The Commission was concerned that the bright-line applicability threshold of 200 kV in this Reliability Standard would exclude a significant number of transmission lines that could impact Bulk-Power System reliability. We stated that, 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 is currently, but to extend the applicability to lower-voltage facilities that have an impact on reliability.

u. Requests for Rehearing

97. NRECA asks that the Commission clarify that Order No. 693 did not mandate that FAC-003-1 apply to lines below 200 kV. NRECA believes that a fair reading of Order No. 693 is that the Commission only directed the ERO to give additional consideration to having FAC-003-1 apply to lines below 200 kV and did not purport to require such a modification.^[73] However, NRECA claims that other portions of Order No. 693 appear to go further, such as where the Commission states that it is requiring the Reliability Standard “to include a greater number of entities* * *”. ^[74] In view of the potential ambiguity, NRECA requests that the Commission clarify that it is not dictating a particular outcome to the ERO's deliberations, as such a directive would be contrary to section 215 of the FPA, Order Nos. 672 and 672-A, and other portions of Order No. 693. Alternatively, NRECA requests rehearing.

v. Commission Determination

98. We will grant NRECA's request for clarification. First, in Order No. 693, we specifically stated that “[w]e will not direct NERC to submit a modification to the general limitation on applicability [in FAC-003-1] as proposed in the NOPR.” ^[75] Further, as a general matter, we stated that a direction for modification should not preclude the consideration of viable alternatives in the ERO's Reliability Standards development process.^[76]

99. In Order No. 693, the Commission stated that it was concerned that the bright-line applicability threshold of 200 kV would exclude a significant number of transmission lines that could impact Bulk-Power System reliability. We noted that, at that time no regional reliability organization had used its discretion to designate lower voltage lines under the proposed Reliability Standard, even though there are lower voltage lines involving IROL.^[77] The Commission was concerned that this approach would not require all transmission lines that could impact Bulk-Power System reliability to be included under this Reliability Standard. While the Commission did not mandate that FAC-003-1 apply to lines below 200 kV, the Commission did require the ERO to address the Commission's concerns through its Reliability Standards development process.

5. IRO-001-1

100. 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. 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.”

101. Order No. 693 approved Reliability Standard IRO-001-1. In Order No. 693, the Commission declined to adopt a change suggested by Santa Clara that would only require the commencement of corrective control action within a 30-minute limit. We found that the requirement to take action without delay and within the 30-minute limit is important to minimize the amount of time the system operates in an insecure mode and is vulnerable to cascading outages.^[78]

w. Requests for Rehearing

102. Santa Clara seeks rehearing of the Commission's determination not to order the ERO to modify Reliability Standard IRO-001-1. Santa Clara is concerned that the 30-minute time period during which entities must take remedial action under this Reliability Standard could be too short with respect to physical actions that must be taken where the facilities which are subject to these actions cannot be readily accessed within the 30-minute time period.^[79]

103. First, Santa Clara maintains that the reliability coordinator could direct that load be dropped within Silicon Valley Power's (SVP) service territory.^[80] According to Santa Clara, those directives could only be implemented through a physical activity, such as opening breakers within certain substations, and cannot be accomplished at all times using an electronic signal from SVP's control center. Therefore, Santa Clara claims that, while SVP personnel would respond to the reliability coordinator's directive immediately, the required action might not be able to be accomplished within 30 minutes.

104. As another example, Santa Clara states that SVP has a program through which certain SVP retail customers can commit to reduce base load by 10 percent where an emergency exists in its control area. However, Santa Clara maintains that reducing load by shutting down power to specific buildings can take longer than 30 minutes. Santa Clara states that it is not seeking to have the language in IRO-001-1 modified as it requested in comments to the NOPR. Rather, it seeks to have the Commission grant rehearing to direct NERC to modify IRO-001-1 and allow Santa Clara to work with NERC to develop clarifications and refinements to IRO-001-1 to remedy its concerns.

105. Avista seeks clarification of the intent of Order No. 693 as to whether the authority of a reliability coordinator to issue directives to reliability entities arises out of (i) reliability coordinator contracts or (ii) Commission-approved Reliability Standards without reliance on reliability coordinator contracts. According to Avista, if the authority of a reliability coordinator is non-contractual and arises out of Commission-approved Reliability Standards, the Commission must make sure that such authority is accompanied by equitable treatment of reliability entities. For example, Avista states that the Commission should require equitable compensation for re-dispatch of generation required by the reliability coordinator and emphasizes the need for fair and impartial procedures and methodologies are adopted to ensure that such equitable treatment is provided.

106. Avista states the Commission's statement in Order No. 693 that it “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” ^[81] applies to existing agreements that affect reliability coordinator functions. According to Avista, provisions of IRO-001-1 seem to imply that, as to the source and scope of authority for a reliability coordinator to issue directives, existing contracts may have been superseded, or rendered moot or unnecessary, by Order No. 693. In particular, Avista contends that Requirement R8 of IRO-001-1 seems to suggest that contracts are unnecessary to authorize reliability coordinators to issue directives.^[82]

107. Avista asserts that, if transmission operators or balancing authorities or other reliability entities are subject to a non-contractual duty imposed by the Commission under Order No. 693 to comply with the directives of a reliability coordinator, the Commission should clearly indicate such a requirement. It notes that, in another proceeding, Western Electricity Coordinating Council (WECC) seems to suggest that it believes that when the reliability coordination Reliability Standards become mandatory, the existing contracts regarding reliability or security coordination no longer will be relevant and will not be necessary to authorize reliability coordinators to issue mandatory directives to reliability entities.^[83]

108. On the other hand, Avista maintains that additional provisions of IRO-001-1 suggest that reliability coordinators must have contracts or other written evidence in place that delineate and evidence their authority over reliability entities. For example, Avista cites measure M2 of IRO-001-1, which states that each reliability coordinator shall have and provide upon request evidence that could include, but is not limited to, job descriptions, signed agreements, an authority letter signed by an officer of the company, or other equivalent evidence that will be used to confirm that the reliability coordinator has the authority to act as described in Requirement 3. According to Avista, this provision suggests that the source of authority to issue directives lies in a contractual relationship between the reliability coordinator and each reliability entity covered by the requirements of Requirement R3.^[84] In Avista's view, the language in the Purpose section indicates that the purpose of IRO-001-1 is to establish authority of reliability coordinators over reliability entities through contracts, in addition to establishing internal authority through delegations of authority and plans presumably through Requirement R2.

109. Avista asserts that the security coordinator in the Pacific Northwest, PNSC, does not have contractual relationships with reliability entities other than control area operators. Avista contends that, if the authority of a reliability coordinator to issue directives to reliability entities arises out of reliability coordinator contracts, the reliability coordinator will need to enter into contractual relationships with each of the reliability entities within its area—which would expand the scope of and parties to the current PNSC contracts. Further, Avista states that existing contracts may not contain provisions regarding the authority of reliability coordinators to issue directives to reliability entities that fully track the Reliability Standards.^[85]

110. Therefore, Avista requests rehearing and asks that the Commission require that (1) reliability coordinators develop and file contracts or tariffs that govern their reliability coordination authority and activities, and (2) such contracts or tariffs ensure equitable treatment of reliability entities by reliability coordinators and provide adequate procedures and methodologies to help ensure such equitable treatment. Avista also seeks rehearing for the purpose of expanding the time to transition from the current, voluntary contractual arrangements to the arrangements contemplated by Order No. 693.

111. Specifically, Avista asserts that the Commission should require reliability coordinators to file such contracts or tariffs under section 205 of the FPA. In this regard, Avista states that the Commission should, as a first step, require reliability coordinators to submit for filing their existing contracts, such as the contracts between PNSC and the control area operators. According to Avista, filing of these contracts or tariffs under section 205 should ensure the equitable treatment of reliability entities, provide a mechanism for redress in the event of inequitable treatment, and provide a basis for the Commission's determination that the Reliability Standards approved by Order No. 693 are just and reasonable.

x. Commission Determination

112. In response to Avista, the Commission clarifies that a reliability coordinator's authority to issue directives arises out of the Commission's approval of Reliability Standards that mandate compliance with such directives. Avista is correct that contracts are unnecessary to authorize reliability coordinators to issue directives. Under the voluntary reliability scheme in place prior to section 215 of the FPA, a contractual basis was needed to assure that entities would comply with a reliability coordinator's directive. Pursuant to the current, mandatory reliability scheme established by statute, contracts are no longer needed. We view the concerns raised by Avista as part of the transition from a voluntary to mandatory scheme. Although, as noted by Avisa, IRO-001-1 retains references to contracts, we view these as vestiges of an earlier program that no longer control given the current, mandatory mechanism.

113. Avista's assertion that, if transmission operators, balancing authorities or other reliability entities are subject to a non-contractual duty imposed by the Commission under Order No. 693 to comply with the directives of a reliability coordinator, the Commission should have clearly indicated such a requirement, is not justified. First, the Commission believes that this duty was clearly laid out in the Reliability Standards themselves. However, the duty to comply with Reliability Standards is imposed by section 215 of the FPA, not by contract. The Reliability Standards approved by the Commission include requirements that certain users, owners and operators of the Bulk-Power System follow directions given by the reliability coordinators.^[86] The duty to follow such directions lies in the duty to comply with Reliability Standards as laid out in section 215 of the FPA and the Commission's regulations.

114. The Commission notes that Avista uses the Commission's statement that it “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” ^[87] for the proposition that the Commission did not intend to change or otherwise affect existing agreements about reliability coordinator functions. We disagree with Avista on this point. The Commission made this statement regarding the responsibility for functions in the Functional Model, especially regarding ISOs, RTOs or any organizations that pool resources. In that statement, we clarified that we were not changing any contract to which an ISO, RTO or pooled resource organization is a party as to who must comply with specific requirements of the Reliability Standards.

115. In response to Avista's arguments regarding Measure M2 of IRO-001-1, the Commission does not believe that this measure imposes a requirement that reliability coordinators must have contracts in place. Measure M-2 of IRO-001-1 requires each reliability coordinator to have and provide upon request evidence that it has the authority to have clear decision-making authority to act and to direct actions to be taken by certain users, owners and operators within its area to preserve the integrity and reliability of the bulk electric system. Neither the Reliability Standard nor the Commission prescribed the form of such evidence.

116. Avista's concerns regarding whether existing contracts, including those regarding the contracts with PNSC, and whether contracts, generally, have been superseded or rendered moot or unnecessary by Order No. 693 are beyond the scope of this proceeding. This proceeding established mandatory Reliability Standards, including those pertaining to directions by reliability coordinators. Reliability coordinator contracts are not before the Commission in this proceeding. Therefore, the Commission cannot rule here on any issue regarding such contracts.

117. The Commission denies Avista's request that the Commission require reliability coordinators to develop and file contracts or tariffs that govern their reliability coordination authority and activities. The Commission understands that reliability must be a primary goal. Each user, owner and operator of the Bulk-Power System must be in compliance with the Reliability Standards so that everyone can have the benefits of using the system. As stated above, the Reliability Standards do not prescribe the form through which each reliability coordinator must provide evidence of its clear decision-making authority to act and to direct actions to be taken by certain entities. To that end, it is unnecessary to require each reliability coordinator to file a contract or tariff.

118. We deny Santa Clara's request for rehearing. In Order No. 693, the Commission noted that various commenters provided specific suggestions to improve or otherwise modify a Reliability Standard that address issues not raised in the NOPR. In such circumstances, the Commission directed 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, did not direct any outcome other than that the comments receive consideration.^[88]

119. However, the Commission denied Santa Clara's specific request to modify Requirement R3 of IRO-001-1, explaining that, when system integrity or reliability is jeopardized, e.g., when IROLs or SOLs are exceeded, the relevant reliability entities must take corrective control actions to return the system to a secure and reliable state as soon as possible but not longer than 30 minutes.^[89] The Commission believes that this reaction time has been vetted through the industry and that the 30-minute time limit for action is important to minimize the amount of time the system operates in an insecure mode and is vulnerable to cascading outages.

6. IRO-005-1 and IRO-005-2

120. IRO-005-1 ensures energy balance and transmission reliability for the current day by identifying tasks that reliability coordinators must perform throughout the day. Order No. 693 approved Reliability Standard IRO-005-1.

y. Requests for Rehearing

121. TANC requests clarification as to whether the Commission intended to approve IRO-005-1 or IRO-005-2 in Order No. 693. Although the Commission states that it approves IRO-005-1,^[90] TANC notes that NERC submitted a later version, IRO-005-2, in its November filing. Therefore, TANC seeks clarification that the Commission intended to approve IRO-005-1, rather than the more recently filed IRO-005-2.

z. Commission Determination

122. The Commission grants TANC's request for clarification. As stated in Order No. 693, the Commission approved version one of IRO-005.^[91]

7. MOD-013-1

123. MOD-013-1 requires the regional reliability organizations within an Interconnection to develop comprehensive dynamics data requirements and reporting procedures needed to model and analyze the dynamic behavior and response of each Interconnection. More specifically, the regional reliability organization, in coordination with its transmission owners, transmission planners, generator owners and resource planners within an Interconnection, is required to: (1) Participate in development of documentation for their Interconnection data requirements and reporting procedures; (2) participate in the review of those data requirements and reporting procedures at least every five years; and (3) make the data requirements and reporting procedures available to NERC and other specified entities upon request.

124. Because MOD-013-1 is a fill-in-the-blank standard, the Commission stated that it will not approve or remand MOD-013-1 until the ERO submits additional information. However, the Commission directed the ERO to develop a modification to MOD-013-1 to (1) permit entities to estimate dynamics data if they are unable to obtain unit specific data for any reason; (2) require verification of the dynamic models with actual disturbance data and (3) expand the applicability section to include the planning authority, transmission operator and transmission planner.

aa. Requests for Rehearing

125. TANC requests that the Commission clarify that it erred in directing the ERO to apply MOD-013-1 to transmission operators and transmission planners. Although the Commission left Reliability Standard MOD-013-1 pending, TANC asserts that the Commission stated that it would adopt the NOPR proposal to expand the applicability section to include planning authorities, but in a later summary paragraph directed the ERO to apply the standard to transmission operators and transmission planners, in addition to planning authorities.^[92] TANC states that the inclusion of transmission operators and transmission planners was neither mentioned in the NOPR nor discussed in Order No. 693. In the alternative, TANC requests rehearing.

126. ISO-New England requests rehearing of the Commission's determination to (1) permit entities to estimate dynamics data if they are unable to obtain unit specific data for any reason; (2) require verification of the dynamic models with actual disturbance data; and (3) expand the applicability section to include the planning authority, transmission operator and transmission planner. ISO-New England states that the Commission's direction to the ERO to modify MOD-013-1 appears internally inconsistent with other positions the Commission took in Order No. 693. First, ISO-New England notes that the Commission required the ERO to modify MOD-013-1 because it would allow the use of estimated data but, at the same time, required “verification of the dynamic models with actual disturbance data.”

127. Second, ISO-New England observes that the Commission stated in Order No. 693 that “[f]ailure to provide the data needed for dynamics system modeling and simulation would halt regional reliability assessment processes and impede planners from accurately predicting future system conditions, which would be detrimental to system reliability.” ^[93] Further, ISO-New England points to the Commission's statement in Order No. 693 that it believes “to achieve the goal of this Reliability Standard of having the ability to accurately model and analyze the dynamic behavior and response of each Interconnection, it is necessary to have accurate data.” ^[94] In sum, ISO-New England argues that just as the Commission has recognized the importance of accurate data with respect to the administration of other NERC Reliability Standards, the Commission should equally recognize the importance with regard to MOD-013-1.

128. Further, ISO-New England argues that the Blackout Report suggests that actual data should be required.^[95] Specifically, ISO-New England points to the Blackout Report's recommendation to improve the quality of system modeling data and data exchange practices. ISO-New England notes that the Blackout Report indicates that “after-the-fact models developed to simulate August 14 conditions and events found that the dynamic modeling assumptions for generator and load power factors in regional planning and operating models were frequently inaccurate.” ^[96] Further, ISO-New England states that the Task Force commented that, during the investigation process, it too found that data was frequently not available.^[97] Consequently, ISO-New England maintains that the Task Force recommended the collection of validated data.^[98]

129. Finally, ISO-New England states that Order No. 693 leaves too much unclear in terms of its direction that entities should be permitted to estimate dynamics data if unit specific data is unavailable “for any reason.” According to ISO-New England, this exemption appears “overbroad” and could serve as the basis for an asset owner's rejection of any reasonable request for the unit specific data. ISO-New England requests that, if the Commission retains its direction to permit entities to estimate dynamics data, that it narrow the scope of the exemption that asset owners may employ in providing unit specific data.

bb. Commission Determination

130. The Commission denies TANC's request for rehearing. TANC correctly identifies that the Commission did not approve or remand MOD-013-1, but provided direction to the ERO concerning the addition of entities not already identified in the Reliability Standard. Although we acknowledge that Order No. 693 did not include a discussion of the addition of transmission operators and transmission planners in the applicability section of this Reliability Standard, in directing the ERO to apply MOD-013-1 to transmission operators and transmission planners, we recognized that transmission operators and transmission planners would be required to perform coordination functions under Requirement R1 of MOD-013-1. Therefore, the Commission directed the ERO to specifically include transmission operators and transmission planners in the applicability section of MOD-013-1 so as to be clear what the Commission considers to be the minimum applicability of this Reliability Standard and to make the Reliability Standard internally consistent.

131. In response to ISO-New England's concerns, the Commission notes that the data referenced in Requirement R1.1 include “items such as inertia constant, damping coefficient, saturation parameters, and direct and quadrature axis reactances and time constants, excitation systems, voltage regulators, turbine-governor systems, power system stabilizers, and other associated generation equipment.” Much of these data will be estimated from similar classes of facilities prior to the facilities going into service. The Commission clarifies that its determination to permit entities to estimate dynamics data if they are unable to obtain unit specific data for any reason is limited to the initial analysis of dynamics data. While we continue to believe that “[a]chieving the most accurate possible picture of the dynamic behavior of the Interconnection requires the use of actual data,” ^[99] we acknowledge that, in certain circumstances, actual data may not be initially available and only obtained through “verification of the dynamic models with actual disturbance data.” In addition, in Order No. 693, we determined that “the Reliability Standard should include Requirements that such estimates be based on sound engineering principles and be subject to technical review and approval of any estimates at the regional level.” ^[100] This procedure would allow peer review and approval at a regional level such that an entity could not avoid using sound engineering principles in obtaining the initial data for the model.

8. PRC-007-0, PRC-008-0, and PRC-009-0

132. PRC-007-0 requires transmission owners, transmission operators, load-serving entities and distribution providers to provide, and annually update, their underfrequency data to facilitate the regional reliability organization's maintenance of the UFLS program database.^[101] PRC-008-0 requires transmission owners and distribution providers to implement UFLS equipment maintenance and testing programs and provide program results to the regional reliability organization. PRC-009-0 ensures that the performance of a UFLS system is analyzed and documented following an underfrequency event by requiring the transmission owner, transmission operator, load-serving entity and distribution provider to document the deployment of their UFLS systems in accordance with the regional reliability organization's program. Order No. 693 approved Reliability Standards PRC-007-0, PRC-008-0,^[102] and PRC-009-0.^[103]

133. These Reliability Standards reference PRC-006-0, which the Commission did not approve or remand because the regional procedures required by the Reliability Standard had not been submitted and because it applies to regional reliability organizations.^[104] The Commission reasoned that since PRC-007-0, PRC-008-0, and PRC-009-0 are existing Reliability Standards that have been followed on a voluntary basis, transmission owners, transmission operators, distribution providers and load-serving entities are generally aware of their requirements. In addition, the Commission stated that a reference in an approved Reliability Standard to an unapproved Reliability Standard may be considered in an enforcement action, but is not a reason to delay approving and enforcing this Reliability Standard.

cc. Request for Rehearing

134. APPA requests rehearing of Commission approval of PRC-007-0, PRC-008-0, and PRC-009-0. As discussed more fully in the section concerning “Fill-in-the-Blank Standards above,^[105] APPA believes that each of these three Reliability Standards cannot be approved because it references a fill-in-the-blank standard that was not approved or remanded by the Commission.

135. According to APPA, PRC-006-0 is the Reliability Standard that requires the development of regional UFLS programs and contains detailed and exacting requirements that the regions develop and apply to applicable entities. According to APPA, PRC-006-0 is the source of the design and documentation of regional UFLS programs and is not merely administrative or a simple codification of established industry practice. Rather, APPA asserts that PRC-006-0 sets forth very specific requirements that each regional UFLS program must meet.

136. APPA asserts that PRC-007-0, PRC-008-0 and PRC-009-0 go much further than imposing data requirements. APPA states that PRC-007-0 requires, among other things, that any transmission owner and distribution provider with a UFLS program must ensure that its UFLS program is consistent with its regional reliability organization's UFLS program requirements. PRC-008-0 requires transmission owners and distribution providers to implement UFLS equipment maintenance and testing programs and provide program results to the regional reliability organization. Finally, APPA maintains that PRC-009-0 requires a transmission owner, transmission operator, load-serving entity, and distribution provider that owns or operates a UFLS program to analyze performance under that unapproved program. According to APPA, because the required UFLS program has not been approved or reviewed by the Commission under PRC-006-0, users, owners and operators of the Bulk-Power System cannot be required to have a program consistent with it.

137. APPA maintains that the fact that these three Reliability Standards apply to specific users, owners and operators of the Bulk-Power System, rather than a regional reliability organization, does not justify approval of a reliability standard that requires users, owners and operators of the Bulk-Power System to comply with regional UFLS programs that have not been approved by NERC, and have not been shown to meet the procedural and substantive requirements of section 215 of the FPA and Order No. 672 for Reliability Standards that qualify for approval and enforcement by the ERO and this Commission. Further, APPA contends that, although the Commission appears to have approved these Reliability Standards in part because they have “been followed on a voluntary basis,” many small entities have often not been part of regional reliability organizations and have not necessarily been aware of, much less followed, regional programs on a voluntary basis.

dd. Commission Determination

138. We deny APPA's request for rehearing and affirm our approval of Reliability Standards PRC-007-0, PRC-008-0 and PRC-009-0. However, as explained below, we clarify that the limited provisions that relate to the regional UFLS program developed under PRC-006-0 are not enforceable until the Commission approves PRC-006-0.^[106] Specifically, any entity that is responsible for compliance with PRC-007-0, PRC-008-0 or PRC-009-0 that currently does not have a UFLS program is not required to develop such a program until PRC-006-0 is approved. Likewise, a responsible entity with an existing UFLS program is not required to comply with a regional UFLS program until the Commission approves PRC-006-0. An explanation for this determination follows.

139. Each of the requirements in PRC-007-0, PRC-008-0 and PRC-009-0, with the exception of Requirement R1 in PRC-007-0, apply only to those entities that have a UFLS program. Therefore, contrary to APPA's assertion, PRC-007-0, PRC-008-0 and PRC-009-0 do not require any entity that does not have a UFLS program to develop one. That requirement would fall under PRC-006-0. To be clear, the Commission will not impose a penalty for the failure to have a UFLS program until such time as PRC-006-0 or a suitable substitute, and the attendant regional UFLS programs, are approved.

140. However, we disagree with APPA that the fact that Requirement R1 references the regional UFLS program precludes us from approving PRC-007-0, PRC-008-0 and PRC-009-0, which provide for updating an entity's UFLS program (PRC-007-0), maintaining the entity's UFLS facilities (PRC-008-0), and reporting on events that involve the entity's UFLS (PRC-009-0). Rather, we uphold our earlier decision to approve these three Reliability Standards with the clarification that Requirement R1 of PRC-007-0 is not enforceable until the Commission approves PRC-006-0. We further clarify, consistent with our discussion above, that, until PRC-006-0 is approved, an entity that does not currently have a UFLS program is not required to develop one or to comply with PRC-007-0, PRC-008-0 and PRC-009-0. However, an applicable entity that currently has a UFLS program must continue to maintain that program as required by these three Reliability Standards. As discussed below, the Requirements of PRC-007-0, PRC-008-0 and PRC-009-0 are necessary for Bulk-Power System reliability and are not dependent on PRC-006-0.

141. PRC-007-0, Requirement R2 states that the applicable entities “shall provide, and annually update, its underfrequency data as necessary for its Regional Reliability Organization to maintain and update a UFLS program database.” ^[107] It is vital to maintain this safety net that each registered transmission owner, transmission operator, distribution provider and load-serving entity with a UFLS system has a program to annually review the location of their UFLS devices and the magnitude of load that can be collectively activated as necessary.^[108] The reason for the annual review is that it is not unusual for loads to be switched among distribution feeders and, with load growth, additional distribution feeders may need to be included to meet the requirements of the entities' UFLS program. In addition, it is necessary to verify that sensitive and critical loads such as hospitals and high impact facilities continue to be excluded from the load shedding program. While it may be necessary to shed load to preserve the Bulk-Power System, it is also good public policy to limit the nature of the facilities that could be interrupted.

142. PRC-008-0, Requirement R1 states that the applicable entities “shall have a UFLS equipment maintenance and testing program in place.” These programs are in place to assure that this last resort system, which has been proven to be necessary to limit the geographic scope of blackouts, operates as expected when required to in accordance with the reliability assessments.

143. PRC-009-0, Requirement R1 identifies what analysis must be completed by the applicable entities after an underfrequency event. It states that “[t]he analysis shall address the performance of UFLS equipment and program effectiveness following system events resulting in system frequency excursions below the initializing set points of the UFLS program.” This requirement assures that actual data on the operation of the UFLS system can be correlated with simulations to provide a check on how well the UFLS system is performing its last resort function.

144. Requirement R1 of PRC-007-0 requires the transmission owner and distribution provider to “ensure that its UFLS program is consistent with its Regional Reliability Organization's UFLS program requirements.” Because the regional UFLS program would be developed pursuant to PRC-006-0, and the Commission has not approved or remanded that Reliability Standard, we agree with APPA that Requirement R1 cannot be enforced as written until the Commission approves PRC-006-0, because Requirement R1 would essentially require compliance with an unapproved Reliability Standard. Because Requirement R1 of PRC-007-0 is not enforceable until the Commission approves PRC-006-0, a transmission owner's or distribution provider's UFLS program cannot be judged for compliance with the unapproved regional UFLS program.

145. While the Commission will not enforce compliance with PRC-006-0, the possible reduction in the amount of load available for underfrequency load shedding can negatively impact the Reliable Operation of the Bulk-Power System. Because of the importance of the UFLS programs and the fact that there currently are no Commission-approved Reliability Standards by which to judge individual UFLS programs, the Commission believes it is important to monitor the current UFLS programs so that we can consider if they provide an adequate safety net for the Bulk-Power System. Therefore, the Commission directs the ERO to collect the frequency and magnitude of load in UFLS systems from applicable entities for this summer, from date of order through September 30, 2007, and perform an analysis as to the ability of the existing system to provide the required last resort function within 90 days of this order. This analysis should consider if the existing UFLS plans together provide an adequate safety net for the Bulk-Power System.

146. In discussing potential ambiguities in the proposed Reliability Standards in Order No. 693, the Commission stated 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.^[109] We believe that this principle applies equally to a Reliability Standard where one Requirement may not be enforceable, but the Reliability Standard must be approved to enable enforcement of other Requirements.

147. The reliability goal of PRC-007-0, PRC-008-0 and PRC-009-0 is to provide last resort system preservation measures by implementing an UFLS program. The Commission believes that this is an important reliability goal. The Commission understands that, until PRC-006-0 is approved, the UFLS program implemented will not be the one envisioned in PRC-006-0. We believe that, where a user, owner or operator does have a UFLS program, the data retention and reporting requirements incorporated in these Reliability Standards serve an extremely important goal of providing last resort system preservation measures. NERC can analyze the information to monitor whether the last resort system preservation measures are sufficient in the aggregate for the entire Bulk-Power System. Although the ERO and Regional Entities cannot penalize a user, owner or operator for an insufficient UFLS program until the Commission approves PRC-006-0, collection, analysis and submission of the UFLS information described above will provide NERC and the Commission with invaluable information regarding the reliability of the Bulk-Power System.

148. We further believe that, other than R1 in Reliability Standard PRC-007-0, the Requirements in the PRC Reliability Standards are independently enforceable. For example, R2 of Reliability Standard PRC-007-0 requires a transmission owner or distribution provider with a UFLS program to provide, and annually update, its underfrequency data. Although R2 contains the phrase “(as required by its Regional Reliability Organization),” the Commission believes that it is of vital importance for the transmission owner and distribution provider to update its UFLS data annually and provide it to the ERO. Because we have not approved any regional programs, this parenthetical currently has no meaning in the context of the approved Reliability Standard. Therefore, the Commission believes that these three Reliability Standards only apply to those entities that have a UFLS program, irrespective of whether a region requires it.

149. The Commission also denies rehearing of our approval of PRC-008-0. This Reliability Standard requires each transmission owner and distribution provider with a UFLS program to have a UFLS program in place that includes UFLS equipment identification and the schedule for UFLS equipment testing and maintenance. PRC-008-0 further requires each transmission owner and distribution provider with a UFLS program to implement its UFLS equipment maintenance and testing program and provide UFLS maintenance and testing program results to its regional reliability organization and NERC on request. In this Reliability Standard, any transmission owner or distribution provider that already has a UFLS program must develop its own equipment maintenance and testing program that complies with PRC-008-0. The Commission believes it is of great importance to Bulk-Power System reliability for such entities to perform such maintenance and testing. Because the maintenance and testing programs do not rely on regional reliability organization requirements, but are, rather, developed by the applicable entity itself, the Commission continues to believe that this Reliability Standard is enforceable regardless of whether the Commission has approved PRC-006-0.

150. Finally, the Commission does not believe that the fact that PRC-006-0 has not been approved or remanded necessitates granting rehearing of our approval of PRC-009-0. This Reliability Standard requires a transmission owner, transmission operator, load-serving entity and distribution provider that owns or operates a UFLS program to analyze and document its UFLS program performance in accordance with its regional reliability organization's UFLS program. The Commission acknowledges, as stated above, that currently there is no Commission-approved UFLS program. However, R1 of PRC-009-0 also includes independent criteria by which a user, owner or operator of the Bulk-Power System must analyze its UFLS program. R1 states that:

The analysis shall address the performance of UFLS equipment and program effectiveness following system events resulting in system frequency excursions below the initializing set points of the UFLS program. The analysis shall include, but not be limited to:

R1.1. A description of the event including initiating conditions.

R1.2. A review of the UFLS set points and tripping times.

R1.3. A simulation of the event.

R1.4. A summary of the findings.

151. R2 of PRC-009-0 further requires the transmission owner, transmission operator, load-serving entity and distribution provider to provide documentation of the analysis of the UFLS program to its regional reliability organization and NERC on request after a system event. This analysis will better enable NERC to analyze system events and determine what actions need to be taken to ensure the Reliability of the Bulk-Power System.

152. Therefore, the Commission denies rehearing of our approval of PRC-007-0, PRC-008-0 and PRC-009-0. To be clear, we recognize that R1 of PRC-007-0 is not enforceable until the Commission approves PRC-006-0. Because, prior to that approval of PRC-006-0, PRC-007-0, PRC-008-0 and PRC-009-0 only apply to those entities that already have a UFLS program, these Reliability Standards do not require any entity that does not have a UFLS program to develop one, and the Commission will not impose a penalty for an entity's failure to have a UFLS program until the Commission approves PRC-006-0. Further, until PRC-006-0 has been approved, a UFLS program cannot be judged for compliance with an unapproved regional UFLS program. Therefore, the Commission clarifies that, until PRC-006-has been approved, only the data retention and reporting requirements, as well as the requirements for maintenance, testing requirements and analysis of UFLS performance following a triggering event in PRC-007-0, PRC-008-0 and PRC-009-0, are mandatory and enforceable.

9. TOP-008-1

153. TOP-008-1 requires a transmission operator to take immediate steps to mitigate System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) violations. Order No. 693 approved Reliability Standard TOP-008-1.^[110] Order No. 693 summarized TOP-008-1 as requiring a transmission owner to take immediate steps to mitigate SOL and IROL violations.^[111]

ee. Requests for Rehearing

154. TANC requests clarification that the Commission intended to use the term transmission operator, rather than transmission owner, as the correct applicable entity in Reliability Standard TOP-008-1.^[112] TANC states that the text of the ERO-proposed Reliability Standard lists the transmission operator as the only entity to which TOP-008-1 applies. Alternatively, TANC requests rehearing.

ff. Commission Determination

155. The Commission will grant TANC's request for clarification. TANC is correct that the Commission's use of the term transmission owner, rather than transmission operator, was in error. The transmission operator is the correct applicable entity in Reliability Standard TOP-008-1.

III. Information Collection Statement

156. Order No. 693 contains information collection requirements for which the Commission obtained approval from the Office of Management and Budget (OMB). Given that this Order on Rehearing does not revise the regulation text of Order No. 693 and makes only minor clarifications to Order No. 693, OMB approval for this order is not necessary. However, the Commission will send a copy of this order to OMB for informational purposes.

IV. Document Availability

157. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

158. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number, excluding the last three digits of this document, in the docket number field.

159. User assistance is available for eLibrary and the FERC's Web site during normal business hours from our Help line at [phone] or the Public Reference Room at [phone] Press 0, TTY [phone]. E-Mail the Public Reference Room at [e-mail].

By the Commission.

Kimberly D. Bose,

Secretary.

Footnotes

1.  Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16,416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242 (2007).

2.  16 U.S.C. 824o (2000).

3.  U.S.-Canada Power System Outage Task Force, Final Report on the August 14 Blackout in the United States and Canada: Causes and Recommendations (April 2004) (Blackout Report). The Blackout Report is available on the Internet at http://www.ferc.gov/​cust-protect/​moi/​blackout.asp.

4.  Order No. 693 at P 75.

5.  Id. at P 221-22.

6.  18 CFR 385.713(c)(2) (2006). See Revision of Rules of Practice and Procedure Regarding Issue Identification, Order No. 663, 70 FR 55,723 (September 23, 2005), FERC Stats. and Regs. ¶ 31,193 (2005). See also, Order 663-A, effective March 23, 2006, which amends Order No. 663 to limit its applicability to rehearing requests. Revision of Rules of Practice and Procedure Regarding Issue Identification, Order No. 663-A, 71 FR 14,640 (March 23, 2006), FERC Stats. and Regs. ¶ 31,211 (2006) (codified at 18 CFR 385.713(c)(2) (2006)).

7.  As explained in Order No. 663, supra, the purpose of this requirement is to benefit all participants in a proceeding by ensuring that the filer, the Commission, and all other participants understand the issues raised by the filer, and to enable the Commission to respond to these issues. Having a clearly articulated Statement of Issues ensures that issues are properly raised before the Commission and avoids the waste of time and resources involved in litigating appeals regarding whether the courts of appeals lack jurisdiction because the issues on appeal were not clearly identified before the Commission. See Order No. 663 at P 3-4.

8.  See, e.g., Duke Power Co., LLC, 116 FERC ¶ 61,171 (2006); and South Carolina Electric & Gas Co., 116 FERC ¶ 61,218 (2006).

9.  Order No. 693 at P 75.

10.  Id. at P 76.

11.  NRECA at 7-11, citing United States v. Public Utilities Commission of California, 345 U.S. 295, 315 (1953).

12.  NRECA at 7-8.

13.  Id. at 11-16, citing Morissette v. United States, 342 U.S. 246, 263 (1952).

14.  NRECA at 16.

15.  NARUC at 3. NARUC refers repeatedly to “NERC's definition of Bulk-Power System.” It is not clear from NARUC's pleading whether this is simply a typographical error or it seeks to make a point that NERC's definition of bulk electric system is equivalent to the statutory term Bulk-Power System.

16.  See Mandatory Reliability Standards for the Bulk Power System, Notice of Proposed Rulemaking, 71 FR 64,770 (Nov. 3, 2006), FERC Stats. & Regs., ¶ 32,608 at P 63 (2006).

17.  Order No. 693 at P 92-101.

18.  Id. at P 95.

19.  18 CFR 292.601(c) (2006).

20.  Applicability of Federal Power Act Section 215 to Qualifying Small Power Production and Cogeneration Facilities, Order No. 696, FERC Statutes and Regulations ¶ 31,248 (2007).

21.  California Cogeneration at 5, Referencing WECC Supplemental Registration Criteria and Dispute Resolution Process, available at http://www.wecc.biz.

22.  NRECA at 20-23. Specifically, NRECA cites the Commission's requirement that (1) COM-001-1, or some replacement Reliability Standard addressing black start capability, and COM-002-2 apply to all distribution providers, (2) TOP-003-0 apply to all load-serving entities, even those below specified thresholds, based on the opinion of the transmission operator, balancing authority, or reliability coordinator, and (3) VAR-001-1 apply to all load-serving entities. See Order No. 693 at P 487, 492, 512, 540, 1624, 1626, 1848, 1858 and 1990.

23.  NRECA at 20, citing see, e.g., Order No. 693 at P 512 (“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 discussed above, we are approving NERC's registry process, including the registry criteria”).

24.  Order No. 693 at P 185-86.

25.  Id. at P 145.

26.  California Cogeneration at 12, citing California Independent System Operator, Corp., 96 FERC ¶ 63,015 (2001) (Initial Decision); Opinion No. 464, 104 FERC ¶ 61,196 (2003) (affirming Initial Decision).

27.  See Order No. 693 at P 101; ERO Certification Order at P 679.

28.  We note that the example cited by California Cogeneration appears to assert that the NERC registry criteria incorporates a bright line test as to which entities should be registered:

The application of the different sets of criteria to a 30 MW generator interconnected at 69 kv illustrates the inconsistency in treatment. Under NERC's criteria, the generator is interconnected at less than 100 kv, and it is not therefore a user of the bulk electric system. The generator would be eliminated from registration by the first step of NERC's process. WECC's Supplemental Criteria, however, state that a generator greater than 20 MW must be registered regardless of the voltage at which it is interconnected.

California Cogeneration at 5. We disagree with this interpretation. NERC's compliance registry would also allow the ERO and Regional Entities to register “[a]ny generator, regardless of size, that is a blackstart unit material to and designated as part of a transmission operator entity's restoration plan, or; * * * [a]ny generator, regardless of size, that is material to the reliability of the bulk power system.” NERC Statement of Compliance Registry at 7.

29.  Order No. 693 at P 33.

30.  NERC Statement of Compliance Registry at 10, n.1.

31.  The entity registered would also have to be a user, owner or operator of NERC's definition of bulk electric system.

32.  The Commission notes that no Regional Entity has filed a supplemental registry with the Commission. The Commission makes its determination to reject regional registry criteria without prejudice to a Regional Entity creating supplemental registry criteria, provided that the Regional Entity affords due process to those entities that would be subject to them, and requests ERO and Commission approval of such criteria.

33.  Order No. 693 at P 185.

34.  Id. at P 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.”

35.  See id. at P 107.

36.  See id. at P 107-09.

37.  Order No. 696 at P 28.

38.  Order No. 693 at P 127-29.

39.  Midwest ISO at 4.

40.  Order No. 693 at P 127.

41.  Id. at P 1893.

42.  Id. at P 129.

43.  Id. at P 207.

44.  Id.

45.  NRECA at 17.

46.  Id. at 18.

47.  North American Electric Reliability Corp., 118 FERC ¶ 61,030 at P 27 (2007) (January 2007 Compliance Order) (emphasis added).

48.  North American Electric Reliability Corp., 119 FERC ¶ 61,046 at P 13 (2007).

49.  Order No. 693 at P 207.

50.  Id. at P 221-22.

51.  Id.

52.  Id. at P 237; Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12,266 (March 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007) at P 1671-77.

53.  U.S.-Canada Power System Outage Task Force, Final Report on Implementation of Task Force Recommendations at 22 (Oct. 3, 2006), available at http://www.oe.energy.gov/​news/​blackout.htm (“Action Required to Fully Implement Recommendation 8: No further action under this recommendation is needed.”).

54.  Id. (“In the United States, some state regulators have informally expressed the view that there is appropriate protection against liability suits for parties who shed load according to approved guidelines”).

55.  Order No. 888-B, 81 FERC ¶ 61,248 at 62,081 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

56.  Avista and PSE also requested rehearing of this issue in Docket Nos. RM05-25-001 and RM05-17-001.

57.  Order No. 890 at P 1675. We note that this discussion concerns civil liability only, not liability for penalties imposed by the ERO, Regional Entities or the Commission.

58.  Id. at P 1677.

59.  Policy Statement on Matters Related to Bulk Power System Reliability, 107 FERC ¶ 61,052 (2004) (Reliability Policy Statement).

60.  Reliability Policy Statement at P 40 (citations omitted).

61.  112 FERC ¶ 61,100 at P 39 (2005).

62.  113 FERC ¶ 61,239 at P 7 (2005).

63.  Order No. 693 at P 297-302.

64.  Id. at P 302 (footnote omitted).

65.  Id. at P 300.

66.  See discussion of PRC-007, PRC-008, and PRC-009, infra.

67.  This is similar to our action in Order No. 693, where we approved certain Reliability Standards, but acknowledged that a particular requirement may be unenforceable. See Order No. 693 at P 147, 157-58.

68.  Id. at P 566.

69.  Order No. 693 at P 583.

70.  Id. at P 672.

71.  See Order No. 693 at P 659.

72.  Id. at P 735.

73.  NRECA at 23, citing Order No. 693 at P 706 (“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”).

74.  NRECA at 23, citing Order No. 693 at P 711.

75.  Order No. 693 at P 706.

76.  Id. at P 185-86.

77.  The Commission notes that the Regional Entities have since filed their definitions of bulk electric system and that at least one Regional Entity, WECC, has designated lower voltage facilities that must comply with the Reliability Standards.

78.  Id. at P 898.

79.  In its comments to the NOPR, Santa Clara requested that this requirement of IRO-001-1 be revised to read: “Actions shall be commenced without delay, but in any event, shall commence within 30 minutes.” Santa Clara Comments, December 28, 2006 at 30.

80.  SVP is the utility division of Santa Clara.

81.  Order No. 693 at P 141.

82.  Requirement R8 states: “R8. Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply with Reliability Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory requirements. Under these circumstances, the Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, or Purchasing-Selling Entity shall immediately inform the Reliability Coordinator of the inability to perform the directive so that the Reliability Coordinator may implement alternate remedial actions.”

83.  Supplemental Comments of the Western Electricity Coordinating Council (WECC) filed March 12, 2007, in Docket No. RR06-3-001 at 13 (“Currently the BAs [balancing authorities] and TOPs [transmission operators] have a contractual obligation to comply with such directives, except in narrow, enumerated circumstances. Once the reliability standards are mandatory, BAs and TOPs must obey such directives or be subject to major penalties or other sanctions.”) (footnote omitted).

84.  Requirement R3 states, “The Reliability Coordinator shall have clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generation Operators, Transmission Service Providers, Load Serving Entities and Purchasing-Selling Entities within its Reliability Coordinator Area to preserve the integrity and reliability of the Bulk Electric System.”

85.  For example, Avista contends that Requirements R8 and R3 of IRO-001-1, when read together, contain very broad language.

86.  For example, Requirement R9 of IRO-001-1 states that transmission operators, balancing authorities, generator operators, transmission service providers, load-serving entities, and purchasing-selling entities shall comply with Reliability Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory requirements.

87.  Order No. 693 at P 141.

88.  See id. at P 188.

89.  Id. at P 898.

90.  See Id. at P 945, 951.

91.  The Commission notes that many provisions of IRO-005-2 only become effective when BAL-002 is retired. If and when NERC proposes to retire BAL-002, we will make a determination on IRO-005-2.

92.  Compare Order No. 693 at P 1199; 1200.

93.  Id. at P 1177.

94.  Id. at P 1188.

95.  ISO-New England at 4, citing Blackout Report at 160-61.

96.  Blackout Report at 160.

97.  Id. at 161.

98.  ISO-New England at 4, citing Blackout Report at 160-61.

99.  Order No. 693 at P 1197.

100.  Id.

101.  A UFLS program is a “safety net” that will automatically drop load at specific locations in the power system in an effort to re-establish the balance between generation and load to avoid cascading.

102.  The Commission also directed the ERO to develop a modification to PRC-008-0 that includes a requirement that maintenance and testing of a protection system must be carried out within a maximum allowable interval that is appropriate to the type of the protection system and its impact on the reliability of the Bulk-Power System. The Commission's direction to modify PRC-008-0 is not at issue in this proceeding.

103.  Order No. 693 at P 1484, 1491, and 1498.

104.  Id. at P 1479.

105.  See section II.C.2., 2. Fill-in-the-Blank Standards, supra.

106.  Such provisions would similarly be enforceable if NERC develops and the Commission approves a substitute for PRC-006-0.

107.  While Requirement R2 identifies the regional reliability organization, we note that this information should go to the Regional Entity or the ERO as the entities with statutory authority under section 215 of the FPA.

108.  Blackout Report at 62.

109.  Order No. 693 at P 277. See also Order No. 693 at P 147, 157-58, explaining that the Commission was approving and requiring modification to five Reliability Standards that apply partially to a regional reliability organization.

110.  Id. at P 1679.

111.  See id. at P 1675.

112.  See id.