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Electric Reliability Organization Interpretations of Specific Requirements of Frequency Response and Bias and Voltage and Reactive Control Reliability Standards

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Start Preamble Issued May 21, 2009.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

Pursuant to section 215 of the Federal Power Act, the Federal Energy Regulatory Commission hereby approves the North American Electric Reliability Corporation's (NERC) interpretation of one Commission-Start Printed Page 25414approved Reliability Standard, BAL-003-0, Frequency Response and Bias; and remands NERC's proposed interpretation of VAR-001-1, Voltage and Reactive Control, for reconsideration consistent with this Final Rule.

DATES:

Effective Date: The Final Rule will become effective June 29, 2009.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Patrick Harwood (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Telephone: (202) 502-6125, Patrick.harwood@ferc.gov.

Richard M. Wartchow (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Telephone: (202) 502-8744.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

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

Final Rule

Issued May 21, 2009

1. Pursuant to section 215 of the Federal Power Act (FPA), the Commission hereby approves the interpretation proposed by the North American Electric Reliability Corporation (NERC) of Commission-approved Reliability Standard BAL-003-0, Frequency Response and Bias, but remands NERC's proposed interpretation of Reliability Standard VAR-001-1, Voltage and Reactive Control, for additional clarification.[1]

I. Background

A. EPAct 2005 and Mandatory Reliability Standards

2. Section 215 of the FPA requires a Commission-certified Electric Reliability Organization (ERO) to develop mandatory and enforceable Reliability Standards, which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO, subject to Commission oversight, or by the Commission independently.[2]

3. Pursuant to section 215 of the FPA, the Commission established a process to select and certify an ERO [3] and, subsequently, certified NERC as the ERO.[4] On April 4, 2006, as modified on August 28, 2006, NERC submitted to the Commission a petition seeking approval of 107 proposed Reliability Standards. On March 16, 2007, the Commission issued a Final Rule, Order No. 693, approving 83 of these 107 Reliability Standards and directing other action related to these Reliability Standards.[5] In addition, pursuant to section 215(d)(5) of the FPA, the Commission directed NERC to develop modifications to 56 of the 83 approved Reliability Standards.[6]

4. NERC's Rules of Procedure provide that a person that is “directly and materially affected” by Bulk-Power System reliability may request an interpretation of a Reliability Standard.[7] In response to a request, the ERO's standards process manager assembles a team with relevant expertise to address the requested interpretation and forms a ballot pool. NERC's Rules provide that, within 45 days, the team will draft an interpretation of the Reliability Standard, with subsequent balloting. If approved by ballot, the interpretation is appended to the Reliability Standard and filed with the applicable regulatory authority for approval.[8]

B. NERC Filing

5. On July 28, 2008, NERC submitted a Petition for Approval of Formal Interpretations to Reliability Standards (Petition), seeking Commission approval of interpretations of BAL-003-0, Requirements R2 and R5; and VAR-001-1, Requirement R4.

6. For BAL-003-0, the Electric Reliability Council of Texas (ERCOT) requested clarification that the provision in BAL-003-0, Requirement R2, permitting use of a variable bias setting, did not conflict with BAL-003-0, Requirement R5, which states that the frequency bias setting for Balancing Authorities serving native load should be at least one percent of yearly peak demand. For VAR-001-1, Dynegy, Inc. (Dynegy) requested clarification whether there are implicit requirements that the voltage schedule and associated tolerance band to be provided by the transmission operator under Requirement R4 be technically based, reasonable and practical for a generator to maintain.

7. Consistent with the NERC Rules of Procedure, a NERC-assembled ballot body, consisting of industry stakeholders, developed the interpretations using the NERC Reliability Standards Development Procedure,[9] and the NERC Board of Trustees approved the interpretations.[10] The interpretations do not modify the language contained in the requirements under review. NERC requested the Commission to approve the interpretations, effective immediately after approval, consistent with the Commission's procedures.

C. NOPR

8. In Response, the Commission issued a Notice of Proposed Rulemaking and proposed to approve the ERO's formal interpretation of Requirements R2 and R5 of BAL-003-0 but remand the proposed interpretation of VAR-001-1, and requested comment on its proposals.[11]

II. Discussion

A. Procedural Matters

9. NERC, Ameren Services Co. (Ameren), Edison Electric Institute (EEI), FirstEnergy Service Co. (FirstEnergy) and The Independent Electricity System Operator of Ontario (IESO) [12] filed comments, largely addressing the Commission's proposal to remand the proposed interpretation of VAR-001-1.

B. BAL-003-0

1. NOPR Proposal

10. BAL-003-0, Requirement 2 states that a “Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authority's Frequency Response.” BAL-003-0, Start Printed Page 25415Requirement 5 states that “Balancing Authorities that serve native load [such as ERCOT] shall have a monthly average Frequency Bias Setting that is at least one percent of the Balancing Authority's estimated yearly peak demand per 0.1 Hz change.” ERCOT requested clarification whether there is a conflict between BAL-003-0, Requirement R2, and BAL-003-0, Requirement R5. In response, NERC proposed the following interpretation:

Frequency Response and Bias Requirement 2 requires a Balancing Authority to analyze its response to frequency excursions as a first step in determining its frequency bias setting. The Balancing Authority may then choose a fixed bias (constant through the year) per Requirement 2.1, or a variable bias (varies with load, specific generators, etc.) per Requirement 2.2.

Frequency Response and Bias Requirement 5 sets a minimum contribution for all Balancing Authorities toward stabilizing interconnection frequency. The 1% bias setting establishes a minimum level of automatic generation control action to help stabilize frequency following a disturbance. By setting a floor on bias, Requirement 5 also helps ensure a consistent measure of control performance among all Balancing Authorities within a multi-Balancing Authority interconnection. However, ERCOT is a single Balancing Authority interconnection. The bias settings ERCOT uses do produce, on average, the best level of automatic generation control action to meet control performance metrics. The bias value in a single Balancing Authority interconnection does not impact the measure of control performance.

11. In the NOPR, the Commission proposed to find NERC's interpretation of BAL-003-0, Requirements R2 and R5 to be reasonable in providing consistency in frequency bias setting determinations, used in area control error (ACE) calculations.[13] The Commission viewed the interpretation as consistent with an earlier, Order No. 693 finding that the requirements of BAL-003-0 do not conflict with one another.[14] In Order No. 693, the Commission found that Requirement R2 provides the relationship between frequency response and frequency bias, with frequency bias to be as close as practical to, or greater than, the balancing authority's frequency response. Requirements R5 and R5.1 require balancing authorities to establish frequency bias settings based on one percent of peak demand or maximum generation level, based on individual circumstances.[15]

12. The Commission proposed to approve the interpretation, since the BAL-003-0, Requirement R5 minimum bias setting establishes a consistent methodology for an ACE determination input, and ensures that an adequate level of generation is set aside to provide frequency response.[16] The Commission declined to address the issue whether the ERCOT methodology, reported to result in “the best level of automatic generation control action to meet control performance metrics,” may be a preferable methodology, noting that such an issue is better resolved through a proceeding to review a proposal to permit ERCOT to depart from the requirement. The Commission noted that while ERCOT is a single-balancing-authority Interconnection and, therefore, does not need to allocate automatic generation control responsibility among multiple balancing authorities within the Interconnection, the other justifications for Requirement R5, supporting a consistent ACE calculation methodology and providing a minimum standard for reliability, remain valid justifications for the minimum setting.[17]

2. Comments

13. No participant filed comments opposing the BAL-003-0 interpretation.

3. Commission Determination

14. The ERO's interpretation clarifies that the BAL-003-0 Requirements R2 and R5 do not conflict with one another. In Order No. 693, the Commission made clear that a frequency bias setting based only on the value set forth in Requirement R5 is insufficient and that a balancing authority must also follow Requirement R2.[18] ERCOT presents the reverse question, whether a balancing authority that follows the variable bias setting under Requirement R2 must also follow Requirement R5. In response, NERC's interpretation affirms that a balancing authority that uses the variable bias option provided under Requirement R2 must also follow Requirement R5. In addition, no comments were filed opposing the Commission's proposal to approve NERC's BAL-003-0 interpretation.

15. Accordingly, we approve NERC's BAL-003-0 interpretation. The Commission finds that the ERO's interpretation is just, reasonable, not unduly discriminatory or preferential, and in the public interest.

C. VAR-001-1

1. NOPR Proposal

16. VAR-001-1, Requirement R4 directs each transmission operator to provide each generator with a voltage and reactive power output schedule, within a tolerance band. A second Reliability Standard, VAR-002-1, Requirement R2, requires that each generator must meet the schedule (typically via automatic control) or provide an explanation why it cannot do so. The Requirements state:

VAR-001-1—Voltage and Reactive Control.

Requirement R4. Each Transmission Operator shall specify a voltage or Reactive Power schedule [19] at the interconnection between the generator facility and the Transmission Owner's facilities to be maintained by each generator. The Transmission Operator shall provide the voltage or Reactive Power schedule to the associated Generator Operator and direct the Generator Operator to comply with the schedule in automatic voltage control mode (AVR [automatic voltage regulation] in service and controlling voltage). * * *

VAR-002-1—Generator Operation for Maintaining Network Voltage Schedules.

Requirement R2. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive Power output (within applicable Facility Ratings) [20] as directed by the Transmission Operator.

R2.1. When a generator's automatic voltage regulator is out of service, the Generator Operator shall use an alternative method to control the generator voltage and reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator.

R2.2. When directed to modify voltage, the Generator Operator shall comply or provide an explanation of why the schedule cannot be met.

17. Dynegy requested clarification whether there are implicit requirements that the voltage schedule and associated tolerance band to be provided by the transmission operator under VAR-001-1, Requirement R4 be technically based, Start Printed Page 25416reasonable and practical for a generator to maintain. In response, NERC proposed the following interpretation:

NERC Reliability Standard VAR-001-1 is only comprised of stated requirements and associated compliance elements. The requirements have been developed in a fair and open process, balloted and accepted by FERC for compliance review. Any “implicit” requirement would be based on subjective interpretation and viewpoint and therefore cannot be objectively measured and enforced. Any attempt at “interpreting an implicit requirement” would effectively be adding a new requirement to the standard.

This can only be done through the [Standards Authorization Request] process.

Since there are no requirements in VAR-001-1 to issue a “technically based, reasonable and practical to maintain voltage or reactive power schedule and associated tolerance band,” there are no measures or associated compliance elements in the standard.

The standard only requires that “Each Transmission Operator shall specify a voltage or Reactive Power schedule. * * *” and that “The Transmission Operator shall provide the voltage or Reactive Power schedule to the associated Generator Operator and direct the Generator Operator to comply with the schedule. * * *” Also, Measure 1 and the associated compliance elements follow accordingly by stating that “The Transmission Operator shall have evidence it provided a voltage or Reactive Power schedule * * *”

* * * * *

Requirement 2 and Requirement 2.2 of VAR-002-1 relate somewhat to questions #2 and 3. R2 states that “Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive Power output (within applicable Facility Ratings) as directed by the Transmission Operator.” R2.2 goes on to state “When directed to modify voltage, the Generator Operator shall comply or provide an explanation of why the schedule cannot be met.” [footnotes omitted.]

18. NERC provided additional information in its transmittal letter accompanying the interpretation, noting that VAR-001-1, Requirement R2 states, “Each Transmission Operator shall acquire sufficient reactive resources within its area to protect the voltage levels under normal and Contingency conditions.” NERC explained that, in order to fulfill Requirement R2, the transmission operator must perform a valid analysis of the system, using models that accurately represent equipment capabilities. Therefore, while NERC supported its interpretation of Requirement R4, including the finding that a requirement cannot establish implicit obligations, it stated that the issue that Dynegy raised for clarification is better resolved through an examination of Requirement R2.[21]

19. In response, the Commission proposed to remand NERC's interpretation of VAR-001-1, Requirement R4, because the interpretation suggested that there is no requirement that a voltage schedule have a sound technical basis. The Commission noted that Order No. 693 stated that all Reliability Standards must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal.[22] The Commission thus disagreed with NERC's proposed interpretation because it suggested that a transmission operator could deliver a voltage schedule that lacked any technical basis. The Commission, citing the NERC Rules of Procedure, section 302.5, concluded that a voltage schedule should reflect technical analysis, i.e., sound engineering, as well as operating judgment and experience.[23]

20. The NOPR also highlighted the Commission's review in Order No. 693 of each Reliability Standard and approval of those containing Requirements that are sufficiently clear as to be enforceable and that do not create due process concerns.[24] The Commission noted that its approval in Order No. 693 of VAR-001-1 meant that VAR-001-1 is sufficiently clear to inform transmission operators what is required of them.[25] The Commission acknowledged that it has elsewhere declined to specify in detail how a registered entity should implement a Reliability Standard, but countered that such actions do not mean that an entity seeking to comply with a Reliability Standard may act in a manner that is not technically sound, i.e., in a manner that is not grounded in sound engineering, and thus, not reasonable and practical.[26] The Commission objected to NERC's proposed interpretation as implying that the voltage schedules provided under VAR-001-1, Requirement R4 need not have any technical basis, and thus need not be reasonable and practical.

21. The Commission proposed in the NOPR to remand NERC's proposed interpretation of VAR-001-1, Requirement R4 for reconsideration consistent with this rulemaking. In addition, the Commission rejected an additional proposal from Dynegy, asserting that NERC needs to develop evaluation measures to review the technical basis for voltage schedules, as beyond the scope of the interpretation process. The Commission proposed that such an effort would be better discussed pursuant to a Standards Authorization Request under the NERC Reliability Standards Development Procedures.

2. Comments

a. VAR-001-1, Requirement R4 Technical Basis

22. No participant contests the Commission's determination that all Reliability Standards must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal.[27] The parties, as discussed below, also largely agree or acknowledge that voltage schedules must have a technical basis.[28]

Start Printed Page 25417

23. FirstEnergy supports the Commission's proposal to remand NERC's interpretation for further consideration because NERC's proposed interpretation suggests that voltage schedules could lack a technical basis. However, FirstEnergy interprets the Commission's proposal in the NOPR as finding that there are “implicit” obligations in VAR-001-1, Requirement R4 that instead should be explicitly incorporated in the Reliability Standards. Therefore, FirstEnergy supports a remand, but states that the remand should incorporate a directive to consider evaluation measures and review the technical basis for voltage schedules pursuant to a Standards Authorization Request under the NERC Reliability Standards development process.[29]

24. According to FirstEnergy, Requirement R4 is correctly written to avoid overly prescriptive language as to what constitutes the correct technical basis, since the determination of voltage schedules is unique to individual transmission systems.[30]

25. Despite acknowledging that the voltage schedules must have a technical basis, some participants object to the Commission's proposal to remand the interpretation in order that NERC may reflect that fact in the interpretation, solely because the requirement is not explicit, that is, not stated directly in the Reliability Standard and supported by compliance measures.[31] EEI supports remand for the limited purpose to incorporate supporting material from NERC's pleadings and a reference to the Order No. 693 discussion that prompted the Commission's concern.[32] However, EEI states that this material would not reflect an auditable requirement that voltage schedules be technically sound, due to the lack of measures and compliance elements.[33] According to EEI, the issue raised in Dynegy's interpretation request was resolved in Order No. 693 when the Commission addressed requests that the Commission direct NERC to modify VAR-001-1 to include detailed and definitive requirements on established limits and sufficient reactive resources and identify acceptable voltage margins.[34] Therefore, EEI views Dynegy's request as an attempt to circumvent the Reliability Standard development process.

26. Ameren characterizes the Commission's proposed remand as effectively creating a new requirement outside the approved procedures, and suggests that the appropriate procedure is to initiate a Standards Authorization Request. Ameren cites the Commission's rejecting Dynegy's proposed evaluation measures as supporting its position.[35] Ameren characterizes the Commission's proposal as resulting in an interpretation that would implement a requirement that is not understood to be part of the Reliability Standard, and cites the NERC balloting as evidence that the industry does not agree with the position that there is an implicit requirement.[36]

b. Technical Basis in Other Reliability Standard Requirements

27. Several participants claim that, while the scope of VAR-001-1, Requirement R4 is limited, other requirements create obligations which lead to technically sound voltage schedules or compliance with VAR-001-1. According to NERC, each of the requirements in VAR-001-1 contributes to meeting the stated objective of the Reliability Standard, and it is the combination of requirements that provides a technically sound method to achieve the purpose of VAR-001-1. NERC states that, although Requirement R4 does not explicitly require a voltage schedule that is technically based, reasonable and practical, “other requirements in VAR-001-1 do require the technical basis to be established.”[37] NERC concludes that “as a whole” VAR-001-1 is technically sound.

28. NERC cites Requirements R2 and R8 through R12 as requiring a transmission operator to have a defensible technical basis to achieve the purpose of VAR-001-1.[38] NERC states that these requirements direct a transmission operator to understand system dynamics to maintain voltage sufficiency and stability under normal and contingency conditions. According to NERC, to maintain the system within limits in real-time and to avoid voltage collapse in the operating time horizon, a transmission operator must study the system on a first contingency basis and must “position the voltage and reactive profile of the system appropriately, including the voltage [schedules] provided to generator operators.” [39] NERC continues, indicating that a transmission operator possesses valuable insight into reactive “weak spots” where additional reactive support would be beneficial to help it achieve the performance expectations outlined in VAR-001-1.[40]

29. NERC also summarizes various planning actions that a transmission operator must take with respect to voltage support. NERC states that, to meet the planning obligations embodied in VAR-001-1, Requirements R2, R9.1 and R11, a transmission operator must rely on long-range and seasonal studies provided by the transmission planner. According to NERC, a combination of planning and operations analysis and feedback provides the technical foundation for voltage schedules to be maintained at buses across the transmission system, including generator buses. NERC concludes that “there must be a technical basis for” the voltage schedule provided for in Requirement R4.[41]

30. To remedy the perceived disconnect, NERC suggests that the interpretation could be improved by stating that it is VAR-001-1, Requirement R4 that lacks an explicit requirement for a technically-based, reasonable, and practical voltage schedule, and “not the entire VAR-001-1 standard.”[42]

31. EEI also indicates that, even though not part of the interpretation, the additional information in NERC's filing demonstrates that the requirements in VAR-001 are based on sound engineering principles, but because it is Start Printed Page 25418not in NERC's official interpretation, a remand may be warranted.[43]

32. Ameren states that review of VAR-002-1a can answer Dynegy's concerns regarding the “reasonable and practical” generator voltage schedule. According to Ameren, the interpretation would not permit unsound practices or practices that threaten system reliability, but instead points to VAR-002-1, Requirement R2 as establishing procedures that accommodate “actual generator capabilities” and “the transmission operator's need to maintain voltage schedules.”[44] Ameren states that the interpretation addresses concerns whether a voltage schedule must accommodate “reasonable” and “practical” generator capabilities by reference to VAR-002-1a, the Reliability Standard that addresses the generators' obligations.[45]

33. Ameren states that Reliability Standards VAR-001 and VAR-002, taken together, support a technically sound purpose of providing for safe and reliable Reactive Power and voltage control, as required by Order No. 693. Ameren asserts that these Reliability Standards as written and interpreted are sufficient to protect electric reliability.[46]

34. According to FirstEnergy, both transmission operators and generator operators are responsible to confirm the technical basis for a voltage schedule. FirstEnergy continues, explaining that the stated purpose of VAR-001-1 provides the basis for Requirement R4, which requires a transmission operator to provide a technically sound voltage schedule that provides sufficient reactive support and respects bulk electric system facility ratings. Failure to do so, FirstEnergy submits, could adversely affect generator equipment and bulk electric system reliability. FirstEnergy states that VAR-002-1 requires generators to provide reactive support to meet this obligation; FirstEnergy suggests that a generator that cannot fulfill that purpose based on the voltage schedule received must coordinate an acceptable voltage schedule with the transmission operator in order to meet the explicit requirements of VAR-002-1.

35. FirstEnergy agrees with the Commission's proposal rejecting Dynegy's request for more detailed specification of the technical requirements of the VAR-001-1 Reliability Standard, as beyond the scope of an interpretation proceeding. FirstEnergy claims that Dynegy's suggestions are already being considered in Project 2008-01, pursuant to NERC's 2009-11.[47] Finally, FirstEnergy suggests that the addition of reliability coordinators as applicable entities would aid in mediating disputes between transmission operators and generator operators.

36. According to IESO, numerous Reliability Standards supplement VAR-001-1 and ensure that transmission operators develop plans and procedures that provide for reliability.[48] IESO states that transmission operators would not be able to provide for system reliability, prevent system operating limit or interconnection reliability operating limit violations, or prevent cascading outages if they do not employ sound engineering principles and technical expertise during the development of plans and procedures.

37. IESO lists several Reliability Standards as supplementing VAR-001-1, including TOP-002-2, Requirement R2 (requiring operations plans); TOP-004-2, Requirement R6 (requiring transmission operators to develop policies for transmission reliability, including controlling voltage levels); TOP-008-1, Requirement R2 (requiring transmission operator to limit potential for IROL or SOL violations). In addition, IESO objects to the Commission's view that NERC's interpretation fails to recognize that a voltage schedule issued under VAR-001-1 should reflect technical analysis, including sound engineering and operating judgment and experience, by noting that planners are required to include system operating personnel in the planning process under TOP-002-2, Requirement R2.[49]

c. Enforceability

38. EEI agrees with NERC that VAR-001-1 lacks an explicit requirement to issue a technically based, reasonable and practical voltage and reactive schedule and also lacks measures or associate compliance elements in the standard. Therefore, EEI concludes that a transmission operator cannot be audited on what EEI terms the “subjective interpretation” that a voltage schedule must have a sound technical basis.[50]

39. According to Ameren, NERC's proposal correctly recognizes that a Reliability Standard cannot establish obligations implicitly, but instead must have stated obligations that can be objectively measured. Ameren states that nothing in VAR-001-1 specifies a technical basis for the transmission operator's voltage schedule and tolerance band or requires a transmission operator to issue its supporting methodology, as Dynegy proposed.[51] IESO agrees with NERC that an implied requirement is not a stated requirement that can be objectively measured.

40. Ameren states that, since there are no implicit requirements, there are no measurements of compliance. According to Ameren, the Reliability Standard and interpretations drafting teams explained that any implicit requirement is subjective, and could not be objectively measured and enforced.[52]

41. Ameren cites the Order No. 672 factors for approving a Reliability Standard as mandatory and enforceable under the FPA.[53] According to Ameren, an implied requirement, not contained Start Printed Page 25419in the language of the Reliability Standard itself, is ambiguous both as to what is required and what measurements will be used to determine compliance. Ameren concludes that such a requirement cannot be enforced fairly, and should not be made part of a mandatory Reliability Standard.

42. Ameren states that disagreements may arise between transmission operators, NERC, generator operators and auditors over reasonableness of a technical basis or methodology or the practicality of a schedule.[54] Ameren criticizes the proposed remand because it contains no instructions for how transmission operators could implement an implicit requirement.[55] Ameren concludes that an implicit requirement is unacceptable and simply unworkable in the context of mandatory and enforceable electric Reliability Standards.

d. Miscellaneous

43. Some participants are concerned that this interpretation could circumvent NERC's Standard development process or otherwise lacks due process.[56] Ameren agrees with the Commission's acknowledgement in the NOPR upholding NERC's rejection of Dynegy's proposed evaluation measures. Ameren states that NERC's interpretation should be approved based on the results of the NERC ballot process. EEI states that the Commission provided an appropriate response in Order No. 693 by directing NERC to develop specific requirements for the issues addressed in the Final Rule through the NERC Reliability Standards development process, and questions whether Dynegy's request concerning voltage schedules is an attempt to circumvent the Reliability Standards development process.[57] These participants claim that interpretations that put new measures in place or would implement new requirements are beyond the scope of the interpretation process.

44. Finally, participants reason that the Commission must rely on the judgment of the ERO in areas involving technical expertise relating to the content of the Reliability Standard and that, if Dynegy wishes to seek new material or measures to be added to the Reliability Standards, it must be handled through a Standards Authorization Request under the NERC Reliability Standards development process.[58] Ameren states that the technical content of the interpretation is entitled to deference. Ameren claims that a remand of VAR-00l-l, Requirement R4 would add a new requirement to the Reliability Standard where the technical experts have acknowledged that one does not exist, without going through the required standards authorization process.[59] Ameren states that such a revision would violate due process and demonstrate a lack of deference to the Reliability Standards development process.

45. On a similar note, FirstEnergy and EEI both suggest that this interpretation request would add requirements to the VAR-001-1 Reliability Standard that are not otherwise required, and the proposed clarification would be more appropriately considered in the ongoing standards development proceedings. FirstEnergy states that changes to Reliability Standards to add more detail, such as the specific technical details sought by Dynegy, should be addressed in the ongoing Reliability Standards development process.

46. EEI points out that Dynegy's request raises several process issues. EEI claims that NERC's narrow interpretation, that there are no implicit requirements with regard to the Reliability Standard's technical validity, could suggest that the Reliability Standard itself is useless. On the other hand, EEI claims that if NERC indicated that there was an implicit requirement, such a requirement must be made explicit in this and every other Reliability Standard, potentially necessitating an overhaul of the entire collection of Reliability Standards.[60] EEI also warns that the Commission and NERC should be careful not to allow a single entity to change a Reliability Standard via interpretations and that any such “backdoor” device should be avoided.

3. Commission Determination

47. The Commission remands to the ERO the proposed interpretation of VAR-001-1, Requirement R4 and directs the ERO to revise the interpretation consistent with the Commission's discussion below.

a. Voltage Schedules Provided Under VAR-001-1, Requirement R4 Must Have a Sound Technical Basis

48. Order No. 693 held that all Reliability Standards must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve the goal.[61] No participant disagrees with this assessment.[62] Furthermore, no participant challenges the Commission's objection that the Reliability Standards should not permit delivery of a voltage schedule that lacks any technical basis.[63] Instead, the participants suggest various ways in which other Reliability Standards requirements provide that technical basis or at least do not permit transmission operators to engage in unsound practices with respect to voltage schedules.[64]

49. VAR-001-1, Requirement R4 requires each transmission operator to specify a voltage schedule to be maintained by each generator and explains that the voltage schedule is a target voltage to be maintained within a tolerance band during a specified period. Requirement R4 is part of the means by which a transmission operator achieves the goal of VAR-001-1, “to ensure that voltage levels, reactive flows, and reactive resources are monitored, controlled, and maintained within limits in real time to protect equipment and the reliable operation of the Interconnection.” Because Requirement R4 requires transmission owners to specify target voltages at each generator's interconnection with the system, while taking into account specific periods of use and facility tolerance bands, the Requirement is not merely a ministerial requirement, but, rather, presupposes the exercise of engineering judgment. These determinations are technical in nature, and, since they represent one of the means by which the VAR-001-1 Reliability Standard achieves its goal, they must be technically sound, that is, based on sound engineering. Actions Start Printed Page 25420that do not reflect sound engineering would not be technically sound.[65] Therefore, the Commission adopts its NOPR proposal, and finds that a voltage schedule should reflect sound engineering, as well as operating judgment and experience.[66] The Commission remands NERC's proposed VAR-001-1, Requirement R4 interpretation, in order that NERC may reconsider its interpretation consistent with this order.

b. Whether Support for a Sound Technical Basis Is Found in Other Reliability Standards and Requirements

50. Several participants, including NERC and Ameren, claim that, in the broader context of the Reliability Standards, there is already an obligation to use technically sound means to comply with VAR-001-1, Requirement R4.[67] The Commission recognizes and appreciates, as part of the NERC filing, the additional information included to allay concerns that generator operators may receive a voltage schedule that is either unsafe or not technically feasible. However, if analysis of other Reliability Standard requirements provides the necessary clarification, such analysis should be made part of the formal interpretation. Thus, in this case, if the actions performed pursuant to other Reliability Standard requirements cited in the participants' comments describe actions that form the basis for development of voltage schedules, then the interpretation should reflect that fact.

51. Some petitioners suggest that other Reliability Standard requirements may mitigate any negative impact of a voltage schedule that lacks a sound technical basis, and thus imply that Requirement R4 need not reflect a sound technical basis, or they suggest that the clarification sought by the Commission is not necessary. The Commission does not agree. As discussed above, voltage schedules developed pursuant to VAR-001-1, Requirement R4 must have a sound technical basis, and failure to properly perform the task would constitute an independent violation of the Reliability Standard.

c. The Commission Is Not Imposing Implicit Requirements

52. The Commission disagrees with participants claiming that the Commission's understanding of Requirement R4 would impermissibly create a new “implicit” requirement, or that such requirements would introduce an unworkable subjective analysis into Reliability Standard enforcement. As the NOPR stated, the Commission reviewed each Reliability Standard and, in Order No. 693, approved those containing Requirements that are sufficiently clear as to be enforceable and that do not create due process concerns.[68] The Commission included VAR-001-1 as among the Reliability Standards that are sufficiently clear to inform transmission operators what is required of them.[69] Order No. 693 declined to order more specificity on the technical basis in the current version of VAR-001-1, but instead found that the development of more detailed requirements to address such concerns are best addressed by the ERO through the Reliability Standards development process.[70] However, that finding does not suggest that existing requirements may be performed without any technical basis.

53. FirstEnergy interprets the Commission's proposal as finding that there are “implicit” obligations in Requirement R4 that should be explicitly incorporated into the Reliability Standard. To the contrary, as noted in the NOPR, the Commission has elsewhere declined to specify in detail how a registered entity should implement a Reliability Standard,[71] and so we do not direct NERC to modify VAR-001-1, Requirement R4, at this time.[72] The Commission affirms its approval in Order No. 693 of VAR-001-1, Requirement R4, and its finding that Requirement R4 is, as written, sufficiently clear to inform entities of what is required of them.

d. Requirement R4 Is Mandatory and Enforceable

54. Several participants claim that any requirement under VAR-001-1 to issue a technically based voltage schedule cannot be audited or enforced because VAR-001-1 lacks measures or compliance elements associated with such a requirement.[73] We do not agree. In Order No. 693, the Commission approved Reliability Standards without associated measures, stating that it disagreed with comments that a Reliability Standard cannot reasonably be enforced, or is otherwise not just and reasonable, solely because it does not include enforcement measures and compliance elements. The Commission reasoned that while such compliance elements and enforcement measures provided useful guidance, “compliance will in all cases be measured by determining whether a party met or failed to meet the Requirement given the specific facts and circumstances of its use, ownership or operation of the Bulk-Power System.” [74]

55. Ameren complains that a remand of the interpretation lacks specific instructions for transmission operators to implement an implicit Requirement. In addition, Ameren speculates that disagreements as to the sufficiency of a particular voltage schedule may arise between parties involved in implementation and enforcement. Again, the Commission affirms its finding in Order No. 693 that Requirement R4 is sufficiently clear; to be enforceable, Reliability Standards need not “spell out in minute detail all factual scenarios that might violate a Requirement and the precise consequences of that violation.” [75]

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e. Procedural Issues

56. Several participants such as Ameren, FirstEnergy, and EEI are concerned that this interpretation could circumvent the Reliability Standards development process. In this remand, the Commission is not approving new Reliability Standards or Requirements. Such action would be better handled via the Reliability Standards development process. In remanding this interpretation, we are simply instructing NERC to provide a revised interpretation reflecting appropriate consideration of the Commission's ruling that a Reliability Standard “must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal.” [76] Furthermore, the Commission, in considering the arguments and comments, has given due weight to the technical expertise of the ERO in deciding how to proceed; the ERO is directed to develop revisions to the Reliability Standard interpretation, consistent with this Final Rule, to address the Commission's concerns.[77]

57. EEI warns the Commission that Dynegy's request raises several process issues and cautions the Commission not to allow a single entity to change a Reliability Standard via an interpretation or any other “backdoor” device. The Commission is mindful of EEI's concern, but we do not believe that we have decided the issues here in a way that allows an entity to change a standard through a “backdoor” effort.

III. Information Collection Statement

58. The Office of Management and Budget (OMB) regulations require that OMB approve certain reporting and recordkeeping (collections of information) requirements imposed by an agency.[78] The information contained here is also subject to review under section 3507(d) of the Paperwork Reduction Act of 1995.[79]

59. As stated above, the Commission previously approved, in Order No. 693, each of the Reliability Standards that are the subject of the current rulemaking. This Final Rule approves one interpretation to a previously approved Reliability Standard developed by NERC as the ERO, and remands another interpretation. The proffered interpretations relate to existing Reliability Standards and do not change these standards; therefore, they do not add to or otherwise increase entities' current reporting burden. Thus, the Final Rule does not materially and adversely affect the burden estimates relating to the currently effective version of the Reliability Standards presented in Order No. 693.

60. The BAL-003-0 Reliability Standard that is the subject of the approved interpretation was approved in Order No. 693, and the related information collection requirements were reviewed and approved, accordingly.[80] The approved interpretation of BAL-003-0 does not modify or otherwise affect the collection of information already in place. With respect to BAL-003-0, the interpretation clarifies that the minimum frequency bias setting applies to systems that employ a variable bias methodology. Incorporating a minimum frequency bias setting into the determination of frequency response under automatic generation control does not change the information that a balancing authority reports because the same logs, data, or measurements would be maintained.

61. The Commission is remanding the interpretation of VAR-001-1. As a result, information collection requirements for that Reliability Standard will not change at this time.

62. Thus, the interpretations of the current Reliability Standards at issue in this rulemaking will not increase the reporting burden nor impose any additional information collection requirements.

63. However, we will submit this Final Rule to OMB for informational purposes.

Title: Electric Reliability Organization Interpretations of Specific Requirements of Frequency Response and Bias and Voltage and Reactive Control Reliability Standards.

Action: Final Rule.

OMB Control No.: 1902-0244.

Respondents: Businesses or other for-profit institutions; not-for-profit institutions.

Frequency of Responses: On Occasion.

Necessity of the Information: This Final Rule approves an interpretation of the specific requirements of one Commission-approved Reliability Standard. The Final Rule finds the interpretation just, reasonable, not unduly discriminatory or preferential, and in the public interest. In addition, this rule remands an additional proposed interpretation for further consideration.

Internal Review: The Commission has reviewed the proposed Reliability Standard interpretations and made a determination that the proposed BAL-003-1 interpretation is necessary to implement section 215 of the FPA. The interpretation conforms to the Commission's policy for frequency response and bias within the energy industry as reflected in BAL-003-1.

64. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE. Washington, DC 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov].

65. For submitting comments concerning the collection(s) of information and the associated burden estimate(s), please send your comments to the contact listed above and to the Office of Information and Regulatory Affairs, Office of Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4638, fax: (202) 395-7285, e-mail: oira_submission@omb.eop.gov].

IV. Environmental Analysis

66. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human Start Printed Page 25422environment.[81] The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended.[82] The actions proposed herein fall within this categorical exclusion in the Commission's regulations.

V. Regulatory Flexibility Act Analysis

67. The Regulatory Flexibility Act of 1980 (RFA) [83] generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The RFA mandates consideration of regulatory alternatives that accomplish the stated objectives of a proposed rule and that minimize any significant economic impact on a substantial number of small entities. The Small Business Administration's Office of Size Standards develops the numerical definition of a small business.[84] For electric utilities, a firm is small if, including its affiliates, it is primarily engaged in the transmission, generation and/or distribution of electric energy for sale and its total electric output for the preceding twelve months did not exceed four million megawatt hours. The RFA is not implicated by this Final Rule because the interpretations discussed herein will not have a significant economic impact on a substantial number of small entities.

68. In Order No. 693, the Commission adopted policies to minimize the burden on small entities, including approving the ERO compliance registry process to identify those entities responsible for complying with mandatory and enforceable Reliability Standards. The ERO registers only those distribution providers or load serving entities that have a peak load of 25 MW or greater and are directly connected to the bulk electric system or are designated as a responsible entity as part of a required under-frequency load shedding program or a required under-voltage load shedding program. Similarly, for generators, the ERO registers only individual units of 20 MVA or greater that are directly connected to the bulk electric system, generating plants with an aggregate rating of 75 MVA or greater, any blackstart unit material to a restoration plan, or any generator that is material to the reliability of the Bulk-Power System. Further, the ERO will not register an entity that meets the above criteria if it has transferred responsibility for compliance with mandatory Reliability Standards to a joint action agency or other organization. The Commission estimated that the Reliability Standards approved in Order No. 693 would apply to approximately 682 small entities (excluding entities in Alaska and Hawaii), but also pointed out that the ERO's Compliance Registry Criteria allow for a joint action agency, generation and transmission (G&T) cooperative or similar organization to accept compliance responsibility on behalf of its members. Once these organizations register with the ERO, the number of small entities registered with the ERO will diminish and, thus, significantly reduce the impact on small entities.[85]

69. Finally, as noted above, this Final Rule addresses an interpretation of the BAL-003-0 Reliability Standard, which was already approved in Order No. 693, and, therefore, does not create an additional regulatory impact on small entities.[86]

VI. Document Availability

70. 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 the Commission's Home Page (http://www.ferc.gov) and in the Commission'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.

71. From the Commission'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.

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

VII. Effective Date and Congressional Notification

73. These regulations are effective June 29, 2009. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a “major rule” as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996.

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List of Subjects in 18 CFR Part 40

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By the Commission.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

End Signature End Supplemental Information

Footnotes

1.  16 U.S.C. 8240 (2006). The Commission is not adding any new or modified text to its regulations.

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3.  Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh'g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

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4.  North American Electric Reliability Corp., 116 FERC ¶ 61,062, order on reh'g & compliance, 117 FERC ¶ 61,126 (2006), appeal docketed sub nom. Alcoa, Inc. v. FERC, Case No. 06-1426 (DC Cir. Dec. 29, 2006).

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5.  Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh'g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

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6.  16 U.S.C. 824o(d)(5). Section 215(d)(5) provides: “The Commission* * * 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.”

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7.  NERC Rules of Procedure, Appendix 3A, Reliability Standards Development Procedure, Version 6.1, at 26-27 (2007).

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8.  The NERC board of trustees approves Reliability Standard interpretations once they are posted and presented for adoption. Id. at 23-24, 26-27.

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9.  See NERC's Rules of Procedures, Appendix 3A.

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10.  NERC Petition at 3.

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11.  Electric Reliability Organization Interpretations of Specific Requirements of Frequency Response and Bias and Voltage and Reactive Control Reliability Standards, Notice of Proposed Rulemaking, 73 FR 71971 (Nov. 26, 2008), FERC Stats. & Regs. ¶ 32,639 (2008) (NOPR).

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12.  The IESO administers wholesale electricity markets and operates the integrated power system in Ontario, Canada and is subject to oversight by the Ontario Energy Board.

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13.  A frequency bias setting is a value expressed in MW per 0.1 Hz, set into a balancing authority's ACE algorithm, which allows the balancing authority to contribute its frequency response to the Interconnection. NERC's glossary, which provides definitions of the relevant terms, defines ACE as “The instantaneous difference between a balancing authority's net actual and scheduled interchange, taking into account the effects of frequency bias and correction for meter error.”

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14.  NOPR, FERC Stats. & Regs. ¶ 32,639 at P 17; Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 370 (addressing the suggestion that Requirement R5 should be required in lieu of Requirement R2 for certain balancing authorities and finding that Requirements R2 and R5 do not conflict); BAL-003-0, Requirement R5.

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15.  See id. P 362, 370.

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16.  NOPR, FERC Stats. & Regs. ¶ 32,639 at P 16, 18.

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17.  Id. P 18 n.19.

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18.  Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 370 (emphasizing the need to follow both Requirements R2 and R5).

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19.  The voltage schedule is a target voltage to be maintained within a tolerance band during a specified period. [Footnote in original.]

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20.  When a Generator is operating in manual control, reactive power capability may change based on stability considerations and this will lead to a change in the associate Facility Ratings. [Footnote in original.]

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21.  NERC Petition at 14.

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22.  Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 5 (“[A] Reliability Standard must provide for the Reliable Operation of Bulk-Power System facilities and may impose a requirement on any user, owner or operator of such facilities. It must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal. The Reliability Standard should be clear and unambiguous regarding what is required and who is required to comply. The possible consequences for violating a Reliability Standard should be clear and understandable to those who must comply. There should be clear criteria for whether an entity is in compliance with a Reliability Standard. While a Reliability Standard does not necessarily need to reflect the optimal method for achieving its reliability goal, a Reliability Standard should achieve its reliability goal effectively and efficiently.”); see also Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 324.

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23.  NOPR, FERC Stats. & Regs. ¶ 32,639 at P 30 (citing Order No. 693 at P 5).

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24.  See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 274. In reviewing specific Reliability Standards, the Commission identified for certain Reliability Standards implicit obligations that should be incorporated into those Reliability Standards and directed NERC to revise the standards to explicitly incorporate the obligations; see Mandatory Reliability Standards for Critical Infrastructure Protection, Order No. 706, 122 FERC ¶ 61,040, at P 75 (2008) (directing the ERO to modify the CIP Reliability Standards to incorporate an obligation to implement plans, policies and procedures); Order No. 693 at P 1787 (“In the NOPR, the Commission identified an implicit assumption in the TPL Reliability Standards that all generators are required to ride through the same types of voltage disturbances and remain in service after the fault is cleared. This implicit assumption should be made explicit.”); Facilities Design, Connections and Maintenance Reliability Standards, Order No. 705, 121 FERC ¶ 61,296, at P 54 (2007) (“although the TPL Reliability Standards implicitly require the loss of a shunt device to be addressed, they do not do so explicitly”).

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25.  Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 275.

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26.  As noted above, Reliability Standards should reflect sound engineering principles. See id. P 5; Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 324; accord NERC Rules of Procedure, section 302.5.

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27.  See, e.g., IESO comments at 5 (“The IESO agrees with the Commission that standards should be technically sound”).

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28.  See NERC comments at 5 (each requirement contributes to meeting a Reliability Standard objective; other Reliability Standards require the technical basis to be established for voltage schedules); Ameren comments at 5 (users, owners and operators must act in a technically sound manner in compliance with VAR-001-1, Requirement R4); EEI comments at 2 (however, EEI states that a transmission operator cannot be audited on the “subjective interpretation” that a voltage schedule be technically sound, because there are no associated compliance measures); FirstEnergy comments at 6 (noting that VAR-001-1 avoids overly prescriptive language defining the correct technical basis). IESO argues that other Reliability Standards require sound engineering principals and technical expertise, in order to meet reliability objectives and obligations, and that these Reliability Standards “supplement” the VAR-001-1 Reliability Standard. IESO comments at 5-6.

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29.  FirstEnergy comments at 5. See also Ameren comments at 9 (comparing current proposal to directives in Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1880, to address clarifying changes through the Reliability Standards development process); IESO comments at 5 (perceived deficiencies in the Reliability Standard should be addressed in the Reliability Standards development process).

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30.  FirstEnergy comments at 6.

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31.  See NERC comments at 5, 9; Ameren comments at 6-9; IESO comments at 1-2, 3.

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32.  EEI comments at 3-4.

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33.  Id. at 2.

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34.  Id. at 3 (citing Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1868).

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35.  Ameren comments at 10 (citing NOPR, FERC Stats. & Regs. ¶ 32,639 at P 32).

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36.  Id. at 7, 10.

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37.  NERC comments at 5-6.

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38.  Id. at 6-7. NERC lists Requirement R2 (discussing reactive sufficiency), Requirement R8 (requiring a transmission operator to operate reactive resources to maintain system voltage limits), Requirement R9 (requiring transmission operators to address reactive support under first contingency conditions), Requirement R10 (addressing system operating limit (SOL) and interconnection reliability operating limit (IROL) violations), Requirement R11 (providing for transformer tap settings) and Requirement R12 (directing a transmission operator to take preemptive action to prevent voltage collapse).

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39.  Id. at 7.

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40.  Id. at 7-8.

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41.  Id. at 9-10.

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42.  Id. at 9.

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43.  EEI comments at 2.

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44.  Ameren comments at 6 (citing NERC Petition, Exhibit B-1 at 2; NOPR, FERC Stats. & Regs. ¶ 32,639 at P 31 (proposing remand and rejecting Dynegy request for the development of compliance measures as beyond the scope of an interpretation proceeding)).

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45.  Id. at 6 (citing NERC Petition, Transmittal Letter at 12-13 and VAR-001-1a as providing that “each Generator Operator shall maintain the generator voltage or Reactive Power output (within applicable Facility Ratings[]) as directed by the Transmission Operator” and Requirement R2.2 as providing that “the Generator Operator shall comply or provide an explanation of why the schedule cannot be met”).

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46.  Id. at 7 (citing Order No. 693, FERC Stats. & Regs. ¶31,242 at P 5, as explaining that “a Reliability Standard does not necessarily need to reflect the optimal method for achieving its reliability goal, [but] a Reliability Standard should achieve its reliability goal effectively and efficiently,” and should be “sufficient to adequately protect Bulk-Power System reliability”).

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47.  FirstEnergy comments at 8.

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48.  IESO comments at 5.

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49.  Id. at 6 (citing NOPR, FERC Stats. & Regs. ¶ 32,639 at P 30).

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50.  EEI comments at 2.

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51.  Ameren comments at 5-6 (citing NERC Petition, Exhibit B-1 and Dynegy Oct. 11, 2007 request for interpretation as stating: “Requirement 4 does not impose any explicit obligations on the Transmission Operator other than to provide the Generator Operator with a voltage or reactive power output schedule and an associated tolerance band.”).

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52.  Ameren comments at 8 (citing NERC Petition at 11; NERC proposed VAR-001-1 interpretation at 1).

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53.  Id. at 7 (citing Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 324, 327:

The proposed Reliability Standard must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose a topic for a Reliability Standard to the ERO, in the ERO's process, the specific proposed Reliability Standard should be developed initially by persons within the electric power industry and community with a high level of technical expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability Standard should be fair and open to all interested persons. * * *

There should be a clear criterion or measure of whether an entity is in compliance with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.

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54.  Ameren comments at 8.

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55.  Id. at 9.

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56.  Ameren comments at 10 (suggesting that remand may circumvent the Reliability Standards development procedure by adding new requirements to the standard violating the principles of due process and deference); FirstEnergy comments at 5.

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57.  EEI comments at 3.

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58.  Ameren comments at 2; EEI comments at 2; FirstEnergy comments at 5; IESO comments at 4.

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59.  Ameren comments at 10 (citing NERC Petition at Exhibit B-3 (results of the ballot body vote) and stating “Indeed, several members of the ballot pool for the VAR-001-1 interpretation indicated their belief that Dynegy's request for an interpretation should have been filed as a Standards Authorization Request because the proposed change is so obviously beyond the scope of the current content of the Reliability Standard”).

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60.  EEI comments at 4-5.

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61.  Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 5; see NOPR, FERC Stats. & Regs. ¶ 32,639 at P 30.

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62.  See NERC comments at 5; Ameren comments at 5; EEI comments at 2; FirstEnergy comments at 3-4; IESO comments at 2-3.

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63.  NOPR, FERC Stats. & Regs. ¶ 32,639 at P 30.

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64.  NERC comments at 5-6; EEI comments at 2 (citing NERC petition at 12-14); FirstEnergy comments at 5-7; IESO comments at 5. See also Ameren comments at 6 (suggesting that procedures in VAR-002-1 would accommodate actual generator capabilities and not permit unsound practices under VAR-001-1, Requirement R4).

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65.  NOPR, FERC Stats. & Regs. ¶ 32,639 at P 31.

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66.  Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 5 (“a Reliability Standard must provide for the Reliable Operation of Bulk-Power System facilities and may impose a requirement on any user, owner or operator of such facilities. It must be designed to achieve a specified reliability goal and must contain a technically sound means to achieve this goal. The Reliability Standard should be clear and unambiguous regarding what is required and who is required to comply. The possible consequences for violating a Reliability Standard should be clear and understandable to those who must comply. There should be clear criteria for whether an entity is in compliance with a Reliability Standard. While a Reliability Standard does not necessarily need to reflect the optimal method for achieving its reliability goal, a Reliability Standard should achieve its reliability goal effectively and efficiently”); see also Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 324; accord NERC Rules of Procedure, section 302.5.

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67.  NERC comments at 8-9 (discussing VAR-001-1, Requirements R2, R9.1 and R11); Ameren comments at 6 (discussing VAR-002-1a, Requirement R2). See also EEI comments at 2 (supporting NERC conclusion); IESO comments at 6 (discussing transmission operations Reliability Standards, TOP-002-2, et al.). However, participants also suggest that a failure to meet that obligation would not constitute an enforceable violation of VAR-001-1, Requirement R4. See EEI comments at 2.

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68.  See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 274.

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69.  Id. P 275.

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70.  Id. P 1869.

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71.  NOPR, FERC Stats. & Regs. ¶ 32,639 at P 31; see also Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 260 (stating that implementation procedures should be included when inextricably linked to the Reliability Standard or when leaving out implementation features could: (1) Sacrifice necessary uniformity in implementation of the Reliability Standard; (2) create uncertainty for the entity that has to follow the Reliability Standard; (3) make enforcement difficult; and (4) increase the complexity of the Commission's oversight and review process).

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72.  Requirement R4 does not prescribe any one particular method of achieving compliance, but instead permits transmission operators to implement Reliability Standards through a variety of technically sound means.

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73.  Ameren comments at 8; EEI comments at 2; IESO comments at 3.

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74.  Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 253.

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75.  Id. P 274-75 (“the Commission finds that none of the Reliability Standards that we approve today contains an ambiguity that renders it unenforceable or otherwise unjust and unreasonable”).

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76.  Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 324.

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77.  See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 165, 167 (“NERC states that the requirement that a Reliability Standard be “in the public interest” provides the Commission with broad discretion to review and approve a Reliability Standard. According to NERC, implicit in the “public interest” test is that a Reliability Standard is technically sound and ensures an adequate level of reliability, and that the Reliability Standards provides a comprehensive and complete set of technically sound requirements that establish an acceptable threshold of performance necessary to ensure reliability of the Bulk-Power System.”).

The Commission agrees with NERC that an open and transparent process is important in implementing section 215 of the FPA and developing proposed mandatory Reliability Standards. However, in Order No. 672, the Commission rejected the presumption that a proposed Reliability Standard developed through an ANSI-certified process automatically satisfies the statutory standard of review. Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 338. The Commission reiterates that simply because a proposed Reliability Standard has been developed through an adequate process does not mean that it is adequate as a substantive matter in protecting reliability. We, therefore, review each Reliability Standard to ensure that the Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest.

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80.  See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1901-07.

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81.  Regulations Implementing the National Environmental Policy Act, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).

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85.  To be included in the compliance registry, the ERO determines whether a specific small entity has a material impact on the Bulk-Power System. If these small entities should have such an impact then their compliance is justifiable as necessary for Bulk-Power System reliability.

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86.  The Commission remands the interpretation of the VAR-001-1 Reliability Standard.

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[FR Doc. E9-12348 Filed 5-27-09; 8:45 am]

BILLING CODE 6717-01-P