04-9358. Policy Statement on Matters Related to Bulk Power System Reliability

Issued April 19, 2004.

Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher, and Suedeen G. Kelly.

1. This Policy Statement responds to recommendations in the U.S.-Canada Power System Outage Task Force's (Task Force) Interim and Final Blackout Reports on initiatives the Commission should undertake. This Policy Statement also responds to comments submitted after the Commission's December 1, 2003 public conference, in Docket No. RM04-2-000, on actions the Commission should take to promote reliable transmission service in interstate commerce (December 1 Reliability Conference). As such, the Policy Statement addresses a number of issues that relate to the Commission's role and policies regarding reliability of the nation's interstate bulk power systems. In particular, the Policy Statement clarifies Commission policy with regard to: the need to expeditiously modify existing bulk power system reliability standards,^[1] to translate them into clear and enforceable requirements; public utility compliance with industry reliability standards and possible Commission action to address specific bulk power system reliability issues; cost recovery of prudent bulk power system reliability expenditures; the need for communication and cooperation between the Commission and the States; the need for communication and cooperation among the Commission, Canada and Mexico regarding reliability issues; consideration of reliability in Commission decision-making; and limitations on liability. This Policy Statement benefits citizens by providing clarity about this agency's policies to support and take what steps it can under current law to enhance transmission grid reliability.

2. The Commission strongly supports legislative reform to provide a clear Federal framework for developing and enforcing mandatory reliability rules. In the interim, the Commission is issuing this Policy Statement and taking other steps within its existing authority to promote greater reliability of the United States' bulk power system and its operation and to support industry efforts to improve the current voluntary industry based approach.^[2]

Background

3. On August 14, 2003, an electric power blackout affected large portions of the Northeast and Midwest United States and Ontario, Canada. The blackout lasted up to two days in some areas of the United States and longer in some areas of Canada. It affected an area with an estimated 50 million people and 61,800 megawatts of electric load.

4. On August 15, 2003, President George W. Bush and Prime Minister Jean Chrétien established a joint U.S.-Canada Power System Outage Task Force (Task Force) to investigate the causes of the blackout and how to reduce the possibility of future outages.

5. During the December 1 Reliability Conference, the Commission conducted a public inquiry into electric reliability. The conference addressed topics related to ensuring the reliability of the nation's bulk power system, including what the Commission should do to promote a reliable bulk power system (Docket No. RM04-2-000). Written comments submitted by John Derrick, Chairman PEPCO Holdings, Inc., on behalf of the Edison Electric Institute (EEI) proposed that the Commission continue to pursue its pending pricing policy for developing transmission infrastructure incentives and build on the NERC structure that is already in place by engaging the industry in a focused, sustained dialogue on (1) Enforcing reliability standards and practices, (2) the six near-term critical reliability elements identified by NERC in an October 15, 2003 inquiry directed to control area operators and reliability coordinators,^[3] (3) third-party liability issues, and (4) clarification of the relationship between grid operations, and market and business practices.

6. On April 5, 2004, the Task Force issued a Final Blackout Report,^[4] replacing the interim report issued in November 2003.^[5] The Final Blackout Report describes the blackout investigation findings and identifies the causes of the blackout. There are four groups of causes that coincided on August 14, 2003 to produce the blackout:

• inadequate system understanding;
• inadequate situational awareness;
• inadequate tree trimming; and
• inadequate reliability coordinator diagnostic support.

Further, the Final Blackout Report indicates that several entities violated NERC operating policies and planning standards, and those violations directly contributed to the start of the blackout. However, the Final Blackout Report finds that due to a variety of institutional issues, the NERC standards are sufficiently unclear, ambiguous and non-specific that it was possible for bulk power system participants to interpret these standards in widely varying ways that, while producing low reliability, could still be considered to comply with the standards.

7. The Final Blackout Report stated that the August 14, 2003 blackout was preventable and provided 46 recommendations to enhance grid reliability, which emphasize comprehensiveness, monitoring, training and enforcement of reliability standards.^[6] Several of these recommendations suggest actions the Commission should take to improve bulk power system reliability. For example, the report recommends that the Commission not approve the operation of a new Regional Transmission Organization (RTO) or Independent System Operator (ISO) until the applicant has met the minimum functional requirements of reliability coordinators.^[7] In addition, the Final Blackout Report states that the Commission should develop a Commission-approved mechanism for funding NERC and the regional reliability councils to ensure their independence from the parties they oversee,^[8] clarify that prudent expenditures and investments for bulk system reliability will be recoverable through transmission rates,^[9] and integrate a reliability impact consideration into our regulatory decision-making process.^[10] The report also states that operators who initiate load shedding pursuant to approved guidelines should be shielded from liability or retaliation.^[11]

8. The Interim Blackout Report indicated (and the Final Blackout Report confirms) that, in the period of time immediately preceding the August 14 blackout, Northeast Ohio had significant reactive power needs. FirstEnergy, a Midwest utility identified as one of the entities whose violations of NERC standards contributed to the blackout, was severely deficient in reactive power to support the Cleveland-Akron area before the blackout. Based on these circumstances, the Commission determined that the availability of reactive power, and more generally, the availability of sufficient generation and transmission facilities in Eastern Ohio are matters deserving more study.^[12] The Commission directed FirstEnergy to retain an independent expert to prepare a study of the adequacy of transmission and generation facilities in Northeastern Ohio.^[13] FirstEnergy has retained an independent expert as directed and is currently preparing the required study, which will be completed in April, 2004.

9. Responding to the blackout and the blackout investigation, on February 10, 2004, the NERC Board of Trustees approved recommendations to take steps to improve the reliability of the bulk electric system, including a recommendation to review the reliability readiness of reliability coordinators and the major control areas.^[14] NERC plans to complete the 20 highest priority reviews by June 30, 2004, inspecting the operators which serve over 80 percent of North America's electric load.

10. The Commission supports NERC's and the industry's efforts to take concrete steps to improve system reliability. Pursuant to an explicit provision in its 2004 appropriation, the Commission is establishing a new reliability division to be staffed with grid-reliability engineering experts in the Office of Markets, Tariffs and Rates, to assure sound integration of reliability and market considerations in Commission decision-making. Members of this division are participating with other industry volunteers in NERC's reliability readiness reviews and supporting the development of new reliability standards.

11. The Congress is currently considering energy legislation, which would address the reliability of the nation's bulk power system based on mandatory industry compliance with enforceable reliability standards. The Commission strongly supports the enactment of legislation containing such a reliability provision. This Policy Statement is intended to be consistent with both current FERC authority and responsibility, and the implementation of such legislation.

Discussion

A. Need for Expeditious Revision of NERC Reliability Standards

12. Over the past 30 years NERC has developed “operating policies and planning standards” with which its members are expected to voluntarily comply. As mentioned above, the operating policies consist of a collection of standards, requirements and guidelines that, together, instruct on the reliable operation of interconnected systems operations and, as currently drafted, place the primary responsibility for reliable operations on control area operators. NERC's planning standards are intended to state the fundamental requirements for planning reliable interconnected bulk electric systems.

13. In 2002, NERC began developing clear and enforceable “reliability standards,” under an American National Standards Institute (ANSI)-accredited process, which includes a voting model that provides for open participation and voting by industry stakeholders, weighted by industry segment. These new standards will be clear and unambiguous as to what needs to be done and who needs to do it to achieve reliable grid operations, and will include compliance measures for each standard. NERC is also working to transition its policies away from control area-oriented terminology suited for traditional vertically-integrated utilities and toward the terminology of a functional model that focuses on tasks or functions required for maintaining electric system reliability. The functional model recognizes changes to new industry structures that have emerged from the advent of open access transmission service.^[15]

14. The Commission agrees with the critical need to replace the current standards with standards that are clear, unambiguous, measurable and enforceable. To date NERC has completed development of one interim reliability standard, relating to cyber security. NERC has identified approximately twelve additional reliability standards that it plans to develop that, when completed, will replace the existing operating policies and planning standards. NERC and the industry have recently agreed to expedite the development of these new standards and are currently working toward the completion and adoption of new standards by the end of 2004. The Commission supports NERC's commitment and our expectation is that such standards will be enforceable in early 2005.^[16]

15. The Final Blackout Report identifies topics that are not currently addressed by NERC standards or are addressed so vaguely as to be ineffective, but are important in maintaining system reliability. Such “gaps” include vegetation management for transmission rights-of-way, line ratings, operator training, adequacy of operator tools, and minimum functional requirements and capabilities for reliability authorities and balancing authorities.^[17] The Commission advises NERC and the industry to include these priority matters in the list of topics for which immediate reliability standards must be developed, and to develop such standards as quickly as reasoned deliberation allows.

16. The Commission requests status reports from NERC and the industry on the development of these revised standards. Pursuant to a recommendation in the Final Blackout Report, the Commission is working with the United States and Canadian governments to hold a meeting with NERC and the electric industry about how the findings of the blackout investigation should affect electric reliability standards and regulation, and looks forward to discussing these issues in that meeting.

17. The Commission believes that NERC's reliability standards should represent a floor for grid operator and bulk system participants' reliability efforts, and not a ceiling. Utilities and other entities involved in transmission system reliability should strive toward achieving reliable transmission service and not simply act with the aim of meeting the minimum requirements that have been set forth in manuals and standards.

18. The Commission recognizes that entities may be subject to regional reliability standards developed by NERC's regional reliability councils or State agencies. The Commission supports variations where the transmission provider or other relevant entity can demonstrate that regional reliability standards are necessary to account for physical differences in the bulk power system and are no less stringent than, and not inconsistent with, NERC's reliability standards.^[18] Regional or State standards that do not account for physical differences and do not produce the same or a higher level of performance are not acceptable. Likewise, we cannot support regional or State reliability standards that result in variations that are less stringent and produce lower reliability than NERC standards. The Commission is concerned, however, that regional variations may create market seams or allow anti-competitive behavior and will watch carefully for any such problems.

19. In summary, we support NERC and industry efforts to translate the existing reliability standards into clear and enforceable standards by early 2005, and we encourage NERC to address the “gaps” in existing reliability standards.

B. Good Utility Practice

20. Nearly all transmission-providing public utilities are members of one of NERC's ten regional reliability councils.^[19] NERC has taken the position that all members must voluntarily agree to operate their transmission systems consistent with NERC reliability standards.

21. In Order No. 888, the Commission required that all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce have on file an open access, non-discriminatory transmission tariff (OATT).^[20] The pro forma OATT, issued as part of Order No. 888, contains numerous provisions that reference “Good Utility Practice,” ^[21] some of which specifically relate to the reliable operation of the transmission grid. For example, “Control Area” is defined as a system or systems to which a common automatic generation control scheme is applied in order to, among other things, “maintain scheduled interchange with other control areas, within the limits of Good Utility Practice” and “maintain the frequency of the electric power systems within reasonable limits in accordance with ‘Good Utility Practice.’ ” ^[22]

22. With regard to network integration transmission service, the OATT provides that a transmission provider is responsible to plan, construct, operate and maintain its Transmission System in accordance with Good Utility Practice ^[23] and may curtail service consistent with Good Utility Practice to maintain system reliability.^[24] Further, the OATT specifically requires that a network customer satisfy its control area requirements by either operating as a control area under NERC and regional reliability council guidelines, contracting with the Transmission Provider or contracting with another entity “consistent with Good Utility Practice, which satisfies NERC and the [applicable regional reliability council] requirements.” ^[25]

23. In this Policy Statement, we clarify that the Commission interprets the term “Good Utility Practice” to include compliance with NERC reliability standards or more stringent regional reliability council standards. Accordingly, public utilities that own, control or operate Commission-jurisdictional transmission systems should operate their systems in accordance with Good Utility Practice as set forth in the Commission's pro forma open OATT, including complying with NERC reliability standards.

24. With respect to ISOs and RTOs, they must comply with NERC reliability standards pursuant to both Order No. 888 and Order No. 2000. Order No. 888-A, in discussing the characteristics and functions of ISOs, states that ISOs should comply with “applicable standards set by NERC and the regional reliability council.” ^[26] Likewise, with regard to RTOs, the Commission discussed in Order No. 2000 a specific requirement that RTOs follow NERC standards. The Commission determined that RTOs must have exclusive authority for maintaining the short-term reliability of the grid that it operates. In that context, the Commission concluded that:

the RTO must perform its functions consistent with established NERC (or its successor) reliability standards, and notify the Commission immediately if implementation of these or any other externally established reliability standards will prevent it from meeting its obligation to provide reliable, non-discriminatory transmission service.^[27]

Accordingly, the Commission expects ISOs and RTOs to perform their functions consistent with NERC reliability standards (or with regional variations that are no less stringent than, and not inconsistent with, NERC standards) and the findings and recommendations of NERC audits.

25. In sum, the Commission expects public utilities to comply with NERC reliability standards and to remedy any deficiencies identified in NERC compliance audit reports and recommendations. The Commission will consider taking utility-specific action on a case-by-case basis to address significant reliability problems or compliance with Good Utility Practices, consistent with its authority. A failure to comply with such industry standards could in some circumstances affect Commission determinations as to whether rates are just and reasonable. For example, it may be appropriate to deny full cost recovery in circumstances where a transmission provider fails to provide full reliability of service.^[28]

26. Generators, transmission customers and other market participants are also expected to support transmission system reliability, and to obey the directives of a balancing authority or reliability authority for operational reliability in real time. The Commission plans to explore this topic further to determine the best means to ensure that all market participants are held responsible to act to support transmission system reliability.

C. Cost Recovery of Prudent Reliability Expenditures

27. The Commission understands that public utilities may need to expend significant amounts of money to implement measures necessary to maintain bulk electric system reliability, including vegetation management, improved grid monitoring and management tools, and improved operator training. The Commission is also aware that there may be uncertainty about public utilities' ability to recover as additional expenses the expenses necessary to ensure bulk electric system reliability, especially if they are operating under frozen or indexed rates. Further, the blackout investigation Final Blackout Report Recommendation 4 recommends that regulators clarify that prudent expenditures and investments to maintain or improve bulk power system reliability will be recoverable through rates.^[29] Accordingly, the Commission assures public utilities that we will approve applications to recover prudently incurred costs necessary to ensure bulk electric system reliability, including prudent expenditures for vegetation management, improved grid management and monitoring equipment, operator training, and compliance with NERC reliability standards and Good Utility Practices.

28. In a Statement of Policy issued September 14, 2001, the Commission provided assurances to regulated entities that the Commission “will approve applications to recover prudently incurred costs necessary to further safeguard the reliability and security of our energy supply infrastructure in response to the heightened state of alert. Companies may propose a separate rate recovery mechanism, such as a surcharge to currently existing rates or some other cost recovery method.” ^[30] The Commission stands by this policy and clarifies that the policy extends to the recovery of prudent reliability expenditures, including those for vegetation management, improved grid management and monitoring equipment, operator training and compliance with NERC standards.

D. Commission Relationship with States on Reliability Issues

29. The Commission recognizes that many aspects of system reliability are within the purview of the states. To maintain and enhance reliability, it is necessary that all those with responsibility for the bulk electric system work together to achieve the common goal of a reliable electric system. Accordingly, the Commission intends to work closely with the states to address vegetation management, jurisdictional overlap issues regarding reliability upgrades, cost recovery, and other reliability-related issues of mutual concern. To date we have been holding such discussions with individual State officials, through the National Association of Regulatory Utility Commissioners, and through interactions on the joint U.S.-Canada Power System Outage System Task Force. We look forward to continuing and strengthening these efforts.

30. With regard to reliability “upgrades,” we note that several State and regional entities have asked the Commission to recognize that State or regional reliability rules may be more stringent than those developed by NERC. For example, in follow-up comments to the Commission's December 1 Reliability Conference, the New York State Reliability Council, Northeast Power Coordinating Council and the Western Electricity Coordinating Council all indicated that, while they support efforts to develop enforceable, industry-wide reliability standards, such standards “should represent a floor rather than a ceiling.” They stated that it is essential for regional entities to have the ability to promulgate more specific and more stringent regional and local reliability standards. According to these comments, more stringent regional criteria that address unique regional needs or concerns make for a more robust overall bulk electric system and allow greater flexibility when extraordinary events occur.

31. As discussed above, the Commission supports regional standards that are necessary to account for physical differences in the bulk power system and are no less stringent than, and not inconsistent with, NERC's reliability standards. The Commission recognizes that regional criteria may be necessary and that the State and regional entities have legitimate interests in enhancing reliability beyond the level achieved by compliance with NERC standards.

32. We are also interested in working together with the States and NERC to address and remedy any deficiencies in public utility implementation of reliability requirements, or any shortfalls in actual bulk system reliability.

E. Commission Relationship with Canada and Mexico on Reliability Issues

33. The Commission recognizes the common interest of the United States, Canada and Mexico in maintaining a safe and reliable interconnected North American bulk electric system.^[31] In this vein, the Commission will work closely and cooperatively with officials designated by the Canadian and Mexican governments to achieve this common interest.

34. Further, the Commission will work closely with Canada to achieve common reliability of the interconnected transmission grid to attain consistent cross-border treatment of reliability standards and regulation as they affect bulk system participants and NERC under current regulatory conditions. When energy legislation is enacted, we will work closely with appropriate Canadian authorities to assure the success of the Electricity Reliability Organization (ERO) and address any issues required to assure that our nations share a reliable electric grid.

F. Recommendations of Blackout Investigation Final Report

35. In addition to recommending that the Commission allow recovery of prudently incurred reliability-related costs, discussed in Section C, above, the April 5 Final Blackout Report recommends or discusses several other actions related to the Commission and its regulation of public utilities. Below we adopt new policies and announce new steps in response to the final report.

Reliability of ISOs and RTOs

36. The Final Blackout Report's Recommendation 6 ^[32] recommends that the Commission not authorize a new RTO or ISO to become operational until the applicant has met the minimum functional requirements for reliability coordinators. In response to this recommendation, the Commission will continue its policy of taking reliability considerations into account before authorizing a new ISO or RTO to become operational. An ISO or RTO must meet all minimum functional requirements for reliability coordinators in order to fulfill its responsibility as reliability coordinator for the area within its footprint.

Consideration of Reliability Impacts in Commission Decision-Making Process

37. The Final Blackout Report's Recommendation 9 ^[33] recommends that the Commission integrate a formal reliability impact consideration into our regulatory decision-making to ensure Commission actions improve, or at a minimum do not harm, reliability. In response to this recommendation, the Commission will continue its policy of considering the reliability implications of Commission decisions, as appropriate.

Funding of NERC

38. The Final Blackout Report's Recommendation 2 ^[34] recommends that the U.S. and Canadian regulatory authorities develop a regulator-approved mechanism for funding NERC and the regional reliability councils, to ensure their independence from, the parties they oversee. In response, the Commission will appoint a staff task force to report to the Commission on potential mechanisms for funding NERC, the regional reliability councils, and, should energy legislation be passed, the Electricity Reliability Organization, to ensure independence from the utilities they oversee. This staff task force will be directed to work closely with our Canadian counterparts, as well as State regulatory authorities, NERC, the regional reliability councils, and industry participants, to develop funding options and recommendations. Such options should take into account funding mechanisms for current entities, such as NERC and the regional reliability councils, and entities created by the passage of reliability legislation.

Memorandum of Understanding with NERC

39. The Final Blackout Report recommends that government agencies in the U.S. and Canada decide whether to develop individual memoranda of understanding (MOUs) with NERC that would define the agency's working relationship with NERC, government oversight of NERC activities, if appropriate, and the reliability responsibilities of the signatories.^[35] In response to this recommendation, the Commission directs staff to draft a MOU which will define NERC's working relationship with the Commission. In addition, this MOU will clarify the appropriate Commission oversight of NERC and the respective reliability responsibilities of both NERC and the Commission. This MOU will be signed by the Chairman, on behalf of the Commission.

G. Limitations on Liability

40. In view of the Commission's interpretation in this Policy Statement that Good Utility Practice includes compliance with NERC reliability standards and NERC compliance audit recommendations, the Commission will consider, on a case-by-case basis, proposals by public utilities to amend their OATTs to include limitations on liability. 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.^[36] Such proposals should address the standard for liability (e.g., gross negligence and willful misconduct) and the types of damages for which the public utility may be liable (e.g., direct damages and not consequential or indirect damages).

By the Commission.

Magalie R. Salas,

Secretary.

Footnotes

1.  Current industry reliability standards are found in the North American Electricity Reliability Council's (NERC) Planning Standards and the NERC Operating Manual, with operating standards set forth in operating policies contained in the Operating Manual and Appendices. The operating policies include “standards” and “requirements,” along with “guidelines” and “criteria.” For purposes of this Policy Statement, the term “reliability standards” refers to the entirety of reliability-related policies now in the NERC Operating Manual and Planning Standards and those evolving through the formal standards development process.

2.  Concurrent with the issuance of this order, the Commission is issuing an order directing transmission providers to report on their vegetation management practices related to certain overhead interstate transmission lines. Order Requiring Reporting on Vegetation Management Practices Related to Designated Transmission Facilities, 107 FERC ¶ 61, 053(2004).

3.  NERC's six critical reliability elements include: (1) Ensuring that high voltage transmission line rights-of-way are free of vegetation and other obstacles; (2) ensuring sufficient reactive power for voltage support; (3) strengthening where needed the reliability communications protocols between control area operators and reliability coordinators; (4) establishing as necessary more formal means to immediately notify control room personnel about failures of system monitoring and control functions; (5) ensuring that emergency actions plans and procedures are in place; and (6) ensuring that all operating staff are trained and certified in emergency drills.

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

5.  U.S.-Canada Power System Outage Task Force, Interim Report: Causes of the August 14th Blackout in the United States and Canada (Nov. 2003) (Interim Blackout Report). The Interim Blackout Report is available on the Internet at http://www.ferc.gov/​cust-protect/​moi/​blackout.asp.

6.  Final Blackout Report at 139.

7.  Recommendation 6. Id. at 147.

8.  Recommendation 2. Id. at 143.

9.  Recommendation 4. Id. at 146.

10.  Recommendation 9. Id. at 147.

11.  Recommendation 8. Id.

12.  FirstEnergy Corporation, 105 FERC ¶ 61,372 (2003).

13.  Id.

14.  See Recommendation 3a. The text of the February 10, 2004 document is available on NERC's Web site, http://www.nerc.com.

15.  Historically, control areas were established by vertically-integrated utilities to balance the control area's load with its generation, implemented interchange schedules with other control areas, and ensured transmission reliability. Industry restructuring in some areas has led NERC to restate its reliability standards in terms that fit the new—as well as the traditional—industry structures. This means replacing the term “Control Area Operator” with new terms that identify more closely which entity in a more disaggregated industry structure is responsible for complying with each NERC standard. To facilitate the update of its reliability standards, NERC has established the functional model. This model now recognizes a “Balancing Authority Area” as the collection of generation, transmission, and loads within the metered boundaries where a “Balancing Authority” maintains a load-resource balance. A “Reliability Authority Area” is recognized as having borders that may coincide with one or more balancing authority areas. A “Reliability Authority” may direct the “Transmission Operators” or Balancing Authorities to take action, for example, to maintain interconnection reliability operating limits. Also, as the functional model was being developed, the term “Reliability Coordinator” was used on an interim basis before Reliability Authority became the accepted term.

16.  In this vein, the Commission notes NERC's April 5, 2004 announcements of the adoption of (1) Revised Compliance Templates and (2) Interim Guidelines for Reporting and Disclosure of reliability audit results and reliability standards compliance violations.

17.  See Final Blackout Report at 21-22.

18.  NERC recently explained that “regional standards may be more stringent than, but may not be inconsistent with or less stringent than, the NERC standards. Both sets of rules apply, and operators must comply with the more stringent one.” March 12, 2004 Response to Questions posed by the Senate Committee on Energy and Natural Resources, Michehl Gent, President and CEO of NERC.

19.  NERC's members are the ten regional reliability councils.

20.  Order No. 888, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21,540 (1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12,274 (1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 62 FR 64,688, 81 FERC ¶ 61,248 (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, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

21.  Order No. 888 defined “Good Utility Practice” in section 1.14 of the pro forma OATT as follows:

Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region. (Emphasis added)

22.  Pro forma OATT at section 1.6.

23.  Id. at section 28.2.

24.  Id. at section 33.7.

25.  Id. at section 35.2.

26.  Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,247-48.

27.  Regional Transmission Organizations, Order No. 2000, 65 FR 809 (2000), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,089 at 31,106 (1999), order on reh'g, Order No. 2000-A, 65 FR 12088 (2000), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,092 (2000), aff'd, Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

28.  See, e.g., Village of Freeport, New York v. Consolidated Edison Co. of New York, Inc., 87 FERC ¶ 61,301 (1999) (setting for hearing whether ConEd followed good utility practice in providing firm transmission service required by the OATT and, if not, what remedies are appropriate); Green Mountain Power Co., 59 FERC ¶ 61,213 at 61,739 (1992).

29.  Final Blackout Report at 146.

30.  Extraordinary Expenditures Necessary to Safeguard National Energy Supplies, 96 FERC ¶ 61,299 at 61,129 (2001).

31.  The northern portion of Baja California Norte, Mexico is interconnected with the western United States and Canada and is part of the WECC, a NERC region.

32.  Final Blackout Report at 147.

33.  Final Blackout Report at 147.

34.  Id. at 143.

35.  Id.

36.  See Wholesale Market Power Platform White Paper (April 28, 2003) (stating that a standard tariff provision limiting liability for transmission providers would be included in the Final Rule Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design). See also Midwest Independent Transmission System Operator, Inc., 100 FERC ¶ 61,144 (2002) (conditionally accepting for filing a proposed OATT revision that would limit the liability of the Midwest ISO and Midwest ISO transmission owners for certain damages related to services provided under the Midwest ISO OATT); and ISO New England, et al., 106 FERC ¶ 61,280 (2004).