DOJ Antitrust Division, Business Review Request Letter 99-3, Western Systems Coordinating Council (WSCC) (1998)
L.L.P.
MARY ANNE MASON
PARTNER
DIRECT DIAL (202) 637-5980
INTERNET MM5@DC2.HHLAW.COM
February 25, 1998
COLUMBIA SQUARE
555 THIRTEENTH STREET, NW
WASHINGTON, DC 20004-1109
TEL (202) 637-5600
FAX (202) 637-5910
Honorable Joel I. Klein
Assistant Attorney General
Antitrust Division
U.S. Department of Justice
950 Pennsylvania Avenue, N.W.
Washington, D.C., 20530-0001
Re: Western Systems Coordinating Council – Request for
a Business Review Letter
Dear Mr. Klein:
Pursuant to 28 C.F.R. § 50.6 (1998), enclosed please find five copies of
a Request for a Business Review Letter stating that the Department of Justice has
no present intention to bring an enforcement action against the Western Systems
Coordinating Council ("WSCC") and its members joining in the Request if WSCC
implements a proposed reliability management system.
Please call me if you have any questions regarding this Request.
Sincerely
Mary Anne Mason
Counsel for WSCC
Enclosures
BEFORE
THE DEPARTMENT OF JUSTICE
ANTITRUST DIVISION
ON IMPLEMENTATION OF
THE WESTERN SYSTEMS COORDINATING COUNCIL'S
PROPOSED RELIABILITY MANAGEMENT SYSTEM
February 25, 1999
Page
EXECUTIVE SUMMARY...iii-xi
I. INTRODUCTION AND SUMMARY...2
II. DESCRIPTION OF THE RMS...9
A. Reliability Standards...9
1. Operating Reserve Requirements...10
2. Disturbance Control Standard (DCS)...12
3. Control Performance Standards (CPS)...14
4. Operating Transfer Capability (OTC) Requirements...18
5. Generator Power System Stabilizer (PSS) and
Automatic Voltage Regulator (AVR) Requirements...21
B. Implementation Through Contracts...25
C. Sanctions for Noncompliance...28
D. Excused Noncompliance...30
E. Data Collection...31
F. Review and Appeal of Proposed Sanctions...32
G. Confidentiality Provisions...35
III. COMPETITIVE ANALYSIS...37
A. The RMS, Including Sanctions, Is Needed to Maintain the
Continued Reliability of the Western Interconnection as
the Electric Power Industry Moves from One of Vertically
Integrated Monopolies to Competition Among Numerous
Industry Participants...38
B. The RMS Standards Were Selected and the Contracts
Developed Pursuant to Well Delineated Procedures Open
to All Industry Participants...46
C. Compliance with the RMS Standards Will Not Impose
Unreasonable Burdens on Selected Participants or
Adversely Affect Any Group of Competitors...48
(continued)
Page
D. The Sanctions Are Narrowly Tailored to Deter
Noncompliance Without Burdening Competition. ...51
E. The Confidentiality Provisions of the RMS Protect
Competitors from Inappropriate Use of Reliability
Records. ...54
IV. IMPLEMENTATION TIMELINE...55
V. CONCLUSION ...57
LIST OF ATTACHMENTS
Over the last few years, the electric utility industry has begun a transition from the traditional vertically-integrated utility model to a restructured competitive model. The reliability of electric service and the feasibility of new competitive markets depend on the integrated and coordinated operation and planning of the generation, transmission, and distribution systems. A failure to perform by any participant or the failure of major system components can have a significant impact on grid reliability leading to outages affecting other participants, customers, and even the entire delivery infrastructure. This point is illustrated by two significant and widespread system blackouts on July 2, 1996, and August 10, 1996, when the Western System Coordinating Council's ("WSCC") Western Interconnection experienced cascading power outages affecting millions of customers. 1/ In both instances, the root cause of the widespread outage was a localized problem.
WSCC members play important roles in keeping the Western Interconnection in a stable and reliable operating state. Each interconnected generator produces electricity that flows over transmission lines to serve customer loads. This large network of generators, lines and loads is like a large, complex, finely-tuned machine serving customers throughout the Western United States, Canada, and a part of Mexico. If suddenly a large generator, a large transmission
1/ Western Interconnection means the area in which members of the WSCC operate synchronously connected transmission systems.
path, or a large load trips off the network, the frequency of the current flowing across the network will shift -- up or down -- from 60 Hz as the whole network reacts to the incident. 2/ System design, criteria, and operating procedures are intended to create a “cushion” or margin that helps the system withstand sudden changes in operating conditions. If, for some reason, the system is not able to respond adequately to changes in frequency, however, the result could be outages that are localized, regional, or Interconnection-wide in scope.
Under the largely vertically integrated structure that previously characterized the electric industry, a system of voluntary cooperation and collaboration among a relatively few utilities was able to maintain reliable operation of the electric grid. As competition and restructuring progress, many new entities are entering the market and generation ownership is being increasingly separated from transmission ownership. Some of the new market participants, including newly created affiliates of existing market participants, are neither directly accountable for assuring a reliable network nor subject to any regulatory sanctions if system integrity is not maintained. Yet the operation of the power grid and electric system reliability remain dependent upon all of these elements functioning together. Under these circumstances it has become increasingly apparent that the industry can no longer rely on the same voluntary approach for
2/ Generators produce electricity or “alternating current” (hence, the term “AC” power) that alternates from positive to negative at 60 cycles per second (or 60 “Hertz” - abbreviated “Hz”). As long as the “frequency” of this alternating electricity stays at 60 Hz the system is termed “stable.”
reliability management, and a broad consensus has emerged among all segments of the industry as well as involved federal and state agencies that some form of enhanced reliability management system is essential to maintain reliability as the transition to competitive markets proceeds.
Ultimately federal legislation governing reliability may be required, but in the absence of legislation and motivated by the 1996 blackouts, the WSCC Board of Trustees in March 1997 established a policy group and three task forces to develop the Reliability Management System ("RMS"), which is the subject of this Request for Business Review. The RMS policy group and task forces operated through an open process, involving the participation of WSCC members, non-WSCC member market participants, and the regulatory community. Materials were made available starting in 1997 to RMS policy group and various task forces and later to interested parties as they were developed, at workshops, by e-mail, and on the WSCC's website. During the latter part of the development process, the various iterations of the complete RMS proposal were available to all interested parties through the WSCC website. The final drafts were subject to review by all participants in a series of workshops and meetings.
The RMS calls for WSCC member transmission operators to agree, through contracts with the WSCC, to comply with selected basic WSCC reliability criteria. 3/ Each transmission operator that executes these agreements with the
3/ Under the RMS, "transmission operators" are defined as all WSCC control area operators and the operators of transmission facilities. Control area operators are those entities responsible for operating an electrical system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to
WSCC would be contractually bound to operate its own system in compliance with the mandatory criteria and also to require other generation owners who enter into new or amended interconnection agreements with its system to comply with the RMS and be subject to WSCC sanctions for noncompliance.
Under the proposed RMS, noncomplying entities would be subject to sanctions ranging from letters indicating noncompliance to monetary sanctions. Initial determinations of compliance would be made by the WSCC staff. All initial determinations by the WSCC staff could be appealed by the affected party to a Reliability Compliance Committee ("RCC"). Challenges to sanction determinations by the RCC could be made through alternative dispute mechanisms, and ultimately by appeal to the Federal Energy Regulatory Commission ("FERC") or court.
In December 1998, the members of the WSCC approved a course of action designed to achieve implementation of the RMS by July 1, 1999. 4/
A condition precedent to implementation of the RMS is that the WSCC obtain a satisfactory Business Review Letter from the Department of Justice ("DOJ"). Transmission operators will individually decide whether to join the RMS after
maintain an interchange schedule with other control areas and contributing to frequency regulation in the Western Interconnection.
4/ The Membership decided to proceed with this filing and a filing at the FERC by a vote of 58 yes to 5 no. Transmission operators covering more than 90% of the transmission load in the Western Interconnection have indicated their willingness to participate subject to obtaining a satisfactory Business Review Letter and FERC Order.
FERC action on the WSCC's filing and the DOJ's response to this Request. No transmission operator is required to participate in the RMS, and there are no sanctions for non-participation. 5/
This memorandum explains how the RMS serves the fundamentally procompetitive purpose of enabling the existing transmission facilities operated and used by members of the WSCC to accommodate emerging competition and the entry of a wide variety of new market participants while preserving the capability of the system to maintain and deliver reliable electric service.
In its initial phase, Phase I, the RMS will be implemented through three basic types of documents:
(1) The WSCC Reliability Criteria Agreement;
(2) RMS Agreements between the WSCC and a transmission operator; and
(3) Generator Agreements between transmission operators and interconnected generators.
Implementation of the RMS will involve the following steps:
(1) data required to monitor compliance will be provided by transmission operators and interconnected generators directly to the WSCC staff;
(2) WSCC staff will review the reported data;
(3) if the WSCC staff determines that the data indicate potential noncompliance, it will provide the affected transmission
5/ The WSCC's standards, policies, procedures, and criteria would continue to apply to non-participating transmission operators that are members of the WSCC but only on a voluntary basis and without such operators being subject to WSCC sanctions.
operator or interconnected generator the opportunity to submit additional or corrected data;
(4) the WSCC staff will be responsible for making an initial determination of noncompliance with the specified criteria;
(5) participants that receive an initial determination of noncompliance from the WSCC staff may appeal such an initial determination to the newly-created RCC, which will be composed of representatives of the regulatory community and all industry sectors; 6/ and
(6) if a party disputes a determination by the RCC, it may pursue alternative dispute resolution procedures, followed by an appeal to the FERC or the courts.
One of the important reasons for developing a mandatory RMS system is to provide for an equitable sharing of the burdens and costs of maintaining system reliability. Although all members of the WSCC have committed themselves to comply with the WSCC reliability criteria on a voluntary basis (i.e., without sanctions), information gathered during an evaluation period from February through September 1998, indicates a significant number of instances of noncompliance. When such incidents occur, additional burdens are placed on other system operators who must make up, if they can, for any deficiencies of the non-complying entities. To the extent other systems cannot make up the deficiency, all are placed at risk because the margin of safety upon which the reliability of the
6/ The RCC will consist of one representative from each of the following industry sectors: (1) major transmitting utility; (2) transmission dependent utility; (3) independent power producer; (4) electric power marketer; (5) state, provincial, or local regulatory body; (6) municipal utility system; and (7) control area or independent system operator. If the WSCC authorizes a new class of voting membership for the WSCC (such as large customers), the WSCC Board of Trustees may add an additional member as a representative to the RCC from such class.
system is dependent is eroded. The transmission system is intentionally designed to cope with contingencies, which may occur at any time. If some participants do not comply with reliability standards, the transmission system operating limits can be impaired, exposing the system to increased risk of failure. By establishing sanctions for noncompliance, the RMS encourages all parties responsible for maintaining reliability to do their fair share and discourages “free-riding.”
Phase I of the RMS, which is the subject of this Request, seeks to strengthen incentives for those operating and using the Western Interconnection’s transmission system to comply with selected criteria that relate directly to the maintenance of the 60 Hz frequency along with the voltage of the electrical network. The Phase I criteria are:
1. Operating Reserve Requirements
2. Disturbance Control Standards (DCS)
3. Control Performance Standards (CPS)
4. Operating Transfer Capability (OTC) Requirements
5. Generator Power System Stabilizer (PSS) and Automatic Voltage Regulator (AVR) Requirements
Compliance with these criteria under the terms of the RMS should not generate anticompetitive consequences because the WSCC has taken specific steps designed to provide for fairness and objectivity, to avoid potential commercial disparagement, and to minimize the likelihood that the burdens of compliance will result in competitive advantage or disadvantage for any market participant or group of market participants.
Throughout the process of developing the RMS, the WSCC has been mindful of the need to limit the scope and effect of the RMS to achieve compliance with reliability standards without impeding the growth of competition in the electric industry. Thus, the RMS was developed after public consultation involving all traditional segments of the industry, the owners and operators of transmission, generation, and distribution facilities, as well as regulators, marketers, aggregators, power traders, and other stakeholders in the electric industry. Although some members have expressed some concerns about communications during early stages of the drafting of the RMS contracts, the process for adoption of the RMS was intended to be inclusive. Intermediate and final drafts of the RMS documents and FERC pleadings were made available to the public on the WSCC's website, and comments were received and considered from a broad spectrum of participants over several months. The RMS documents were amended on the basis of such comments.
The measures adopted for implementation of the RMS have also been fashioned with the principles of procedural fairness, objectivity, and inclusiveness as basic goals. The memberships of the WSCC Board and the RCC have been carefully balanced to include representatives of affected stakeholders. To the extent that sanctions are called for, they will be implemented according to pre-established, objective criteria by the WSCC staff. The WSCC staff will observe strict confidentiality guidelines to prevent inadvertent disclosure of compliance-related information. The task of the staff will be to collect and analyze data and information concerning compliance, including information which in certain specified instances will excuse noncompliance, and, based on the data provided, to follow specified procedures that call for application of sanctions in accordance with a matrix of sanction levels set forth in the RMS. The WSCC staff will not have discretion to deviate from the pre-established sanction levels or to waive any of the requirements of the RMS.
To protect against error and to avoid any potential for abuse of the RMS sanctions for anticompetitive purposes, no sanction can be deemed final until a participant has waived or exhausted an appeals process. All appeals will be heard in the first instance by the RCC, which again is restricted solely to fact finding, including facts which may establish an instance of excused performance as provided for in the RMS agreements. After the RCC has acted, appeals may be taken to arbitration and/or to the FERC or court. Again, to avoid any premature disclosure or potential misuse of information, the RMS imposes confidentiality requirements on the members of the RCC and any arbitration.
In sum, the RMS has been designed to maintain the reliability of the Western Interconnection as the electric industry evolves into a highly competitive power marketplace made up of multiple independent market participants. The WSCC believes that the RMS will strengthen incentives for maintaining the reliability of the system without having any effect on the kinds of services that generators may provide or customers may seek. The RMS, by helping maintain reliability in the face of newly competitive markets, permits users to enjoy the benefits of those markets -- the potential for lower prices and an increased variety of services -- without fear that such benefits will be obtained at the cost of reduced security and reliability of the network. For this reason, the WSCC requests that the Department promptly issue a favorable business review letter.
Re: MEMORANDUM IN SUPPORT OF REQUEST FOR BUSINESS REVIEW OF PROPOSED RELIABILITY MANAGEMENT SYSTEM
From: Western Systems Coordinating Council
Pursuant to 28 C.F.R. § 50.6 (1998), the Western Systems
Coordinating Council (“WSCC” or the “Council”) on behalf of itself and certain of its members 7/ hereby respectfully request that the Antitrust Division of the U.S. Department of Justice (“DOJ” or the “Department”) issue a Business Review Letter stating that the Department has no present intention to bring an enforcement action against the WSCC or its members joining this Request if the WSCC implements a proposed reliability management system (“RMS”) as described herein. 8/ Review is requested because maintenance of reliable electric service within WSCC’s Western Interconnection requires cooperation among industry participants some of whom are, or may be, competitors.
7/ This Request is being simultaneously circulated to all WSCC members; those members which will sign letters joining in the Request will be identified by a subsequent filing.
8/ Review of the RMS is within the scope of the Department’s Business Review Procedure insofar as it concerns the flow of electric energy through the interconnected electric power systems in the WSCC’s Western Interconnection, and thus involves activities that are conducted in interstate commerce. 28 C.F.R. § 50.6.2.
The Request for Business Review contains full and complete disclosure with respect to the business conduct for which the WSCC and its members request review. Relevant data, including background information and complete copies of all operative documents are included here as Attachments A through F. The WSCC will provide any additional supporting information or documents that the Department may hereafter request to further its review of this matter. 9
The purpose of the WSCC -- one of the ten electric reliability councils in North America 10/ -- is "to promote regional planning and the reliable operation" of the Western Interconnection. 11/ The "bulk power system" in the Western Interconnection contains over 100,000 circuit miles of high-voltage transmission lines and interconnected generation in fourteen Western states, two Canadian provinces, and a portion of Mexico. These lines are interconnected and operated by thirty-one control areas as a single synchronous network or "interconnection," one of three interconnections in the United States. The facilities of the Western
9/ Id. § 50.6.5.
10/ The WSCC is the largest of the ten regional councils of the North American Electric Reliability Council ("NERC"). NERC is a non-profit corporation owned by the regional councils.
11/ WSCC Agreement and Bylaws, Art. I, § 1. Currently there are 107 members of the WSCC, including state regulatory agencies, generators and marketers, as well as transmission operators. The WSCC Board of Trustees is currently composed one-third of representatives of major transmission utilities, one-third of representatives of transmission dependent utilities, and one-third of representatives of marketers and independent generators.
Interconnection transmit over 700,000 gigawatt hours of energy per year, virtually all of the electric energy consumed in this area.
The reliability of electric service throughout this vast area depends on the integrated and coordinated operation and planning of the interconnected generation, transmission, and distribution systems so as to maintain the synchronism and hence the stability of the Western Interconnection. 12/ Lack of coordination among participants, significant deviations from established operating parameters, noncompliance with criteria, or the failure of major system components can have a significant impact on reliability throughout the Interconnection, resulting in the loss of power and concomitant economic losses to system users and end-use customers. Experience in the Western Interconnection, including the wide spread system outages on July 2, 1996 and August 10, 1996, affecting millions of people, has demonstrated that problems with localized origins that appear to be limited to only one or a few participants' facilities can cascade outward across a significant portion of the network. 13/
Under a system made up principally of vertically-integrated monopolies, voluntary cooperation and collaboration was able to maintain reliable
12/ In a "synchronous" network, all generators must rotate together with split-cycle synchronism. This requires the coordination of all interconnected generation throughout the Western Interconnection.
13/ See WSCC Disturbance Report for the Power System Outage that Occurred in the Western Interconnection July 2, 1996, 14:24 MAST, July 3, 1996, 14:03 MAST (July 1996 Disturbance Report"); WSCC Disturbance Report for the Power System Outage that Occurred in the Western Interconnection, August 10, 1996, 15:48 PAST ("August 1996 Disturbance Report").
operation of the electric grid. Indeed, that system has served to ensure both the adequacy and security of the electric power delivery system. As competition grows and restructuring proceeds, generation ownership is being separated from transmission ownership, and many new entities are entering the market. In the changed circumstances, the industry can no longer rely on the traditional voluntary approach for reliability management. This conclusion was central in the recent report of a Department of Energy ("DOE") blue-ribbon panel.14/ This report emphasizes the need for prompt steps to protect the continued reliability of the bulk power system in the face of commercial restructuring of the electric industry. As the report concludes (and cautions):
The traditional reliability institutions and processes that have served the Nation well in the past need to be modified to ensure that reliability is maintained [in the newly-restructured markets] in a competitively neutral fashion, without favoring one or another set of market participants.
Id. at x (emphasis added). 15/
14/ See Secretary of Energy Advisory Board, U.S. DOE, Maintaining Reliability in a Competitive U.S. Electric Industry, Final Report of the Task Force on Electric System Reliability (Sept. 29, 1998) ("Advisory Report"), contained in Attachment A.
15/ The Federal Energy Regulatory Commission ("FERC"), an agency charged with economic regulation of the wholesale power industry, has similarly and repeatedly emphasized the importance of reliability in a restructured electric industry. See, e.g., Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Stats. & Regs., Regulations Preambles January 1991 - June 1996, ¶ 31,036, at p. 31,635 (1996) ("Order No. 888") (emphasis added); order on reh'g, FERC Stats. & Regs., ¶ 31,048 (1997) ("Order No. 888-A"); order on motions for clarification, 81 FERC ¶ 61,248 (1997) ("Order No. 888-B"); order on rehearing, 82 FERC ¶ 61,046 (1998) ("Order No. 888-C").
Ideally, the matter would be addressed by federal legislation creating clear regulatory authority with respect to reliability issues, but, in the absence of such legislation, most WSCC members believed, and continue to believe, that it would be prudent to implement the RMS expeditiously in an effort to maintain the reliability of the Western Interconnection.
Motivated by these concerns and the two large-scale 1996 outages the WSCC Board of Trustees, in March 1997, established a policy group and three task forces to develop the RMS and a proposed implementation plan. The RMS policy group and task forces operated through an open process, involving the participation of WSCC members, non-WSCC member market participants, and the regulatory community. Portions of the RMS proposal were available for review and comment during 1997 at workshops, on the WSCC website, and at the 1997 WSCC annual meeting. To facilitate access and to further encourage the widest possible participation, drafts of the proposed RMS agreements and filings developed in 1998 were posted on the WSCC website beginning in July 1998. These drafts were subject to review and revision at subsequent workshops and meetings of the Policy Group as well as the WSCC's annual membership meeting in December.
Under the proposed RMS, WSCC member control area and transmission operators would agree through contracts with the WSCC to comply with selected WSCC reliability criteria. 16/ Transmission operators who execute
16/ Under the RMS, "transmission operators" are defined as all WSCC control area operators and the operators of transmission facilities. Control area operators are those entities responsible for operating an electrical system or systems, bounded these agreements with the WSCC would be contractually bound to operate their own systems in compliance with the mandatory criteria and also to require other generation owners who enter into new interconnection agreements with their systems to comply and be subject to WSCC sanctions for noncompliance. These contracts are described in more detail in Section II.B. of this memorandum.
Participating entities would be subject to sanctions for noncompliance ranging from letters indicating noncompliance to monetary sanctions and, in the case of the Disturbance Control Standard, the requirement to maintain increased operating reserves. Initial determinations of noncompliance would be made by the WSCC staff. All determinations by the WSCC staff could be appealed by the affected party to a Reliability Compliance Committee ("RCC"), which will include representatives from various industry segments and the regulatory community. 17/
by interconnection metering and telemetry, capable of controlling generation to maintain an interchange schedule with other control areas and contributing to frequency regulation in the Western Interconnection.
17/ The RCC members are to be appointed by the WSCC Board of Trustees. The members, who will be selected through an open, publicly-noticed process, will include representatives of each of the following industry sectors: (1) major transmission owners; (2) transmission dependent utilities; (3) independent power producers; (4) electric power marketers; (5) state, provincial, or local regulatory bodies; (6) control area and independent system operators; and (7) municipal utilities. Further, the RMS requires that, to the extent practicable, the RCC reflect the geographical diversity of the WSCC membership, cover both public and privately-owned entities, and include no more than three members at any one time that could qualify as representatives of the same industry sector. In addition to its review-related responsibilities, the RCC must periodically review the implementation of the RMS and make recommendations to the WSCC Board of Trustees for suggested modifications to the program.
Challenges to sanction determinations by the RCC could be made through alternative dispute resolution procedures, or ultimately an appeal to the FERC or court.
In December 1997, the members of the WSCC approved implementation of an evaluation program during 1998 to determine the suitability and workability of the proposed RMS. The evaluation program began in February 1998, with the initial collection of reliability data by WSCC control areas and others. The data have been reported to WSCC staff on a monthly basis during the evaluation program, but no sanctions were issued for noncompliance.
Based on this experience, the members of the WSCC approved the implementation of Phase I of the RMS, subject to obtaining a satisfactory Business Review Letter from the DOJ and, with respect to FERC jurisdictional entities, a satisfactory order from the FERC. 18/ The WSCC would like to implement the Phase I RMS by July 1, 1999, although that date would be deferred until such time as the Antitrust Division acts on this Request. 19/ If the RMS is implemented, no
18/ See Attachment B (containing WSCC's RMS Resolution dated December 4, 1998). The resolution was approved by a vote of 58 yes to 5 no.
At an earlier meeting in November 1998 attended by persons favoring the adoption of the RMS, a number of transmission operators and other members of the WSCC, covering more than 90% of the transmission load, agreed to implement the RMS Phase I as drafted, subject to certain conditions, principally obtaining a satisfactory Business Review Letter from the DOJ and, with respect to FERC jurisdictional entities, a satisfactory order from the FERC. See Attachment C (containing position statement on WSCC's RMS dates).
19/ On December 28, 1998, the WSCC filed with the FERC a petition for declaratory order asking the FERC to assert jurisdiction over certain aspects of the RMS. The WSCC requested that the FERC issue the declaratory order by no later
transmission operator is required to participate, and there are no sanctions for non-participation. Non-participating WSCC control areas as parties to the WSCC Agreement would continue to be subject to the WSCC's standards, policies, procedures, and criteria but only on a voluntary basis, as they are presently, and without being subject to WSCC sanctions.
As a final note of introduction, the WSCC's initiative may be the model for other regional organizations in the absence of legislation. As NERC itself reiterated in comments filed with the FERC regarding the RMS, quoting the report of its blue-ribbon Electric Reliability Panel:
Pending adoption of legislation establishing the statutory foundation for NAERO [North American Electric Reliability Organization] to serve as a self-regulating organization, NERC and the Regional Councils should pursue as diligently as possible the alternative being formulated by the Western Systems Coordinating Council (WSCC Reliability Management System) or other possible alternatives which would not require federal legislation. Regardless of whether and when legislation is enacted, this process should advance NERC/NAERO toward the goal of promulgating and enforcing reliability standards for the entire bulk electricity industry. 20/
than March 31, 1999, so as to permit the WSCC and RMS participants to modify the RMS as necessary to reflect the FERC's guidance, to file related contracts and amendments with the FERC, and to obtain FERC orders accepting such contracts and amendments for filing before the proposed implementation date of the RMS, July 1, 1999. See discussion in Section IV, infra.
20/ See Attachment D, Motion to Intervene of North American Electric Reliability Council in FERC Docket No. EL99-23-000, Jan 22, 1999, at p. 3.
In Phase I, the RMS will entail the imposition of pre-determined sanctions for noncompliance with selected existing reliability standards. 21/ A WSCC task force, comprised of experienced engineers and technical experts from WSCC members, as well as non-members and regulatory representatives, determined the specific criteria to be included in Phase I of the proposed RMS program. These selected criteria represent those judged to be most critical for system reliability at the present time.
The criteria-selection process used by the WSCC task force began with a review of all existing WSCC operating reliability criteria. The task force ranked each by high, medium, or low impact on reliability. The task force employed the following standards to rank the criteria:
1. The greater the impact of the criterion on frequency or voltage performance the higher the ranking. 22/
21/ In total, there are 17 criteria that the WSCC intends to phase-in over a three-year period. The criteria that are submitted with this Request are to be implemented first. It is contemplated that the remaining criteria, which are not covered by this Request, will be added to the RMS in two phases, during the second and third years following implementation of the initial criteria. Similar to the first set of criteria, the addition of new criteria to the RMS will be preceded in each case with an evaluation period during which data will be collected, but no sanctions will be enforced. This Request does not address the additional criteria that may be added in subsequent phases.
22/ Each interconnected generator, transmission line, and electric load plays an important role in keeping the electrical network in a stable and reliable operating state. This large network of generators, lines, and loads is like a large, complex, finely-tuned machine. Generators produce electricity or “alternating current” (hence, the term “AC” power) that alternates from positive to negative at 60 cycles per second (or 60 “Hertz” – abbreviated “Hz”). As long as the “frequency” of this
2. Higher rankings were given to criteria where noncompliance would increase the risk of the following:
3. Criteria that in the past were violated during system disturbances.
4. Criteria that are measurable, can be monitored at all times, and described as having the larger impact were ranked higher.
The Phase I criteria selected pursuant to this process are described in detail below.
The oldest existing reliability measure is the requirement to maintain operating reserves. The operating reserve criterion specifies the amount of additional generation that is to be kept available at all times to help maintain scheduled frequency and to avoid the loss of firm load following transmission or generation contingencies. Operating reserves supply capacity to respond to instantaneous load variations, replace capacity lost due to a forced outage, meet on-demand obligations to other entities, and replace the loss of imports from other entities. As competitive pressures to control costs increase, it is particularly
alternating electricity stays at 60 Hz, the system is termed “stable.” If suddenly a large generator, a large transmission path, or a large load trips off the network, the frequency will shift -- up or down -- from 60 Hz as the whole network reacts to the incident. The Phase I criteria discussed below relate directly to the maintenance of this 60 Hz frequency along with the voltage of the electrical network.
important that transmission operators and generators not reduce the level and availability of operating reserves below specified levels. To do so would increase the potential that customer outages, both in the control area itself and in other interconnected control areas, could result from the unexpected loss of a significant generating resource or transmission facility.
Operating reserves are required for each transmission operator to meet its regulating responsibility (so that one system does not place a burden on the interconnection with additional regulating costs), and to meet its contingency and non-spinning reserve requirements to provide acceptable system recovery for the largest single hazard. Inadequate reserves in a single major control area or in several smaller control areas simultaneously, at a time of unexpected unit outages, can lead to system frequency decline and ultimately cascading outages.
The operating reserve levels for each control area or reserve-sharing group is determined in accordance with WSCC's "Minimum Operating Reliability Criteria" ("MORC"). Each control area or reserve sharing group is expected to maintain minimum operating reserves, which consist of regulating reserves, contingency reserves, and additional reserves for interruptible imports and on-demand obligations. These reserve requirements are industry standards that have been in place for many years and are consistent with NERC operating reserve requirements for North America.
Operating reserves are readily measurable. Regulating reserves are the amount of spinning reserves responsive to Automatic Generation Control ("AGC") sufficient to allow the control area to meet NERC control performance criteria (CPS1 and CPS2 described infra, Section II.A.3). Contingency reserves are the amount of spinning reserve and non-spinning reserve sufficient to reduce area control error ("ACE") 23/ to zero within ten minutes after loss of generation or transmission resulting from the most severe single contingency to avoid burdening other control areas. The standard also sets a minimum level of contingency reserves as a percentage of generation. Spinning reserves must make up at least fifty percent of the contingency reserve requirements. Non-spinning reserves are not connected to the system but are capable of being connected and loaded within ten minutes. Operating reserves are necessary to maintain reliability within the control area and to avoid burdening other control areas following the loss of generating capacity.
Each control area monitors operating reserves in real time. Some WSCC members are participants in reserve sharing groups wherein the largest single hazard is covered by a group of control areas instead of a single control area. This may reduce the amount of reserves carried by each control area without jeopardizing the interconnected system's ability to compensate for loss of on-line generation.
When a generator unexpectedly becomes disconnected from the system, the demand for electricity suddenly exceeds the supply. Unless corrected, this imbalance between the supply and demand for electricity will cause the system
23/ ACE is the instantaneous difference between actual and scheduled interchange modified by the frequency bias obligation.
frequency to decline and settle at a level below 60 Hz. If one entity fails to correct for the outage of its generation, an unfair burden is placed on the other entities in the Interconnection to replace the lost generation and restore frequency to 60 Hz. The lost generation must be replaced quickly to return the system to normal operation and to allow it to withstand other outages that might occur unexpectedly. Replacement of the lost generation in an uncontrolled manner from neighboring areas could result in power flows between control areas that exceed transmission limits.
The DCS criterion requires that control areas maintain sufficient generating resources to return the electrical system to normal or to pre-disturbance levels within ten minutes following a disturbance. Within North America, ten minutes has been the long-standing accepted time standard for recovery following the outage of a generating unit or other disturbance that creates an imbalance between the supply of and demand for electricity.
Generating unit outages are common occurrences that may result from a wide number of possible problems. DCS is an important indicator of a control area's responsiveness to a generator outage. As a group, control areas need to have assurance that neighboring (interconnected) systems are operating in a manner that can withstand an expected level of generator outages. In the absence of compliance with a DCS standard, multiple unit outages could occur with no provision for recovery. Such an event could lead to a severe and unrecoverable decline in system frequency, overloaded transmission, cascading outages, and ultimately a blackout of the interconnected electric system.
The DCS criterion states that ACE must return to zero or to its pre-disturbance level within ten minutes following the start of the disturbance. Measuring ACE is a normal function of each control area's computerized monitoring and control system, referred to as the Energy Management System ("EMS"), and the measurement is carried out on a continuous basis. The ACE measurement is used to calculate "Average Percent Recovery" for each incident. Formulae and calculations for DCS and Average Percent Recovery are set out in NERC Operating Policy 1 and the NERC Performance Standard Training Document. The criterion requires an operator to maintain an Average Percent Recovery of one hundred percent for each quarter. 24/
Control areas train personnel to restore ACE to zero within ten minutes as part of standard operating practices. Control centers for control areas are staffed at all times, and control room operators are expected to restore ACE to zero or pre-disturbance levels within ten minutes.
There are two Control Performance Standards, CPS1 and CPS2. Compliance with the Control Performance Standards reduces the potential for transmission operators in one area to burden other transmission operators through
24/ Minimum DCS reporting is for disturbances greater than the lesser of 300 MW or 80% of the Control Area's single largest generation hazard. Disturbances greater than the largest generation hazard are not included in the Average Percent Recovery calculation.
inadvertent interchange or through inadequate frequency control. Proper frequency control is essential to reliable system operation.
One of the major indicators of the health of the electrical grid is system frequency. System frequency is maintained at the correct level by continuously balancing generation with load. If perfect balance is maintained, the system frequency will be 60 Hz -- the standard at which electric power grids in North America are designed to operate. If generation is inadequate (not enough to meet customer demand), system frequency will fall. If there is an excess of generation (usually caused by loss of customer load), system frequency will rise.
Unprotected electric generators and electric motors may become damaged if they are operated at significantly higher or lower frequencies than 60 Hz. If the frequency is not maintained close to this level, the protection systems for generating equipment (and some critical load equipment) will automatically disconnect the generator or motor from the system to prevent damage. For example, if the frequency is only 0.5 Hz above or below 60 Hz, some electric generators will be disconnected by their protective devices within three minutes to prevent damage to the generators. Wider deviations can lead to instantaneous disconnection. Because a generator is basically a flywheel spinning inside a large iron core, within very close tolerances, frequency problems can cause serious damage. A seriously damaged generator may be out of service for a long time, which decreases the interconnected system's available generating capability and therefore reduces the number of tools available for managing reliability in the affected area.
Protection systems continually monitor the safe operating conditions of generators and other equipment. If the equipment limits are exceeded, such protection systems automatically remove the equipment from service very quickly before damage occurs and before the entire system can become further out of balance. If the frequency is 1.5 Hz above or below 60 Hz, the protective devices will disconnect many of the generators and motors within a period of a few seconds. This very short period would not allow enough time for system operators to implement corrective measures to restore proper system frequency and avoid damage to the generators and motors. Therefore, it is very important that frequency be controlled automatically. In the absence of automatic frequency control, relatively minor problems in separate control areas could compound and cause cascading outages of generators due to operation of their protective devices, which might result in a system wide blackout. The CPS1 control performance standard is a measurement of how well each control area controls frequency.
CPS1 is the measure of the short-term error between load and generation. If the control area exactly matches generation to load, or if the mismatch is in the direction to cause system frequency to be driven closer to 60 Hz, CPS1 performance will be good. If the control area has a mismatch between generation and load that will cause system frequency to be driven further from 60 Hz, CPS1 performance will be degraded.
The CPS2 standard helps maintain CPS1 and prevent excessive power flows. The CPS2 standard requires each transmission operator to maintain its average ACE within specified limits for each ten-minute period. The CPS2 standard requires each control area operator to maintain its average ACE within specified limits for each ten-minute period. By adhering to CPS2, the resulting system control places bounds on ACE to prevent excessive interchange deviations. Without CPS2, the frequency control embodied in CPS1 could result in a very large inadvertent interchange. CPS2 measures how well control areas avoid excessive generation-load mismatch, even if the mismatch is in the correct direction. This is because large mismatches can cause excessive power flows and potential transmission overloads between the areas with over-generation and insufficient generation. If the bound imposed by CPS2 is exceeded, CPS2 performance will be degraded. The consequences of excessive power flows with respect to reliability are described below in the context of the Operating Transfer Capability criterion.
NERC adopted CPS1 and CPS2 for the North American power grids in February 1998, after several years of rigorous research. In October 1996, many utilities participated in a pilot program to test and verify the validity of the CPS1 and CPS2 standards. CPS1 and CPS2 are readily measurable and are a normal function of each control area's EMS. The measurements are carried out on a continuous basis with data recorded for each minute of operation. The formulae and calculations are clearly delineated in NERC Operating Policy 1 and the NERC Performance Standard Training Document. Both of these documents are part of the NERC Operating Manual.
The minimum acceptable performance level for CPS1 is 100%. Perfect control would result in a performance level of 200%. The minimum performance level for CPS2 is 90%. Perfect control would result in a performance level of 100%. Control areas that meet normal expectations in matching generation with load should not have a problem meeting the CPS1 and CPS2 performance criteria.
The Operating Transfer Capability criterion requires that the actual power flow on a bulk power path be maintained within the path's operating transfer capability limit. 25/ This criterion is intended to protect the physical transmission facilities and increase the likelihood that facilities will be operated within reliable limits. If transfer capability limits are exceeded both in magnitude and time-duration, the unexpected outage of a transmission element or a loss of a generating unit could result in power flows on the affected path to the point where protective relays would trigger. If the affected path is taken out of service and the corresponding shifts in power flows overload other facilities, the ultimate result could be widespread system disturbances.
OTC is the maximum power transfer level across a transmission path that will meet WSCC's Reliability Criteria for Transmission System Planning and Minimum Operating Reliability Criteria ("MORC"). The OTC may vary by season, and can be affected by changing generation patterns, customer load levels, transmission lines in service, voltage support equipment, and a variety of other system conditions.
If the OTC stability limits are exceeded, the potential for a system-wide disturbance that could cause a widespread blackout is increased. 26/ For
25/ Transmission path transfer capability limits reflect different limits under different operating conditions (e.g., seasonal flow, load variations, simultaneous transfers).
26/ There are two basic types of limits for transmission lines – stability limits and thermal limits. A thermal limit is a limit that must be met to prevent example, if a transmission path is operating above its stability limit, the outage of the line could result in growing oscillations, cascading outages of other lines and generators, and uncontrolled customer outages.
If OTC thermal limits are exceeded, the facilities that are operated above thermal limits are subject to damage due to overheating. If the facility is a transmission line, the line will sag excessively due to the expansion of the metal in the line caused by the excessive heat. In some cases, thermally overloaded lines will sag too close to underlying vegetation and will be disconnected by protective relays. Line outages of this nature can result in overloading and subsequent tripping of parallel lines. Under worst-case conditions, this scenario can lead to cascading outages of other equipment and a system blackout.
If contingencies occur that cause a path OTC limit to be exceeded, the appropriate transmission path operator, transmission operator, and security coordinators must take all steps available up to and including declaring an emergency to reduce the path transfer level below its OTC. The OTC measurement for real-time operation is the actual power flow and the scheduled power flow across
overheating of equipment. A stability limit is a limit that must be met to preserve the stability of the system. If the system becomes unstable due to exceeding the stability limit, voltages, line flows, and other system parameters will oscillate uncontrollably until various protective devices operate to disconnect transmission lines, generators, and loads resulting in a blackout. Because many transmission paths in the Western Interconnection have stability limits that are lower than the thermal limits, the system is termed “stability limited.”
an interconnection or transfer path. Time duration of flows exceeding OTC is also measured.
Although the RMS requires a transmission operator to maintain power flows within a path's OTC, the RMS does not itself determine the setting of the OTC limits for each path. Rather, the OTC limits are currently set on a seasonal basis by the Operating Transfer Capability Group. The OTC Group is appointed by the WSCC's Board of Trustees and includes representatives of the three membership classes and a mix of policy, operating and planning personnel with geographical diversity. The OTC Group makes its decisions after receiving the recommendation of the WSCC's subregional study groups which are responsible for the necessary technical studies. The studies, analyses and models used to recommend OTC limits are made available for comment to all members during the process and prior to approval of the seasonal OTC limits. 27/ The OTC limits themselves and the method of establishing them are not a subject of this Request.
27/ The current procedures for determining OTC were adopted to make the approval process more efficient and to address concerns expressed in 1997 by several members about the procedures which were adopted just after the 1996 disturbances. Early in 1997, the Board of Trustees, concerned about the widespread outages which occurred in 1996, reduced the OTC limit for the California-Oregon Intertie/Pacific DC Intertie below that recommended by the OTC Group. The revised procedures are intended to assure that to the extent reasonably possible OTC limit determinations are made by a diverse group on the basis of technical engineering studies and policy judgments.
The PSS and AVR criteria require all generators that are equipped with PSS or AVR to have that equipment in service and operating properly when the generation is on-line. 28/ Operating this equipment helps to maintain a stable and secure interconnected electric system. Absent PSS, system stability could not be maintained. Absent AVR, it would be considerably more difficult to maintain adequate transmission system voltages and reactive control.
The Western Interconnection is stability limited. As previously noted, an interconnected electric system operates essentially as a large synchronous machine. 29/ The three main component classes of the system are generators (sources), loads (sinks), and transmission (the transportation system). All of these components share an important role in preserving the reliability of the system. The operation of a large interconnected power system is dynamic – meaning that changes in generation output, load levels, or transmission availability create a need for the system to rebalance very quickly. This is especially true for stability limited systems like the Western Interconnection.
28/ In Phase I, existing generators are not required under the RMS to have PSS and AVR equipment, although their existing interconnection agreements may require them to have such equipment. In addition, certain generators with specified capacity and other characteristics are required by WSCC criteria which are not part of the RMS to have AVR and PSS equipment.
29/ See footnote 21 supra.
In many cases, stable adjustment depends on the action of automatic controls, since the time necessary for human intervention would take too long to be effective. Generator AVR and PSS controls play an important role in continually responding to system changes and disturbances throughout a normal day, week, and season.
PSS's are essential in the Western Interconnection to maintain system stability under normal system conditions and following a disturbance. PSS's are control devices that are connected to a generator's excitation system. The PSS's are used to monitor machine accelerating power, slip, or other system parameters. Based upon variations in these parameters, the PSS's provide input signals to the generators' excitation systems to respond to system conditions in such a way that positive dampening is provided to the system. If a sufficient number of generators in the Western Interconnection were not equipped with PSS's, technical studies indicate that the system would be inherently unstable.
Most of the generating capacity in the Western Interconnection is equipped with PSS's. These control devices are effective in mitigating disturbances in progress by helping damp oscillations as the system adjusts to the disturbance conditions. PSS equipped generators are the single most important source of this stabilizing action. The MORC and the RMS criteria require that generators equipped with PSS's be operated with them in service. WSCC policies require that the minimum level of PSS units on-line not fall below 60,000 mega volt-amperes ("MVA") WSCC-wide, that all existing units larger than 75 MVA equipped with suitable excitation systems be equipped with PSS, and that all new generators with suitable excitation systems be equipped with PSS. 30/ PSS equipment is to be periodically tested and calibrated. The effectiveness of PSS equipped units is also location dependent and such units must be widely distributed to be effective in dampening common system frequency oscillations.
The AVR provides essential dynamic reactive support to help maintain power system voltages. Reactive support is a key ingredient to maintaining stable voltage levels critical to preserving system reliability and is very location sensitive. For instance, reactive support needed at the California-Oregon border cannot be provided from a generator in Canada or Arizona. Although other power system elements can provide reactive support, most of these are static devices (capacitors) that are less flexible in responding to quickly changing events. Generators, on the other hand, if operating in voltage control mode (i.e., with AVR operational) will respond automatically to changes in system voltage with the right amount of reactive supply or consumption to accomplish the adjustment needed to stabilize voltage levels and maintain reliability. If generators do not have their AVR controls operational, those units (which are uniquely qualified to provide essential dynamic reactive support) do not respond as needed and the ability to facilitate secure transfers of power on the transmission grid may be reduced. The absence of sufficient AVR in key locations can result in voltage collapse and cascading outages. The WSCC MORC requires that all generating units of 10 MVA and larger be
30/ This requirement itself is not part of Phase I of the RMS.
equipped with automatic voltage control equipment and be normally operated in voltage control mode. 31/
The AVR and PSS criteria under the RMS require that each covered generating unit equipped with PSS or AVR (other than units that are operated less than five percent of the total hours in a calendar quarter) be operated in voltage control mode and set to respond effectively to voltage deviations (for AVR equipped generators) and with PSS in service and properly tuned (for PSS equipped generators) greater than ninety-eight percent of all hours the generating units are in operation for each calendar quarter. The controls respond before operator action is possible to maintain system voltage levels and avoid unstable (growing) oscillations which, if not checked, can lead to the tripping of equipment and consequent outages. 32/ Disabled or ineffective controls are a serious risk to system reliability and effectively reduce system operational transfer capabilities. The seriousness of unpredictable or inoperative PSS and AVR is further exacerbated when such conditions are not captured in stability studies used to establish operating limits. For example, if generators operate under voltage control mode sometimes and power factor correction mode at other times, or operate with power system stabilizers on sometimes and off at other times, the simulations which form the basis for real-time operations and dispatch decisions in real time present an
31/ This requirement itself is not part of Phase I of the RMS.
32/ This was believed to be a factor in the August 1996 outage. See August 1996 Disturbance Report at 2.
inaccurate (and overly optimistic) picture of the robustness of the system.
Operation of AVR and PSS on a consistent basis is critical to the reliable operation of the interconnected system.
The RMS will be implemented through the following three types of documents: (1) a WSCC Reliability Criteria Agreement (“Reliability Criteria Agreement”); (2) an RMS Agreement between the WSCC and transmission operators (“RMS Agreement”); and (3) a Generator Agreement between a transmission operator and each interconnected generator (“Generator Agreement”). 33/
The Reliability Criteria Agreement is a multilateral agreement among the WSCC and all transmission operator participants in the RMS. 34/ This single agreement contains all of the reliability criteria, data submission requirements, sanction measures, compliance determination procedures, and alternative dispute resolution procedures for implementing the RMS. In essence, the Reliability Criteria Agreement will operate as a “reliability tariff” that contains the operating terms and conditions of the RMS.
33/ See Attachment E.
34/ Assuming the FERC asserts jurisdiction over the Reliability Criteria Agreement, the agreement would be filed with the FERC and could be modified only through the filing of an amendment with the FERC or through FERC action. See Reliability Criteria Agreement §§ 9 & 13.
The RMS Agreements and the Generator Agreements are the equivalent of “service agreements” under which individual parties agree to be bound by the terms and conditions in the Reliability Criteria Agreement. 35/ Thus, each transmission operator participant in the RMS will also execute a separate contract with the WSCC -- the RMS Agreement 36/ -- under which the transmission operator agrees to comply with the requirements of the Reliability Criteria Agreement (including with respect to its controlled generation), and to incorporate provisions in contracts with generators requiring the generators to comply with the Reliability Criteria Agreement. 37/
The Generator Agreement is an agreement between each participating transmission operator and a generator, which is executed pursuant to the
35/ Because the Phase I reliability criteria are applicable only to transmission operators and generators, the related agreements are similarly limited to these two types of entities. In the future, as additional reliability criteria are added to the RMS, the program may be extended to cover all users of a transmission system. The actual contractual mechanism to be employed under such circumstances is uncertain at this time, but it could include appropriate amendments to a transmission operator’s open access transmission tariff. See Reliability Criteria Agreement, Annex A, Art. V.
36/ There will be two basic types of such agreements -- contracts with FERC-jurisdictional entities and contracts with non-FERC-jurisdictional entities. Contracts with non-FERC-jurisdictional entities will be based on the model contract with FERC-jurisdictional entities, with necessary modifications to the provisions regarding filings with the FERC.
37/ Participating transmission operators located outside of the United States would be bound in the same manner as US entities -- by contract with the WSCC. They would be responsible for any regulatory filings or contracts in their jurisdictions that may be necessary to fulfill their contractual obligation vis-à-vis the WSCC.
transmission operator's commitment to the WSCC in the RMS Agreement:
(1) except where precluded by law, to require in any new interconnection agreement that the generator comply with the RMS through the Reliability Criteria
Agreement; and (2) with respect to existing interconnection agreements: (a) to make good faith efforts to amend the agreement to require compliance with the RMS, and
(b) to make unilateral filings of such amendments with the FERC 38/ if agreement to amend is not reached and such filings are permitted. 39/
It is important to understand what the contracts do not do. First, the RMS and the implementing contracts do not create a new standard of reliability.
Rather, the RMS is intended to monitor compliance with current standards and to provide additional incentives for compliance with such standards. Secondly, the contracts do not create any duties to, or rights in, third-parties. 40/ In this respect,
38/ At the FERC, a generator would have the right to oppose the amendment.
39/ See RMS Agreement, Appendix A & B (containing language for inclusion in new interconnection agreements and a model stand-alone generator agreement). As an example of how all of these contractual arrangements will fit together, assume a FERC-jurisdictional transmission operator that has agreed to be a participant in the RMS. The transmission operator will be a party to the Reliability Criteria Agreement (along with the WSCC and all other transmission operator participants). The WSCC and the transmission operator will execute a separate RMS Agreement under which the transmission operator agrees to comply with the reliability criteria and other requirements set out in the Reliability Criteria Agreement. Pursuant to the RMS Agreement, the transmission operator will: (1) require all newly interconnected generators to comply with the RMS program as set out in the Reliability Criteria Agreement; and (2) with respect to existing interconnected generators, (a) make good faith efforts to reach agreement on amendments to existing interconnection agreements to require compliance with the RMS program, and (b) make unilateral filings of such amendments with the FERC if agreement is not reached and such filings are permitted.
40/ Reliability Criteria Agreement, § 8; RMS Agreement, § 6.
the contracts are not intended to impose any liability on transmission operators or generators with respect to their customers (or the customers of others), although all are expected to benefit from the maintenance of the reliability of the Western Interconnection.
The RMS establishes a system of tiered sanctions for failure to comply with the reliability standards, depending on the severity and frequency of noncompliance. The sanctions include: (1) monetary sanctions; (2) letters to a noncomplying entity's Chief Executive Officer ("CEO") informing the CEO of the noncompliance, with copies to NERC and the entity's WSCC representatives; and (3) similar letters to the noncomplying entity's Chairman of the Board and to state or provincial regulatory agencies with jurisdiction over the entity or, in the case of U.S. entities, if so requested to FERC and the DOE, by the agency; and (4) in the case of the Disturbance Control Standard, participants may be required to increase their reserves in a subsequent quarter. 41/ Any sanction, either monetary or a notification letter, becomes effective only upon a final determination of noncompliance. 42/ Accordingly, no letters are sent to third parties until after the appellate process is complete.
There are four levels of noncompliance: (1) Level 1 - minor or first time incidents of noncompliance; (2) Level 2 - significant or repeat incidents of
41/ Reliability Criteria Agreement, Annex A, Art. 2.
42/ Id. §§ 5.4.a & c; 6.5; 6.6; & 7.1.
noncompliance; (3) Level 3 - persistent or major incidents of noncompliance; and (4) Level 4 - persistent or flagrant incidents of noncompliance. 43/ Notification letters to noncomplying entities are the specified sanction for the first Level 1 incidents of noncompliance. The specified sanction for the second Level 1 or for the first Level 2 instance of noncompliance is a notification letter to the noncomplying entity and, if requested, to regulatory agencies. Monetary sanctions, in addition to notification letters, are specified for all subsequent Level 1 or Level 2 instances of noncompliance and for all Level 3 or Level 4 instances of noncompliance. 44/ In the case of the Disturbance Control Standard ("DCS"), instead of monetary sanctions there is a requirement to maintain increased reserves for a period after the noncompliance. This requirement is an already existing NERC requirement for control areas that have been unable to fully comply with the DCS in any quarter. 45/ It was adopted in lieu of monetary penalties in order to avoid having a double sanction applicable to control areas or reserve sharing groups.
43/ The specific type of sanction to be imposed for a given instance of noncompliance is set forth in Annex A, Article II of the Reliability Criteria Agreement. The specific noncompliance levels for each criterion are included in Annex A, Article III and IV of the Reliability Criteria Agreement.
44/ A schedule setting forth the designated amount of monetary sanctions is set forth in Annex A, Article II of the Reliability Criteria Agreement.
45/ The sanction for DCS noncompliance is described in detail in the NERC Performance Standard Training Document under item 4.3 – Contingency Reserve Adjustment Factor. The Contingency Reserve Adjustment Factor results in an increase in the control area's or reserve sharing group's Operating Reserve requirement. The increased Operating Reserve becomes effective starting at the beginning of the first month after a final determination of noncompliance and remains in effect for three months. Operating Reserve requirements become increasingly higher for consecutive quarters in which the DCS criterion is not met.
Funds collected by the WSCC through monetary sanctions will be applied directly against the WSCC's costs of administering the RMS. Any remaining costs of the RMS will be recovered through WSCC membership dues. If the funds collected through the monetary sanctions exceed the costs of administering the RMS, such excess amounts will be rebated to participating WSCC members in order to offset their costs of compliance with the RMS. 46/
The RMS excuses noncompliance with the reliability criteria under narrowly-defined circumstances. Specifically, noncompliance is excused, and thus no sanctions will be applied, if the noncompliance stems from: (1) a participant's compliance with or action under any applicable law or regulation or other legal obligation related thereto, or any curtailment, order, regulation or restriction imposed by a governmental authority; 47/ (2) a participant's compliance with any instruction, directive, order or suggested action by the WSCC Security Coordinator for the WSCC sub-region within which the participant operates; 48/ (3) any action taken or not taken by a participant which, in its reasonable judgment, subject to
The Operating Reserve requirement returns to normal at the end of the three-month period in which the DCS sanction is applied provided that full DCS compliance has been achieved during this period.
46/ Reliability Criteria Agreement § 7.2.
47/ Id. Annex A, Art. VI, § B.1.
48/ Id. Annex A, Art. VI, § B.2.
certain specified conditions, was necessary to protect the operation, performance, integrity, reliability or stability of its computer system, electric system, or any interconnected electric system; 49/ or (4) during the duration of any Extraordinary Contingency. 50/
In order to monitor compliance with the reliability standards, the RMS provides for data collection and reporting requirements. Each participant must regularly submit to the WSCC Staff certain specified information related to its compliance with the criteria. 51/ If a participant fails to supply such data within
49/ Id. Annex A, Art. VI, § B.3. Such action or inaction is not excused if the need for the action or inaction was due to the participant's noncompliance with any WSCC reliability standard or if the participant could have avoided the need for such action or inaction through reasonable efforts taken in a timely manner. Id.
50/ Id. Annex A, Art. VI, § B.4.c. Extraordinary Contingency is defined as
any act of God, actions by a non-affiliated third party, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, earthquake, explosion, accident to or breakage, failure or malfunction of machinery or equipment, or any other cause beyond the Participant's reasonable control; provided that prudent industry standards (e.g., maintenance, design, operation) have been employed; and provided further that no act or cause shall be considered an Extraordinary Contingency if such act or cause results in any contingency contemplated in any WSCC Reliability Standard . . .
Id.
51/ Id. § 5.2.a. The specific data that must be submitted is set forth in the Reliability Criteria Agreement, Annex A, Art. III & IV.
a designated period of time, the WSCC Staff will send a letter to the company's CEO notifying the CEO of such failure, with copies to NERC, and, if applicable, the company's WSCC representatives. Upon the participant's second or subsequent failure to submit data during a rolling six-month period, the WSCC Staff will send additional copies of the notification letter to the company's Chairman of the Board, with copies to state or provincial regulatory agencies with jurisdiction over the company and, in the case of U.S. entities, the FERC, and the DOE. 52/
The RMS also provides for a detailed compliance review and appeals process. The compliance-related data submitted by a participant will initially be reviewed by the WSCC Staff. If the Staff determines that the participant may not have complied with the applicable criteria, the participant will be given an opportunity to provide additional data to demonstrate its compliance or excusable noncompliance. 53/
If the WSCC Staff determines that a participant has failed to comply with any of the applicable criteria, it will notify the participant, setting out the details of such noncompliance and indicating the applicable sanctions. 54/ The WSCC Staff's initial determination becomes final, triggering the application of
52/ Id. § 5.2.a.
53/ Id. § 5.2.b.
54/ Id. § 5.3.
appropriate sanctions, unless the affected participant requests that the determination be reviewed by the RCC. 55/
In the case of an RCC review, the RCC must perform an independent evaluation of the matter, either sustaining the WSCC Staff's initial determination or substituting its own judgment regarding the alleged noncompliance. 56/ The RCC's determination becomes final, triggering appropriate sanctions, unless either the WSCC or the disputing participant requests a review of the determination through arbitration or, under certain circumstances, through a direct referral to the FERC or the appropriate court. 57/
The arbitration is to be conducted by a single, independent, arbitrator, 58/ based on the previously assembled data. 59/ In any arbitration, either the WSCC or the disputing participant may raise any issue regarding the sanction determination, including the factual basis for the sanction or whether
55/ Id. § 5.4.a.
56/ Id. § 5.4.b.
57/ Id. §§ 5.4.c & 6.1. Direct referral to the FERC/court may be either by mutual agreement of the parties or where arbitration is prohibited by law. Id. § 6.1.
58/ Id. § 6.3.a.
59/ Id. § 6.3.b. The WSCC and the disputing participant must be afforded a reasonable opportunity to rebut any such existing evidence. Id.
the applicable RMS procedures were properly followed. 60/ They may not, however, question the validity of the underlying reliability criteria. 61/
The costs of arbitration (not including attorney and expert witness fees which shall be borne by the respective parties) are borne by the losing party unless the parties agree otherwise or the arbitrator adopts neither party's position, in which case cost allocation will be determined by the arbitrator. 62/ The arbitrator's decision is final and binding on the parties, except if such decision is appealed to the FERC or the appropriate court. 63/
Either the WSCC or the disputing participant may apply to the FERC to hear an appeal of the arbitrator's decision. 64/ The FERC's decision resolving or rejecting the appeal constitutes a final determination of the dispute. The appeal related costs are borne by the party that incurred them. 65/ If the disputing participant is not subject to the FERC's jurisdiction, or if the FERC declines to
60/ Id. § 6.3(c).
61/ Id. Challenges to the criteria may be made by complaint to the FERC or through the WSCC procedure for establishing or modifying criteria.
62/ Id. § 6.5.
63/ Id.
64/ Id. § 6.6. Any initiation of a FERC appeal by the WSCC must be authorized by the WSCC Board of Trustees. Id.
65/ Id.
assert jurisdiction over the dispute, either the WSCC or the disputing party may appeal the arbitrator's decision to the appropriate court. 66/
Except for a few, narrowly-delineated, circumstances, the compliance-related data supplied to the WSCC may not be disclosed to third parties. Specifically, the WSCC Staff: (1) must treat as confidential all information submitted to it by an RMS participant pursuant to the Reliability Criteria Agreement; (2) must not, without the participant's prior written consent, disclose to any third party such confidential information; 67/ and (3) must make good faith efforts to protect each participant's confidential information from inadvertent disclosure. 68/ Similar requirements apply to all RCC members, 69/ arbitrators reviewing an RCC determination; 70/ and the Board of Trustees of the WSCC. 71/
66/ Id. § 6.7. Any initiation of a court appeal by the WSCC must be authorized by the WSCC Board of Trustees. Id.
67/ Information that is published or is publicly available (so long as the publication or public availability is not the result of action or inaction by the WSCC Staff or the breach of any confidentiality obligation) is not deemed confidential. Id. § 5.2.d(ii).
68/ Id. § 5.2.d(i).
69/ No member of the RCC may participate in a review of the WSCC Staff's initial determination unless he/she agrees in writing to be bound by the confidentiality obligations applicable to the WSCC Staff, or the affected participant consents to the RCC member's participation in the review. Id. §§ 5.1.b(iv); 5.2.d(i).
70/ Id. 6.3(a).
The WSCC Staff may disclose to any requesting governmental or regulatory authority having jurisdiction over a participant the following information (in either aggregate form or in a form that specifically identifies the participant): (1) whether the participant has been finally determined, in accordance with the RMS procedures, to have failed to comply with any of the applicable criteria during the time period to which the request relates; (2) if the participant has been finally determined to have failed to comply, which of the applicable criteria were not complied with as well as the number of occurrences and the applicable level of noncompliance; and (3) the type of sanction and the amount of any monetary sanction(s) assessed and the amounts paid or remaining unpaid. The WSCC Staff must give the affected participant notice of any such disclosure. 72/
Second, the WSCC Staff may disclose any confidential data if so requested or required, by subpoena, oral deposition, interrogatory, request for production of documents, administrative order, or other legal or regulatory process. Under such circumstances, the WSCC Staff must immediately notify the affected party in writing to enable that party to challenge the disclosure or to seek
71/ Either the WSCC Staff or the RCC may provide specified information regarding a participant's noncompliance to the WSCC Board of Trustees. Id. § 5.2.d(ii).
72/ Id. § 5.2.d(ii).
a protective order. The WSCC Staff must cooperate with the participant's efforts to so limit or avoid disclosure of the confidential information. 73/
Third, the WSCC Staff may disclose confidential data in the case of an appeal to the FERC or to a court. As before, the Staff must provide advance notice to any affected party to allow such party to seek an appropriate protective order. 74/
Fourth, the WSCC Staff or the RCC may make publicly available aggregate statistics or information on an unidentified basis concerning implementation of, and compliance with, the RMS. 75/
The RMS is an example of procompetitive, efficient cooperation among industry members -- including among competitors or potential competitors -- that the Sherman Act was not meant to prohibit. At its core, the RMS will serve as a mechanism to enhance the prospects for competition in electric markets by maintaining the reliability of the present transmission network as the number and variety of commercial transactions over the network dramatically increase. Without the RMS, reliability concerns might otherwise require the imposition of constraints that would inhibit the development of the competitive power market. The RMS therefore will enable competition in the restructured electric markets and,
73/ Id. § 5.2.d(iii).
74/ Id. § 5.2.d(iv).
75/ Id. § 5.2.d(v).
as such, is procompetitive. In this regard, it is well recognized that there are industry circumstances in which “cooperation among competitors [such as the RMS participants], is a commercial necessity.” 76/ It is also beyond dispute that private standard-setting organizations, such as the WSCC, and “private standards [such as the proposed RMS criteria] can have significant procompetitive advantages.” 77/
A. The RMS, Including Sanctions, Is Needed to Maintain the Continued Reliability of the Western Interconnection as the Electric Power Industry Moves from One of Vertically Integrated Monopolies to Competition Among Numerous Industry Participants.
The reliable operation of the Western Interconnection as a large integrated transmission system linking loads and generation throughout the area is critical to the efficient operation of electric power markets in the Western United States and to the well-being of electric power users throughout the area. Maintaining the electric network in a stable and reliable operating state requires the cooperation of all entities that are part of the interconnected system. Historically, this cooperation was achieved principally by the coordinated efforts of vertically integrated transmission operators, but this is no longer possible as the industry moves towards the development of competitive wholesale power markets.
76/ Association of Independent Television Stations, Inc. v. College Football Assoc., 637 F. Supp. 1289, 1297 (W.D. Okla. 1986).
77/ Allied Tube & Conduit Corp. v. Indian Head, Inc., 486 U.S. 492, 501 (1988) (footnote omitted). See also Harry S. Gerla, Federal Antitrust Law and Trade and Professional Association Standards and Certification, 19 Dayton L. Rev. 471, 503 (1994) (“Antitrust courts generally have been favorably disposed toward trade and professional association standards.”).
If competitive power markets are to be maintained (and legislation is not adopted), new measures, such as the RMS, are needed to promote compliance with those reliability standards that are necessary for the grid, and hence wholesale markets, to operate.
Since its inception, the WSCC has sought to promote reliability of the Western Interconnection through a system of peer-reviewed standards. 78/ Implementation was achieved through voluntary compliance and adherence to reliability standards and procedures. No formal or informal sanctions were imposed for failure to satisfy the voluntary standards and procedures. 79/ Thus, reliable electric service depended on the cooperative efforts of those facility owners and operators who did adhere to the agreed standards and procedures.
The efficacy of these traditional cooperative efforts to maintain reliability is jeopardized by commercial restructuring of the electric industry. Restructuring entails a variety of elements including:
1. new competitive pressures brought about through FERC open access transmission tariff requirements;
78/ No agency of the federal or state governments is invested with direct jurisdiction to regulate the technical requirements associated with electric reliability management or to establish and enforce standards designed to maintain reliability of the electric power system.
79/ The WSCC currently lacks an enforcement mechanism for noncompliance with its reliability criteria. Article VI, § 1 of the WSCC Agreement and Bylaws specifies that "[t]he members shall be responsible for meeting the established criteria, policies and procedures" established by the Council. However, there are no associated sanctions for noncompliance, short of the WSCC trying to enforce compliance through a court order.
2. state and federal regulatory incentives and mandates for the separation (often by divestiture) of generating assets from transmission assets;
3. the emergence of public and private support for transfer of control over operating facilities to independent system operators (such as in California);
4. reconfiguration of traditional vertically-owned and operated utilities into regulated business functions (transmission and distribution) and unregulated business functions (e.g., power generation, and energy management services);
5. competition in the supply of electric services to end-use customers in some states; and
6. technological advances and regulatory changes facilitating entry into certain industry segments such as power generating, marketing, and power trading.
The effect of these changes is to vastly enlarge the number of entities that use electric transmission grids, to expand the number and variety of commercial transactions that can be undertaken, and increase competitive pressure to reduce costs. At the same time, restructuring is prompting the disaggregation of many of the traditional entities that have been responsible for voluntary “command and control” of the electric transmission system.
Restructured and competitive power markets may offer consumers enormous benefits, but in this new environment, a prevalent, and difficult, issue is the continued ability of the Western Interconnection to maintain its historical system reliability on a voluntary basis. Two aspects of deregulation are most relevant here. First, under the traditional model, vertically integrated control area utilities would generate, transmit, and distribute electric energy, and voluntarily cooperate to maintain system balance and stability using primarily their own assets. Under the restructured model, in which electric generation, transmission, \DC - 6379646 - 6789020.14 and distribution are now frequently owned and/or operated by separate (and potentially competitive) entities, the same level of voluntary cooperation will be much more difficult to maintain, and concentrated control of generation and transmission will be much less common.
For example, the traditional model facilitated a utility's recovery of its justifiable costs, including costs incurred to maintain system reliability, through its bundled rates. This will no longer hold true as more and more utility services are priced competitively. Indeed, price competition could create incentives for some system operators and market participants to disregard reliability criterion if they believe they can avoid negative consequences, whether economic, political, legal, regulatory, or operational. If there are insufficient mechanisms to discourage leaning on other participants to manage reliability, some participants may be tempted to "free-ride," with the expectation that near-term system outages will not occur because of other participants' obligations or incentives to keep the system stable, even to their own economic or operational detriment.
Similarly, generators in competitive markets have strong incentives to reduce costs and maintain revenues. If a particular generator assumes that it will not suffer adverse effects from refusing to participate in reliability management, it may be tempted to make operational decisions that compromise system reliability for others. Operating AVR and PSS equipment imposes costs of operation and maintenance. The competitive pressure on generators to avoid such costs, if they can do so without serious legal, economic, or operational repercussions, is clear.
Further, when providing transmission service, certain ancillary services are necessary to maintain stability of the grid and to prevent cascading
\DC-63796/46-6789029.14 outages. 80/ Historically, ancillary services were provided by vertically integrated transmission utilities as an undivided part of the transmission service or the bundled supply of electric power and energy. In Order No. 888, the FERC ordered that transmission providers give customers the option to purchase four of these necessary services separately from other suppliers. Thus, more entities are now involved in providing necessary services to maintain a control area's reliability. At a minimum, this shift means that the incentives have been changed among the providers of ancillary services and that cooperation is now required among many more players than in the past. This leads to increased complexity in coordination as well as reliance on a greater number of market participants to maintain reliability.
The consequences of a breakdown in cooperative reliability measures are particularly serious for an interconnected, synchronous system such as the Western Interconnection. When incidents of noncompliance occur, additional burdens are placed on other system operators that must make up, if they can, for any deficiencies resulting from the noncompliance. To the extent other systems cannot make up the deficiency, all are placed at risk as the margins of safety are eroded upon which reliability of the system depends.
80/ In Order No. 888, the FERC concluded that a transmission provider must offer the following six ancillary services under its open access transmission tariff: (1) Scheduling, System Control and Dispatch Service; (2) Reactive Supply and Voltage Control from Generation Sources Service; (3) Regulation and Frequency Response Service; (4) Energy Imbalance Service; (5) Operating Reserve - Spinning Reserve Service; and (6) Operating Reserve Supplemental Reserve Service. Order No. 888 at 31,703.
The Western Interconnection is intentionally designed to cope with randomly occurring contingencies, under the assumption that participants are playing complementary supporting roles. When some participants do not comply with reliability standards, however, the system's ability to respond to contingencies is reduced and the probability of failure increases. The societal costs of major system failures can be immense. For example, the costs of the two system outages that occurred on July 2, 1996, and August 10, 1996, have been estimated at $735,000,000.
The network nature of the grid, the introduction of competition among suppliers, and the lack of the guaranteed recovery of costs create incentives to "free-ride" if possible. 81/ When individual participants fail to fully meet their reliability obligations, they unfairly burden other participants or jeopardize the stability of the grid, or both. Complying with reliability criteria has costs. To the extent an entity elects not to comply with reliability criteria to avoid these costs, it gains an unfair economic advantage over similarly situated participants that adhere to the criteria. This inequity is compounded if complying participants are forced to compensate operationally for the impact of others' noncompliance. If compliant participants
81/ See Continental T.V., Inc. v. GTE Sylvania Inc., 433 U.S. 36 (1977) (location restrictions can be reasonable where they serve to achieve efficiencies, including elimination of the "free-rider" effect); Rothery Storage & Van Co. v. Atlas Van Lines, Inc. 792 F.2d 10 (D.C. Cir. 1986), cert. denied. 479 U.S. 1033 (1987) (van line's adoption of policy of terminating agents which did not transfer independent operations to separate and distinct companies in order to prevent agents from having a "free ride" on van lines' reputation and services found not to violate the antitrust laws).
cannot or do not offset operational effects of noncompliance, all participants suffer the increased risks created by reduced margins of reliability.
The proposed RMS, by establishing sanctions for noncompliance, is an effort to offset any potential incentives to unjustly shift compliance burdens onto other competitors. Sanctions encourage all participants to comply with appropriate reliability standards and discourage “free-riding.”
The extent of noncompliance in the Western Interconnection during the past year is illustrated by data collected during the RMS Phase I evaluation period. 82/ During the monitoring period, there were 575 incidents of noncompliance with respect to various Phase I criteria. These incidents are summarized in Table I below. A limited number of participants were responsible for most of these incidents. While many of the incidents were relatively minor, some were quite significant. For instance, there were forty-one incidents in which operators failed to comply with the Operating Transfer Capability standards, but these all occurred on only eight paths. The duration of the overloads ranged from twelve minutes to one instance of over nine hours. In one forty-four minute incident, flow exceeded the transfer capability limit by fifty-five percent.
Similarly, nine out of the thirty-one reporting control areas reported 272 incidents of noncompliance with the Operating Reserve Standard. Eighty-two of the incidents were Level 4 incidents in which reserves were below seventy
82/ See generally Reliability Management System, Analysis of Phase I Evaluation Period, February 1, 1998, through September 30, 1998 (“Evaluation Report”).
percent of those required. On seven occasions two control areas reported deficiencies at the same time. In the case of DCS, there were twenty-three incidents of noncompliance involving sixteen of the thirty-one control areas. Most of these instances occurred during the summer months when record hot weather created unprecedented demands on the system making the maintenance of reserves correspondingly more expensive but all the more important. The limited but significant non-compliance found during the evaluation period suggests the need for additional monitoring and incentives such as the RMS would provide in order to promote adherence to existing reliability standards.
TABLE I
NONCOMPLIANCE SUMMARY
| Criteria | Reporting Entities | Entities Reporting Noncompliance | Number of Incidents |
|---|---|---|---|
| Operating Reserve | 31 | 9 | 272 |
| Disturbance Control | 31 | 16 | 23 |
| Control Performance | 28 | 1 | 5 |
| Operating Transfer Capability | 31 | 5 | 41 |
| Power System Stabilizers | 44 entities for 595 units | 21 | 150 |
| Automatic Voltage Regulator | 64 entities for 1,536 units | 19 | 84 |
The WSCC attempted to create a standard selection process that was untainted from an antitrust perspective. 83/ The RMS was developed over a twenty month period by the WSCC Policy Group and three task forces dealing with standards, sanctions, and legal issues respectively. The standards task force began with a review of all existing WSCC reliability criteria and selected a subset of the most critical criteria for inclusion in the initial phase of the RMS. The contractual structure of the RMS and the sanctions were developed by the legal and sanctions task forces, again operating under the Policy Group.
The initial structure and standards to be used in Phase I were approved by the Board of Trustees and a vote of the membership in December 1997. 84/ Subsequently, the legal task force and the Policy Group conducted a series of meetings to monitor the results of the evaluation program and to review drafts of the contracts and the proposed filings to the FERC and the Department. These meetings and workshops were open to all interested parties, including state and provincial regulators. To facilitate participation by all members, especially
83/ See Allied Tube & Conduit Corp., 486 U.S. at 501 (private standards can have significant procompetitive advantages if they are based on the merits of objective expert judgments under procedures that eliminate competitive bias); American Soc'y of Mechanical Engineers, Inc. v. Hydrolevel Corp., 456 U.S. 556, 572 (1982) (ASME found liable because it had failed to employ "meaningful safeguards" in its evaluation process and had allowed a competitor to use "ASME's reputation to hinder Hydrolevel's competitive threat").
84/ One of the initially approved standards, tagging, was dropped from Phase I.
those which had not been active in the legal or other committees, the WSCC began in July 1998, to post successive drafts of the proposed contracts and filings on the WSCC website.85/ These drafts were then finalized through an iterative process based on the comments received in a series of industry-wide workshops and additional meetings of the Policy Group to which all WSCC members, representatives from the regulatory community, and individual non-WSCC market participants were invited. At the same time, certain further refinements were made in the criteria based upon the results of the evaluation program and additional work of the standards task force.
As indicated before, to measure the workability of the proposed RMS, the WSCC members also implemented an evaluation program (which is still ongoing) that called for participants voluntarily to report data needed to measure compliance with the proposed Phase I criteria. Each participant was given written notification of any instance of noncompliance, but participants were not subject to any sanctions. The Evaluation Report adopted by the Standards Development Task Force and presented to the annual meeting concluded that: (1) compliance with the RMS rules could be measured and monitored through the reporting requirements; (2) the Phase I criteria were suitable and effective in monitoring and promoting system reliability; (3) accountability through data reporting had been a reinforcement to members' efforts to operate the system in a reliable manner; and
85/ See Attachment F for a list of the meetings and workshops. Due to resource constraints and other reasons, some members became actively involved only in the later stages when drafts of the RMS documents became available for review.
(4) through improved awareness of established criteria, members could improve their overall compliance, reducing the potential for system disturbances and loss of customer load. 86/
In analyzing the RMS, the Department must consider any
anticompetitive effects that the program might have and weight those effects against the benefits. 87/ While standards can sometimes be used to adversely affect particular groups of competitors, such concerns do not apply in this case.
The standards have been developed based on objective technical standards and best professional judgments and were selected through an open process that involved the regulatory community and a full range of competitors.
86/ Evaluation Report at 2.
87/ United States v. Topco Assocs., Inc., 405 U.S. 596, 607 (1972) (an analysis of the reasonableness of a particular restraint, “includes consideration of the facts peculiar to the business in which the restraint is applied, the nature of the restraint and its effects, and the history of the restraint and the reason for its adoption”). See also Association of Independent Television Stations, 637 F. Supp. at 1297, 1300, n.11 (under the rule of reason, a court or a reviewing agency will assess the reasonableness of an arrangement as a whole, and weigh any potential anticompetitive effects against its procompetitive benefits); National Bancard Corp. v. Visa U.S.A., Inc., 596 F. Supp. 1231 (S.D. Fla. 1984), aff’d, 779 F.2d 592 (11th Cir. 1986), cert. denied, 479 U.S. 923 (1986) (credit card interchange fee by competing banks found to be lawful where it created efficiencies, such as increased use of credit cards); Association of Retail Travel Agents v. Air Transport Ass’n of Am., 623 F. Supp. 893, 897-98 (D. D.C. 1985) (relying in part on the DOJ’s statement that the “proposed rules should not be viewed in isolation, but rather as part of an overall joint venture that has a desirable goal [of] . . . contribut[ing] to . . . efficiency . . . by reducing transactions costs. . . .”).
The Phase I RMS standards are part of the WSCC's long-standing minimum operating reliability criteria, 88/ with which WSCC members have historically been expected to comply even when facilities required for secure and reliable operation have been delayed or forced out of service. These standards are thus already a subset of criteria that have been determined, through years of hands-on experience running the nation's power transmission grids, to be essential to reliable system operations. The technical analysis of the criteria in Section II.A. shows their importance in maintaining voltage and frequency performance, maintaining reliable power transfer levels, maintaining adequate generation availability, and the potential for serious noncompliance to increase the risk of major outages.
The criteria will apply to all RMS participants and are designed not to favor any industry segment. 89/ Also, should any RMS participant be unable to
88/ The expertise of NERC and its 10 regional reliability councils, including the WSCC, in establishing reliability criteria is well established. The FERC has on numerous occasions relied upon NERC and regional council criteria and standards to resolve issues of reliability. See, e.g., North American Electric Reliability Council, 85 FERC ¶ 61,353 (1998) (approving NERC's transmission loading relief procedures); American Municipal Power-Ohio v. Ohio Edison Co., 76 FERC ¶ 61,265, at p. 62,351, n.7 (1996) (FERC "recogniz[ing] the general applicability of the reliability standards of NERC and the regional reliability councils"). See also, e.g., Florida Power & Light Co., 62 FERC ¶ 61,251 (1993); Florida Power & Light Co., 70 FERC ¶ 61,007 (1995) (in each case, the FERC applied NERC or regional reliability council guidelines to determine whether a proposed transmission service agreement was just and reasonable). Similarly, in establishing the open access transmission regime under FERC Order Nos. 888, 888-A, 888-B, and 888-C, the FERC repeatedly recognized the role of NERC and the regional reliability councils (such as the WSCC) in maintaining system reliability.
89/ For example, generators controlled by a participating transmission operator will be subject to the criteria in the same fashion as any independent generator.
comply with the criteria due to certain specified reasons, it is excused from such noncompliance and payment of the related sanctions. 90/ Further, the evaluation program indicates that the criteria can be monitored in a straightforward manner, and are measurable and quantifiable. 91/ These features make it relatively easy for the WSCC to monitor such compliance. 92/
Furthermore, compliance costs should not impose undue burdens on any of the participating entities. Participants already are supposed to be complying with the standards. The incremental costs of reporting and monitoring are estimated to range from $6,000 to $24,000 per year for each control area and from $750 to $6,000 for generators. These costs are negligible whether compared to the value of transmission services or the costs of system disturbances.
Further, independent generators (as opposed to transmission operator-owned generators) will not be competitively harmed by complying with standards that are equally applicable. As a practical matter, transmission operators have always required that an interconnecting generator comply with certain specified criteria in order to maintain the reliability of the interconnected electric system. For expressly that reason, the Reliability Criteria Agreement permits a transmission operator to require an interconnecting generator to comply with reliability criteria that are more stringent than those included in the RMS. See RMS Agreement, Appendix A, § 2.7; Appendix B § 5.3.
90/ Reliability Criteria Agreement, Annex A, IV.
91/ Evaluation Report at 2.
92/ Id. at 3.
A potential concern regarding the imposition of sanctions by a private association, such as the WSCC, is that a sanction may be applied not because it is justified but because it will disadvantage a competitor. As before, this concern is not material in this case -- the primary, procompetitive function of the proposed RMS sanctions is deterrence of behavior that increases reliability risks; the sanctions are narrowly structured to fit this deterrent objective; and the noncompliance determination is subject to several layers of review by independent parties. 93/
The three types of sanctions -- notification letters, monetary sanctions, and the obligation to maintain increased reserves -- have been selected based on their suitability to deter noncompliance. The notification sanctions for noncompliance make such noncompliance visible to senior management on a timely basis and facilitate regulatory oversight of reliability performance. They are expected to have a significant deterrent effect. Even in the evaluation phase, notification of noncompliance has apparently served to improve subsequent compliance by some participants. Monetary sanctions have been set at a level
93/ See, e.g., Silver v. New York Stock Exch., 373 U.S. 341, 361-363 (1963) (enforcement of sanctions may be appropriate when there are procedural protections such as notice of the grounds for discipline, and a hearing or an opportunity for the member disciplined to respond to and confront its accusers); Cooney v. American Horse Ass'n, Inc., 495 F. Supp. 424 (S.D.N.Y. 1980) (association's drug rule, which required removal from competition of racers with a drug-induced competitive edge, was designed to improve and foster fair competition in racing, a procompetitive purpose).
intended to encourage compliance but without creating an undue financial burden on participants. 94/
The sanctions are structured to effectively serve the deterrence objective. The sanctions are based on the frequency and level of noncompliance and the criterion involved -- the more severe or the more frequent the noncompliance, and thus the greater impact on reliability, the more serious the sanction. Relatedly, because of the gradation of the sanctions, a noncomplying entity is given an opportunity to correct its future behavior, before a more serious sanction is triggered. 95/
Importantly, no sanction will be applied until a participant has been determined, pursuant to carefully delineated procedures, to have failed to comply with the criteria. RMS participants will have at least four layers of protection so that any determination of noncompliance, and the related imposition of sanctions, is the result of a fair and unbiased review process. The WSCC itself is composed of members from all industry segments. The RCC will be composed such that no industry segment will be able to control its decisions on sanctions. The specified
94/ There is, of course, no experience to date with monetary sanctions, and there were different judgments among WSCC members and the regulatory community about the appropriate dollar size of the sanctions. Some entities argued that significantly higher sanctions were required to deter noncompliance. Once sanctions are in place, the WSCC can better judge whether the size of the monetary sanctions is sufficient to achieve the desired deterrent effect.
95/ As indicated, also subservient to the reliability objective of the RMS, the moneys collected through the imposition of sanctions will be used to offset the cost of the RMS program to both the WSCC and the participating WSCC members.
alternative dispute resolution process provides for the use of neutral and unaffiliated arbitrators. Finally, should an RMS participant wish to do so, it may appeal an arbitrator's decision to either the FERC or a court. These procedural protections should prevent any misuse of the RMS to disadvantage a competitor.
Moreover, it is important to note that although the willingness of any one transmission operator to make itself subject to sanctions may be influenced by the willingness of others to do so, no transmission operator is required to participate and subject itself to sanctions. As members of the WSCC, non-participating control areas would continue to be subject to the WSCC's generally applicable standards, procedures, policies, and criteria, but they would not be subject to sanctions either by the WSCC or other transmission operators.
A participating transmission operator does agree: (1) to amend, where it can do so, existing interconnection agreements with generators to require compliance with the RMS, and (2) to make compliance a condition of entering into any new interconnection agreements. 96/ Similarly, the transmission operator agrees to require generation on its system that it controls to comply with the RMS. In this one instance, third-parties may be required by participants in the RMS to comply with the RMS requirements subject to sanctions. This requirement, however, is imposed equitably. All generators connected to a participating
96/ Although the RMS prescribes that one minimum condition be included in interconnection agreements, the RMS does not affect the power of a transmission operator to impose other and more stringent requirements as deemed necessary by the operator in order to maintain the reliability of that portion of the grid under its control. See footnote 88 supra.
transmission operator (except third-party generators having interconnection agreements not subject to amendment) are subject to the same condition. The potential burden on generators relative to plant costs is limited. On the other hand, proper operation of AVR and PSS is important both to maintain reliability in normal system operation and to recover promptly from a disturbance. One of several factors in the August 10, 1996 outage was the failure to have AVR equipment in operational mode. 97/
As set out in Section II.G., the RMS contains multi-layered confidentiality provisions to limit disclosure regarding noncompliance and potential noncompliance. Strong confidentiality provisions were deemed appropriate to avoid premature disclosure of information which could adversely affect participants and to minimize the risk of potential misuse of information by competitors. 98/
97/ A number of factors were involved in the July and August disturbances including inadequate contingency planning, lack of operating studies, and inadequate right of way maintenance. See, e.g., August 1996 Disturbance Report at 6. These problems have been addressed by other actions of the WSCC and the parties involved.
98/ Commercial disparagement of a competitor by reference to the competitor's violation of an industry standard was held to violate the antitrust laws when defendant's agent used standards setting group to fraudulently find noncompliance. See American Soc. of Mechanical Engineers, Inc. v. Hydrolevel Corp., 456 U.S. 556 (1982). The case has no applicability to the RMS because of the well-established basis for the RMS criteria themselves and the elaborate procedural protections for determining noncompliance.
As indicated, while the WSCC itself is subject to strict confidentiality rules, regulators with jurisdiction will have authority to obtain information about the reliability performance of those entities subject to their regulation, and the DOE and the FERC will have the ability to receive such information about all United States participants. Regulators can determine whether to make such information public based upon their own guiding statutes and policies. Information regarding noncompliance may thus become public, but only because public authorities have deemed it appropriate and only after a final determination of noncompliance has been made. The WSCC itself will not be making the decision whether or not to make confidential information available to the public.
Timely implementation of the RMS is an important cautionary and prudent step in maintaining reliable service to the over sixty-five million customers in the service territories of WSCC members. Commercial restructuring of the industry is proceeding apace. As indicated, changes in the commercial environment place ever-increasing pressure on existing reliability management tools. As the DOE Advisory Report concluded:
Transmission-grid reliability and an open, competitive market can be compatible . . . provided appropriate steps are ... taken soon. . . . [T]he primary challenges to bulk-power system reliability are presented by the transition itself, rather than by the end state of competition. Failure to act will leave substantial parts of North America at unacceptable risk.
Id. at x (emphasis in original). The WSCC's timetable therefore is intended to implement the RMS at the earliest practicable time.
Receipt of a Business Review Letter in response to this Request is a critical path item in the implementation plan for the RMS. The WSCC and its members have recognized from the outset that any industry standards setting effort may raise issues of potential concern under the antitrust laws. Accordingly, even if the FERC issues the requested declaratory order, the members are not prepared to execute the contracts necessary to put the RMS structure in place unless and until a favorable Business Review Letter has been issued. Although it has no assurances, the WSCC is hopeful that the FERC will act on its Request for a Declaratory Order on or before March 31, 1999. Such action, absent the need for a Business Review Letter, would permit the implementation of the RMS by July 1, 1999. 99/. Given the limited time between now and March 31, 1999, the WSCC realizes that the Department may be unable to act on this Request by that date, but the WSCC hopes that the Department will act as soon thereafter as is reasonably practicable to avoid undue delay in the implementation of the RMS.
99/ Only after receipt of the Business Review Letter and a FERC declaratory order can the Board of Trustees and the members determine whether to execute the contracts and to implement the RMS. Once that determination is made, FERC jurisdictional entities will have to file the contracts with the FERC. The contracts will not become effective until the FERC acts on this second set of submissions, which action may occur 30 to 60 days after filing.
Because the procompetitive purpose of the proposed RMS and the expected reliability benefit outweigh any slight potential for anticompetitive effects, the WSCC respectfully requests that: (1) the Department issue a Business Review Letter stating that it has no present intention to bring an enforcement action against the WSCC or its members joining in this Request if they implement the RMS; and (2) the Department act on this Request as soon as practicable, in order to permit the WSCC and RMS participants to timely implement the program.
Respectfully Submitted,
Mary Anne Mason
Joseph C. Bell
Jolanta Sterbenz
Hogan & Hartson L.L.P.
555 Thirteenth Street, N.W.
Washington, D.C. 20004
(202) 637-5600
Counsel for Western Systems
Coordinating Council