Options for

Maintaining and Enhancing Electric System Reliability

Western Governors' Association's

Task Force on Electric Industry Restructuring: Competition and Reliability

and

The Reliability Work Group of the

Committee on Regional Electric Power Cooperation

by the

Western Interstate Energy Board

Contact: Doug Larson 303/573-8910 dlarson@westgov.org

Brad Wetstone 303/573-8910 bwetstone@westgov.org

Page

I. INTRODUCTION                                                                                            5

II. BACKGROUND                                                                                             6

A. Existing System for Maintaining Reliability                                                6

B. Shortcomings in Existing System                                                              7

C. Changes Occurring in the Western Interconnection                                 11

A. Adequacy of Criteria:                                                                             13

B. Compliance with Criteria:                                                                       17

Glossary of Terms

Cascading

The uncontrolled successive loss of system elements in which the loss of each successive element is contingent upon prior losses of elements.

Single Contingency - The loss of a single system element under any operating condition or anticipated mode of operation.

Most Severe Single Contingency - That single contingency which results in the most adverse system performance under any operating condition or anticipated mode of operation.

Control Area

A system which regulates its generation in order to maintain its interchange schedule with other control areas and contributes its frequency bias obligation to the interconnection.

The controlled tripping of transmission system elements in response to system disturbance conditions to form electrically isolated islands which are relatively balanced in their composition of load and generation. This controlled action is taken to prevent cascading, minimize loss of load, and enable timely restoration.

A portion of the interconnected system which has become isolated due to the tripping of transmission system elements.

Independent System Operator.

The controlled interruption of service to a predetermined number of customers in order to minimize loss of generation, stabilize the system, and enable rapid service restoration to all customers.

The difference between the scheduled and actual power flow, assuming zero inadvertent interchange, on an interconnection between control areas. Also called unscheduled flow.

Minimum Operating Reliability Criteria

North American Electric Reliability Council

Open access same time information system

PUC

State Public Utility Commission

Special preplanned corrective measures which are initiated following a disturbance to provide for acceptable system performance. Typical automatic remedial actions include generator tripping or equivalent reduction of energy input to the system, controlled tripping of interruptible load, DC line ramping, insertion of braking resistors, insertion of series capacitors and controlled opening of interconnections and/or other lines including system islanding. Typical manual remedial actions include manual tripping of load, tripping of generation, etc.

A protection system which automatically initiates one or more remedial actions. Also called Special Protection System.

Operating Reserve - That reserve above firm system load capable of providing for regulation within the hour to cover load variations and power supply reductions. It consists of spinning reserve and nonspinning reserve.

Nonspinning Reserve - That portion of the operating reserve capable of being connected to the bus and loaded within ten minutes. Also included is any load which is designated for use as reserve and can be reduced by dispatcher action within ten minutes.

Simultaneous Outage

Multiple outages are considered to be simultaneous if the outages subsequent to the first event occur before manual system adjustment can be made. For simulation purposes, it may be assumed that the outages occur at the same instant, or the outages may be staggered if the time sequence is known.

WSCC

Western Systems Coordinating Council

I. INTRODUCTION

While 99 percent of power outages are due to failures in the distribution system, such as an auto accident knocking down a power pole, the focus of this paper is on reliability problems which damage the integrity of the western bulk power transmission grid. Some events that may affect the reliability of the bulk power transmission system are instantaneous phenomena, such as the failure of a relay leading to an outage. Other reliability problems unfold over a longer period of time as was the case in the August 10 outage where an extended period of system instability preceded the outage. Still other sources of reliability problems involve long-term problems, such as not providing sufficient generating capacity to meet peak load.

The purpose of this white paper is to identify and discuss options for maintaining and enhancing reliability of the bulk power transmission system in an increasingly competitive electric power industry. Two questions for western states and provinces are whether the current regional reliability criteria used by industry are adequate and whether compliance with these criteria should be mandatory.

For example, what methods are available to determine if the West has achieved an optimal level of reliability; that is where the marginal cost of expenditures on reliability equals the marginal benefits customers receive from such expenditures? If the current criteria are not adequate to provide the optimal level of system reliability, who should establish new criteria and what process should be used? Are the criteria specific and measurable?

If it is determined that compliance with regional reliability criteria should be made mandatory, what government action is required? Which level of government, states/provinces and/or federal governments, should act? What are the potential unintended consequences of establishing new criteria or new systems to enforce the criteria?

II. BACKGROUND

Institutional Structure: The North American Electric Reliability Council (NERC) and its regional councils are responsible for protecting the reliability of the interconnected transmission system in the United States, Canada, and northern Baja California. (See map.) NERC was formed in 1968, in the aftermath of the 1965 blackout in the East. While NERC and the regional reliability councils were initially comprised of transmission- owning and transmission-dependent utilities, their membership has recently broadened to include independent power producers, power marketers and brokers. The U.S. government has limited authority with respect to reliability. ⁽¹⁾ States have responsibilities associated with reliability which are typically executed by public utility commissions in defining the terms and conditions of service.

East Central Area Reliability Coordination Agreement Mid-Continent Area Power Pool

ERCOT NPCC

Electric Reliability Council of Texas Northeast Power Coordinating Council

FRCC SERC

Florida Reliability Coordinating Council Southeastern Electric Reliability Council

MAAC SPP

Mid-Atlantic Area Council Southwest Power Pool

MAIN WSCC

Mid-America Interconnected Network Western Systems Coordinating Council

Affiliate

ASCC-Alaska Systems Coordinating Council

Reliability Criteria: NERC and the regional reliability councils establish reliability criteria and guides for members which plan, operate and use the transmission system. ⁽³⁾ The criteria established by WSCC and NERC are based on engineering judgments concerning the desired level of reliability. ⁽⁴⁾ The level of transmission reliability reflected in the criteria is not based on probabilistic assessments of the risks of outages and the costs of such outages. ⁽⁵⁾ (See Appendix A for excerpts of the WSCC reliability criteria.)

Many reliability criteria are written as guidelines without measurable performance standards. For example, WSCC's Minimum Operating Reliability Criteria state that: "When it is agreed that a disturbance on specific facilities occurs more often than should be reasonably expected and results in an undue burden on other systems, the owners of the facilities should take measures to reduce the frequency of occurrence of the disturbance, and cooperate with other systems in taking measures to reduce the effects of such disturbance."

WSCC has an elaborate process for developing and changing regional reliability criteria. ⁽⁶⁾ This process does not require review of criteria by state/provincial or federal regulatory agencies or the public.

Potential shortcomings in the existing framework for protecting reliability fall into four categories:

(1) Is the approach to evaluating reliability sound?

(2) Have criteria been developed to deal with the factors that make the system unreliable?

(3) Are existing criteria adequately stringent, specific and measurable?

(4) Are parties accountable for compliance with reliability criteria? Are there incentives for compliance and penalties for non-compliance with reliability criteria?

Ideally, reliability criteria would be set at a level where over time the marginal cost of ensuring reliability (including hardware investments, operation and coordination costs) equals the marginal benefits from such expenditures. Improving system reliability through measures such as the construction of new transmission lines can be very expensive. Similarly, the cost of blackouts can be very expensive. ⁽⁷⁾ Therefore, there can be significant economic benefits from setting reliability criteria at a level where expenditures on reliability equal the benefits from the expenditures. To under invest in reliability can cause significant economic loss to the western economy. To goldplate the transmission system would also be wasteful.

There is presently no way to determine whether the existing reliability criteria are resulting in an under investment or a goldplating of the transmission system. NERC and WSCC use deterministic approaches for setting reliability criteria. For example, the WSCC Minimum Operating Reliability Criteria states: "The bulk power systems will be operated at all times so that general system instability, uncontrolled separation, cascading outages, or voltage collapse will not occur as a result of the most severe single contingency." There is no requirement to assess the probability of the most severe single contingency (or, even more importantly, the probability of multiple contingencies occurring simultaneously) or the cost associated with such events. ⁽⁸⁾

(2) Have criteria been developed to deal with the factors that make the system unreliable?

In determining whether the existing reliability criteria deal with all the important factors contributing to system unreliability, it is instructive to consider the events which contributed to the July 2-3 and August 10 outages in the West and then compare these events with current reliability standards.

(3) Are such criteria sufficiently encompassing and adequately stringent, specific and measurable?

Inadequate Contingency Studies: For example, studies simulating operating conditions were not sufficiently encompassing to include the events that led to both the July 2-3 and August 10 outages. According to the WSCC Minimum Operating Reliability Criteria (MORC), "systems or control areas will remain stable upon the loss of any one single element without cascading that could result in the successive loss of additional elements." The MORC also states that "multiple contingency outages of a credible nature will be examined, and the system will be operated to protect against general system instability, uncontrolled separation or cascading outages for these contingencies." Given the potential for the western economy to incur high costs resulting from outages, perhaps utilities and the reliability councils should broaden the scope of credible continency studies so as to include low probability, high-cost events. Alternatively, perhaps real-time modeling of system conditions need to be conducted. The July 2-3 and August 10 outages may have been avoided if the multiple contingencies that led to the outages had been evaluated and remedial actions designed. ⁽⁹⁾

Faulty Equipment: Faulty protective equipment and relays on high-voltage transmission lines exacerbated the effects of the events which led to the July 2 and 3 disturbances. ⁽¹⁰⁾ The WSCC Minimum Operating Reliability Criteria, calls for "periodic testing of protective relay systems." ⁽¹¹⁾ Additionally, the MORC explicitly acknowledges that reliability is ". . . dependent upon periodic inspection and adequate maintenance. . ." of system facilities. The WSCC reliability criteria do not provide further guidance regarding the frequency by which protective equipment should be inspected and tested. Apparently, individual utilities have discretion to establish and adhere to maintenance and inspection schedules of their own design.

Voltage Support: Inadequate voltage support played a critical role during the July 2-3 and August 10 outages. According to the WSCC MORC, "[t]he bulk power systems will be operated at all times so that general system instability, uncontrolled separation, cascading outages, or voltage collapse will not occur as a result of the most severe single contingency." The MORC also states that "[s]ystems and control areas shall ensure that reactive resources are adequate to maintain minimum voltage limits under facility outage conditions." ⁽¹²⁾ Clearly, the demand for reactive power on the transmission system exceeded the supply and this condition led to cascading outages.

Failure to Communicate with Other Utilities: Prior to the initiating event of the August 10 power outage, three of Bonneville Power Administration's (BPA) 500 kV lines in the Portland area were knocked out of service (two lines were lost due to interference from trees, the other line outage resulted from circuit breakers being out of service). The WSCC MORC states that "[m]embers shall by mutual agreement, provide essential and timely operational information regarding their system . . . to other members." WSCC's Procedure for Coordination of Scheduled Outages and Notification of Forced Outages further states: "[e]ach WSCC Member System which owns or operates a key generation or transmission element . . . which has been forced out of service is responsible for notifying the other WSCC members via the WSCC Communication System of the facility outage." Although Portland General Electric was aware of one of the line losses and Pacific Gas & Electric was aware of another, BPA did not widely provide notice of the loss of the three lines. Such notice might have helped mitigate the severity of the August 10 disturbance.

(4) Are parties accountable for compliance with reliability criteria? Are there incentives for compliance and penalties for non-compliance with reliability criteria? Obviously, compliance with reliability criteria has not been perfect. Some problems of non-compliance have been dealt with effectively through peer pressure, but quite a few have not. Some, such as the NERC Reliability Compliance Team, argue that "[r]eliability has been maintained only because there have been enough entities willing to do 'more than their share' to offset the negative influence of those not in compliance. Such willingness existed on the part of many because required investments were covered in a regulated environment, a situation that is doubtful for the future where functions are unbundled and vertically-integrated utilities may not exist." ⁽¹³⁾ It should be noted, however, that transmission has been, and will continue to be, a regulated function where the cost of reliability-related investments are traditionally recovered. Of course, all parties operating and using the grid must know their responsibilities, be able to carry their "share" of the burden of ensuring system reliability, and be accountable for their actions.

Puget's actions also highlighted the difference between compliance with regional reliability criteria and membership in a regional reliability council. Puget, which operates a load control center, maintained that even though it was withdrawing from WSCC it would continue to comply with WSCC standards.

The NERC Reliability Compliance Team report and the matter involving Puget Power raise pertinent questions about the future effectiveness of the current institutional framework ⁽¹⁵⁾ for ensuring reliability of electric power supplies. First, can the industry rely on a system based on volunteerism to achieve reliability? Second, can the industry safely rely on a party that elects not to join a reliability council as a member, despite assurances from that entity that it will comply with all applicable standards? Lastly, can financial costs beyond the realm of membership dues and studies (e.g., allocation of costs for implementing loop flow mitigation programs or penalties for failing to abide by reliability criteria) be recouped from members participating in a voluntary organization?

C. Changes Occurring in the Western Interconnection

The electric power industry is undergoing change which may mitigate or exacerbate the shortcomings in the existing system for protecting reliability. Five changes are underway in the West which may impact system reliability: (1) the Federal Energy Regulatory Commission (FERC) has mandated open transmission access (Order 888); (2) California has granted open access to retail customers beginning in 1998 (and on a limited experimental basis in Washington State and Idaho open access has been granted to Washington Water Power's large customers); (3) independent system operators (ISOs) are under development in California and seven northwestern states; (4) the WSCC is moving to create four security coordinators in the Western Interconnection and has proposed an "industry compact" that would include sanctions for non-compliance; and (5) the recent trend of squeezing more capacity out of existing transmission lines will likely continue.

Retail access will begin in California in 1998. Washington and Idaho have already authorized Washington Water Power to offer retail access on an experimental basis to its largest customers. As retail access expands, the number of parties consummating sales which require use of the transmission system will increase. Some argue that in a competitive retail access regime, reliability is likely to improve at the distribution level because market participants will have an increased financial incentive to maintain the system. However, at the bulk power supply level, reliability may degrade. ⁽¹⁶⁾ Others suggest that reliability may degrade at the transmission and distribution levels as revenues from the regulated transmission and distribution functions are used to cross subsidize unregulated activities within a company. ⁽¹⁷⁾ In either case, increasing attention must be paid to maintaining the reliability of the bulk power transmission system.

Have primary responsibility for ensuring short-term reliability of grid operations and complying with applicable standards set by NERC and regional reliability councils;

Have control over operation of the transmission system;

Identify transmission constraints and take operational actions to relieve those constraints; and

Develop mechanisms to coordinate with neighboring control areas.

FERC has given preliminary approval to an ISO in California; the Texas PUC has ordered the establishment of an ISO; and a proposed independent grid operator (IndeGO) is under development in seven northwest states. The establishment of two or three ISOs in the western grid could improve reliability by: (1) reducing the number of parties operating the system and thereby reducing communication problems during crises ⁽¹⁸⁾; (2) transferring transmission maintenance activities to a single-purpose, regulated monopoly, as an ISO would be, instead of keeping the maintenance function within companies that are competing for market share and seeking to minimize operating costs; and (3) "depoliticizing" operational decisions by eliminating the reluctance of system operators to take actions which benefit the entire grid.

In response to a NERC initiative, in November 1996, the WSCC appointed four of the West's utilities as security coordinators, with the authority to order remedial actions in emergencies. The Bonneville Power Administration would monitor the Northwest; the Western Area Power Administration would monitor the Rocky Mountain region; Arizona Public Service Company would monitor the Arizona-New Mexico region; and Pacific Gas & Electric would monitor California, southern Nevada and northern Mexico. Coordinators would have authority to direct operations immediately before, during and immediately after any problems or disturbances expected to have a regional impact. It would cost approximately $5 million to set up the coordination centers. The costs would be collected from membership fees. ⁽¹⁹⁾ A NERC report recommended that security coordinators be independent of market participants, which is the case in some reliability regions. ⁽²⁰⁾ The WSCC plan presumes the creation of a California ISO, a Northwest independent grid operator, and a new entity in the Wyoming/Colorado region. These bodies would assume the responsibilities of the security coordinators. However, even where ISOs execute reliability functions, there will continue to be a need for some overall organization that is independent from operations to coordinate reliability criteria, monitor compliance and issue sanctions, especially at the ISO boundaries.

Finally, in recent years many transmission-owning utilities in the West have been uprating the transfer capability of lines without constructing new lines. This trend will likely continue with (1) the introduction of new technologies ⁽²¹⁾, such as flexible AC transmission systems (FACTS), which will allow the transmission system to be operated closer to its thermal capacity (i.e., the point at which the sagging line provides inadequate clearance or the conductors melt) and (2) the long lead times necessary to permit and construct new transmission lines.

To maintain and enhance reliability, reliability criteria must be adequate and they must be followed.

A. Adequacy of Criteria: Options to improve the adequacy of reliability criteria fall into four categories:

(1) Using different methods to determine the level of reliability desired;

(2) Requiring the use of a public process in establishing reliability criteria;

(3) Expanding the number of factors which reliability criteria address;

(4) Ensuring that criteria are sufficiently encompassing, stringent, specific and measurable; and

(5) Changing the parties who oversee the development of reliability criteria.

1. Require the use of probabilistic evaluation in transmission planning and transmission system operation.

A competitive electric system provides a strong motivation to reevaluate the traditional deterministic method used in developing reliability limits for real-time operations, and consider adopting a risk-based reliability assessment approach, where risk is the product of the probability of an event times the consequences of the event. How the system is operated would depend on the level of risk and the economic benefits of operating the system at a specific level, and not simply be based on when the system performance first violates the Minimum Operating Reliability Criteria. ⁽²³⁾

Pros: While probabilistic techniques for setting reliability criteria have been available for years, there has been little incentive to use such techniques. The introduction of competitive users of the grid creates incentives for a multiplicity of players to take operating risks in order to maximize their profits. A risk based management system may help prevent haphazard risk taking not conducive to good operating practices.

The initiation of ISOs may provide a good opportunity to introduce probabilistic techniques because (1) new procedures will have to be developed by the ISO in any case and (2) because under an ISO a single operator will control more of the transmission system thus potentially reducing the overall cost of undertaking the analytic work necessary to implement a probabilistic approach. Risk assessment would be conducted by one entity over a broad area, as opposed to many utilities having to conduct separate risk assessments covering the same region.

With potential real dollar costs associated with mandatory compliance with deterministic reliability criteria, there may be greater interest by industry participants in examining alternatives, such as probabilistic risk assessment.

Probability based reliability criteria could uncover areas of potential savings in the operation of generation, such as reduced reserve margins, without damaging reliability.

Cons: All the tools for implementing risk based reliability criteria may not be available.

If undertaken as a comprehensive grid-wide effort, the use of risk based reliability criteria could involve a long-term, costly analytic process. (The incremental use of risk based reliability criteria, e.g., establishing risk based reliability criteria for certain features of the grid, would not be so time consuming or expensive.)

Using risk based reliability criteria may yield results no different from those developed using the current deterministic approach.

Potential unintended consequences:

Use of inadequate assessments of various contingencies could hide potential threats to reliability.

A focus on probabilistic risk assessment could divert attention from important issues, such as enforcement of reliability criteria, right-of-way maintenance, etc.

Presently, reliability criteria are developed through processes internal to NERC and the regional reliability councils. ⁽²⁴⁾ Under this option, proposed reliability criteria would be reviewed by state/provincial agencies and the public. (This public review process would augment the existing process by which criteria are developed.) The regional reliability council would have to respond as to why suggested changes to the proposed criteria were not adopted.

Pros: A public review process would give state/provincial agencies ⁽²⁵⁾ and customers an opportunity to understand the underlying rationale for reliability criteria, to question the proposed criteria and to raise new issues. This open process may become more important in the future as individual customers may need more information on system reliability when making supplier decisions.

Important concerns of customers, which may have been overlooked in the past, may be identified in an open process.

A more public process for developing reliability criteria may give regulators and legislatures greater comfort in acting to make compliance with such criteria mandatory.

Cons: This could be a time and resource consuming process, particularly because of the technical complexity of the issue.

Some process would have to be agreed upon to make decisions when a significant portion of the public and states/provinces disagreed with the proposed criteria.

Unintended Consequences:

A public process for establishing reliability criteria may harden the views of segments of the industry or of different areas within the West thereby making compromise more difficult.

3. Expanding the number of factors which reliability criteria address.

In contrast to the use of predetermined criteria, additional reliability factors could be incorporated into real-time modeling of the system. Operation of the system within the constraints identified by the model would be required. Depending on the current conditions on the system, this might allow system operators to exceed predetermined criteria for a period of time if the model indicates that such exceedance would not jeopardize system reliability. ⁽²⁶⁾

Pros: New criteria, if followed, could promote uniformity in right-of-way maintenance practices in the western grid and reduce the risk of outages resulting from shorts caused by trees.

Cons: Becoming ever more prescriptive in developing standards adds complexity to the situation and would likely result in the application of requirements which may not be relevant in all circumstances, thereby increasing cost with little benefit.

It is very unlikely that new reliability criteria can be written to cover all eventualities.

Potential unintended consequences:

Resources may be wasted in adopting new criteria to address low probability, low consequence events.

With additional and more detailed criteria, system planners and operators may incorrectly conclude that all events are covered by the reliability criteria, with the result that system operators and planners do not independently exercise their best engineering judgments.

For example, criteria could require that additional contingency (including equipment failure) studies be performed to cover events such as those that led to the July and August outages. Existing standards governing equipment performance could be more specific (e.g., regularly scheduled tests of relays and other equipment could be required). Standards for communication among operators of the transmission system during crisis times could be expanded and made more specific.

Regardless of what criteria are chosen, one must be able to administer the criteria. This means that the criteria must be specific and measurable. Specific and measurable criteria are necessary in order to monitor compliance and impose sanctions for non-compliance. Existing criteria may not be sufficiently specific and measurable. The NERC Reliability Compliance Team has recommended that NERC "...perform a comprehensive review of the existing policies, standards, and criteria to ensure they are specific, measurable, adequate and appropriate for the new industry environment." ⁽²⁷⁾ Finally, there needs to be clear institutional accountability for those who establish, for those who implement, and for those who enforce reliability criteria.

Pros: Specific and measurable criteria are needed to ensure that all the entities using the grid know the rules.

To be enforceable, criteria must be specific and measurable.

Expanded analysis of contingencies in the western grid would likely be significantly less expensive than additional outages.

The formation of ISOs provides a good opportunity to expand the analyses of contingencies and to develop new strategies for dealing with such contingencies. An ISO will have more alternatives to deal with reliability problems than individual utility operators of the system who can only control actions taken on their lines and not neighboring lines.

Cons: In a complex network like the western grid, there can be innumerable contingencies that might lead to an outage. It would be difficult to find and evaluate all such contingencies. It may also not be economically appropriate to protect against all such outages.

Specific, measurable criteria will be difficult to develop given the increasing number of members in the WSCC, particularly if such criteria are enforceable and non-compliance subjects the violator to sanctions.

Some criteria, such as a requirement that analyses be performed of various sequences of events that could contribute to an outage, may be difficult to measure. For example, would one measure the number of analyses performed? Or, would one try to measure the appropriateness of the scenarios that were selected for analysis?

Potential Unintended Consequences:

Specific equipment maintenance criteria, such as schedules for testing of relays, which are unrelated to the consequences from the failure of a relay (i.e., the cost of an outage ), could result in insufficient testing of critical relays or excessive testing of relays which will have little impact on reliability even if the relay fails.

If all criteria are specific and measurable, some market participants may seek "loop holes" in the criteria and then argue that they cannot be sanctioned for taking actions threatening reliability because such actions are not prohibited by a specific criterion. For example, a generator may elect to go off-line during a period of system instability and, following system failure, offer their power at a higher price.

Current reliability criteria are developed and adopted by NERC and its regional reliability councils. This option would put either FERC or a consortium of states (and provinces), or both states and FERC, through a joint process, in the position of overseeing the development of reliability criteria, ruling on appeals to proposed criteria, and approving changes to reliability criteria.

Pros: Having FERC and/or a consortium of states (and provinces) oversee the development of new criteria, deal with appeals of proposed criteria and approve changes to reliability criteria, explicitly recognizes that there is a major public interest affected by the setting of reliability criteria. The interests of consumers (particularly small consumers who are unlikely to participate in any public meetings) would be better represented by FERC or the states.

Governmental review and approval of criteria also provides some cover for the industry in the event of an outage since agencies charged with representing the public interest approved the reliability criteria.

Governmental oversight may be a requisite for any grant of power authorizing NERC or regional reliability councils to both require compliance and to penalize non-compliance with reliability criteria. The government needs to have a mechanism to determine whether this grant of authority is being abused (e.g., criteria are not sufficiently specific to be measurable, thus making enforcement impossible).

Cons: Imposition of a government review and approval process adds time and expense to an already lengthy process of developing criteria.

The FERC and states (and provinces) generally do not have technical expertise to bring to the reliability problem.

An entirely new forum would be required if a consortium of states (and provinces) was charged with the responsibility for reviewing and approving reliability criteria.

FERC may not have adequate staff or resources to review and approve reliability criteria.

Potential unintended consequences:

Industry participants may use the governmental review and approval process as a tactic for delaying needed changes in reliability criteria.

B. Compliance with Criteria: NERC and regional reliability councils are voluntary associations of private companies and public power utilities. The participation of dozens of new entities such as power marketers and independent power producers, together with increased competition among utilities, will make the regional reliability council's practice of operating by consensus increasingly difficult, particularly when penalties are to be applied for failure to follow reliability criteria.

There are at least three important compliance issues: (1) how to ensure that all generators and operators of the grid (e.g., those that operate load control areas or ISOs) are subject to the reliability criteria; (2) how to determine the extent of compliance and who will make that determination; and (3) what type of penalty will be charged for non-compliance and who will administer the penalty.

1. An "industry compact" should be adopted wherein the industry voluntarily implements and submits to "mandatory compliance and enforcement";

2. A FERC-regulatory responsibility to backstop the "industry compact" should be created thereby obligating all market participants to adhere to mandatory compliance through the terms and conditions in open access transmission tariffs, interconnection agreements, licenses, and approvals of independent system operators and power exchanges; and

3. The U.S. Department of Energy needs to adopt a policy role to support the industry initiatives to move to mandatory compliance. This would include giving industry a deadline to develop a specific plan to implement mandatory compliance and identify needed legislation.

NERC will consider these principles at a meeting in January 1997.

WSCC believes this approach will obviate the need for prescriptive government intervention. WSCC further believes that "...[r]eliability councils should transition from a coordinating role to enforcement and compliance through adoption and periodic updates of reliability standards to ensure they are clear and specific." NERC and WSCC would need standard setting, monitoring, enforcement and sanction capability. The Western Systems Coordinating Council believes that all market participants doing business in the western grid (including, but not limited to ISOs, control areas, security coordinators, independent power producers, transmission owners, and power marketers) must become members of the WSCC. WSCC intends to establish a task force to recommend a course of action to achieve these principles.

Some have suggested that in a changing electric industry environment NERC, and by analogy the regional reliability councils, will need to exercise initiative and independence in measuring performance, conducting reliability assessments and ensuring compliance. Granting reliability bodies greater authority to act on their own raises issues with respect to governance of the institution. Clearly, all types of users of the grid (e.g., utilities, independent power producers, brokers, marketers) need to be part of the governance of any institution charged with maintaining reliability. However, what role should customers play? What role should states, provinces, and federal governments play? To what extent are customers and government agencies willing to participate?

From a public policy perspective, states need to examine the full range of potential options for enforcing compliance with regional reliability criteria, including the options being pursued by the WSCC.

There are at least eight options for promoting compliance with regional reliability criteria. Following are a brief description of the options and a discussion of the advantages and disadvantages of each option. As with all changes, one needs to beware of potential unintended consequences resulting from each of the options.

1. Do nothing - continue to rely on voluntary compliance with regional reliability criteria.

Cons: To many the existing system which resulted in the July and August outages is not acceptable.

The historic approach may become increasingly tenuous in a more competitive western electricity market, as market players see little advantage in taking steps to ensure system reliability when the benefits of such increased reliability flow to other competitors as well.

Failure to pursue a system of enforceable reliability criteria may signal to transmission utilities that regulators feel that recent outages, such as those experience in July and August 1996, represent acceptable levels of performance. As a consequence, reliability may degrade further.

2. Ask the Federal Energy Regulatory Commission to require compliance with regional reliability criteria as a condition of marketing licenses, transmission tariffs, transmission access orders, and approvals of ISOs and power exchanges.

By FERC orders, all marketing licenses, transmission tariffs, transmission access orders and approvals of ISOs and power exchanges would include language requiring compliance with regional reliability criteria. ⁽²⁸⁾ These conditions would apply to FERC jurisdictional utilities and through reciprocity provisions, to non-jurisdictional utilities. The reciprocity provisions would operate in a manner similar to reciprocity for open transmission access under FERC Order 888. ⁽²⁹⁾

Under this option, FERC could (1) directly impose sanctions for non-compliance or (2) authorize regional reliability councils to impose sanctions for non-compliance. Sanctions could include being "economically disconnected" from the grid and prohibited from conducting business. Additionally, provisions could be written in all power contracts which would allow the parties to the contract to enforce reliability provisions.

Pros: This requirement would reach all generators and operators of the grid, including parties not under the jurisdiction of state PUCs.

FERC action implies greater uniformity among grid users in the U.S. and, through reciprocity requirements, to generators and operators of the grid in Canada and Mexico.

Establishing compliance with reliability criteria as a power sales contract provision may be the easiest avenue for promoting uniformity and compliance across international boundaries.

Setting such a system in place may be faster than enacting an interstate compact, uniform state laws or new federal law.

Direct FERC enforcement for non-compliance would:

Remove enforcement from an organization comprised of grid operators and market participants; and

Avoid the problem of granting the power of government authorized sanctions to a private party.

Enforcement by regional reliability councils would:

Limit the role of government in reliability; and

Put enforcement responsibility in the hands of those most knowledgeable of the grid.

Cons: It is unclear how a regional reliability council would enforce sanctions for non-compliance. The role of affected parties, security coordinators and the various committees of the regional reliability council would need to be defined.

It is unlikely that FERC will grant enforcement powers to a non-governmental body, such as a regional reliability council, without retaining some form of oversight.

FERC does not have adequate staff or expertise to either oversee enforcement by regional reliability councils or execute direct enforcement actions itself.

Direct FERC enforcement in the event of non-compliance may result in a "one-size-fits-all" nationwide requirement with undesirable consequences in the western grid.

Potential Unintended Consequences:

Parties who establish, monitor and enforce reliability criteria may be liable for damages resulting from an outage.

States and provinces may have no role in the enforcement of reliability criteria.

Pros: Ensures that transmission users are members of the body establishing regional reliability criteria.

May make it easier to sanction a party not in compliance with regional reliability criteria if the party is a member of the sanctioning organization and had previously agreed to comply with such criteria.

Cons: Membership in a regional reliability council could become a barrier to entry for small new market participants, particularly if membership dues are significant. (This could be addressed through variable membership fees.)

Potential unintended consequences:

Mandatory membership in regional reliability councils which are not subject to government oversight may be construed as an inappropriate granting of governmental powers (e.g., the ability to tax, the ability to deny access to the grid for non-compliance) .

4. Have public utility commissions order their jurisdictional utilities to comply with regional reliability criteria and impose sanctions for non-compliance.

Pros: Assuming each state or province has the authority to issue such an order, this option could be enacted rapidly.

Cons: Typically, PUCs do not have jurisdiction over municipal utilities, rural cooperatives, generation and distribution cooperatives or federal power marketing administrations, all of which are major users of the western grid.

The PUC in one state may be reluctant to impose sanctions on its utility if the utility's actions to protect local customers led to an outage in another state.

It may be difficult to get all state PUCs to adopt similar sanctions, thereby ensuring a level playing field. The problem with inconsistency of rules across states would be exacerbated when a multi-state utility is being sanctioned.

Additional PUC staffing may be required to police enforcement and impose sanctions.

A requirement that only PUC jurisdictional utilities must comply would create an unlevel playing field among investor-owned utilities, public power, independent power producers and power marketers and brokers. This situation would provide an opportunity for non-jurisdictional parties to seek economic gain, potentially at the expense of reliability.

5. Enact uniform state laws requiring all generators and operators of the grid, including municipal utilities and rural cooperatives, to abide by regional reliability criteria and be subject to sanctions for non-compliance.

Pros: Would achieve uniformity among states without federal action.

Would reach all users of the grid, except the federal power marketing administrations.

Cons: May be difficult and time consuming (e.g., several years) to enact.

Would allow each state to unilaterally change its rules thereby undermining regional uniformity.

Would not reach federal power marketing administrations.

Would not apply to users and operators of the grid outside the U.S.

It is not possible under some states' laws to require compliance with future criteria which may be developed and adopted by a non-government body. That is, state law would not incorporate future changes to reliability criteria by a regional reliability council.

Which state agency would impose sanctions? The PUC? The Attorney General? Another agency? Regardless of which agency is responsible, policing compliance with reliability criteria and imposing sanctions would require additional state expenditures.

Potential Unintended Consequences:

Efforts to effectuate state-mandated compliance with reliability criteria may raise concerns among public power entities that the state will ultimately extend the jurisdiction of PUCs to public power entities.

To avoid giving blanket endorsement to all existing and future criteria adopted by regional reliability councils, some states may decide to specify the reliability criteria to be followed. This would raise the prospect of conflicting criteria being adopted by different states.

6. Amend federal law to require generators and operators of the grid, including federal power marketing administrations, to comply with reliability standards and provide sanctions for non-compliance.

An amended Federal Power Act would require all users of the transmission system to abide by regional reliability council criteria. The FERC or the Department of Energy would be empowered to investigate instances of non-compliance and impose sanctions. (Such an amendment could also set out a public process for the review and adoption of regional reliability criteria.)

Pros: Would require compliance by all users of the grid.

Would promote uniformity in criteria and enforcement of compliance.

Cons: FERC and DOE have no staff to police the reliability issue.

Could be difficult to pass legislation due to concerns among public power entities about the FERC or DOE extending jurisdiction over their activities.

The process for reviewing criteria, investigating non-compliance, and imposing sanctions would likely become drawn out and litigious.

Would not apply to users of the grid outside the U.S.

Potential Unintended Consequences:

Uniform national enforcement may lead to a lowest common denominator approach with inadequate sanctions for major power outages which are more likely in the western grid with its long distances between loads and generation compared to the more tightly knit grid in the East.

7. Adopt an interstate compact to set and enforce criteria

To form an interstate compact to set and enforce reliability criteria, uniform legislation would need to be enacted in each participating state and the legislation would need to be enacted by Congress and the President. A compact may or may not have a staff.

Pros: Interstate compacts are, in essence, contracts among states which cannot be unilaterally changed by one state. A compact would add permanence and uniformity.

Congressional sanction of an interstate compact would mitigate any legal problems associated with claims that the compact is interfering with interstate commerce.

Cons: Interstate compacts are time consuming to adopt.

States may be reluctant to bind themselves under an interstate compact.

Voting rules and state representation may be contentious issues.

A compact would not apply outside the U.S.

Potential Unintended Consequences:

A compact could result in duplicate levels of enforcement if FERC or DOE is also authorized to enforce regional reliability criteria.

8. Foster the creation of one (or more) independent system operators (ISO)

Pros: ISOs can help ensure reliability because their mission is limited and without conflict. An ISO, which would be a regulated entity, would be free from competitive pressures to cut costs in areas such as right-of-way maintenance. An ISO would have more options for responding to operational problems than individual control areas. ISOs would have the tools to control scheduling and counter scheduling. ISOs cannot derive strategic benefit out of selective outages.

One ISO in the western grid would clearly pinpoint accountability for compliance with reliability criteria.

Cons: Decisions on rates charged by an ISO would be left to FERC.

There are a number of potential impediments to the formation of ISOs, including: developing adequate governance provisions which comply with the FERC principles for ISOs; potential liability the ISO may incur; determining the degree of control the ISO will have over system expansion; developing a transmission pricing system to address congestion; and developing incentives to optimize throughput on the system, but not at the expense of reliability.

An ISO proposal may have difficulty securing required PUC approvals in some states. For example, to date, it is not fully understood what the filing requirements will be for the utilities seeking approval from seven northwestern states to establish an independent grid operator in that region (i.e., IndeGO). In some states, the filing may be subject to transfer of property statutes. Parties would therefore have to demonstrate that utility participation in IndeGO is in the public interest as evidenced by transmission cost savings or other benefits to citizens. Additionally, if the filing requirements differ among the states and are unduly onerous, the IndeGO utilities may withdraw from the effort to form an ISO. ( The regulatory agencies in the Northwest are currently working to resolve these and other regulatory issues.)

Given that an ISO is not a market player, it may have a reduced incentive to operate efficiently.

If multiple ISOs are created in the West, there will remain a need for inter-ISO coordination.

APPENDIX A: Excerpts of WSCC Reliability Criteria

For transmission system planning, WSCC states ⁽³⁰⁾ that:

It is recognized that it is impossible to provide 100 percent reliability of power supply. Within a single system, it is expected that each member will, insofar as practical, protect its customers against loss of service. With the development of the complex interconnected systems, it is likely that a disturbance on one system will be reflected in varying degrees on other systems. The setting of limits of this effect on other systems is the objective of the criteria in this document.

Each member of the Council, each Pool or other group of Council members may have criteria which differ from the criteria presented in this document. Such differences may be justified by the geography of the area, type of load being served, system configuration, weather consideration, or other reasons. It is not required that such individual system criteria conform to this Council Criteria for the evaluation of that system's planned performance for simulated disturbances or operating conditions on its own system...

These criteria are based on the understanding that there should be no loss of load on a system for the more common single system element disturbances originating on other systems. There are disturbances that are credible but of low probability for which it is not feasible to protect the systems against islanding and/or loss of load. These criteria recognize the necessity for islanding and load shedding for certain disturbances, but such islanding and load shedding should be controlled so as to limit the adverse impact of the disturbance and to leave the systems in such condition as to permit rapid load restoration and re-establishment of interconnections. Uncontrolled loss of load is unacceptable even under the most adverse credible disturbance...

Insofar as reliability is concerned, each system should be planned on the basis of adherence to the following principles:

1. Each system should provide sufficient transmission capacity within its system to serve its load and meet its transmission obligation to others without unduly relying on or without imposing an undue degradation of reliability on any other system, unless pursuant to prior agreement with the system(s) so affected.

3. Each system should conduct the necessary studies to demonstrate that its power transfers, in the absence of loop flow, will not unduly rely on or impose an undue degradation of reliability on parallel transmission capacity of any other system, except pursuant to prior agreement with affected system(s).

Each system should plan its system with adequate transfer capability so that its power transfers will not have an undue loop flow impact on other systems, and so that planned schedules do not depend on opposing loop flow to keep actual flows within the path transfer capability. A system adding facilities should recognize that the addition itself could result in a component of loop flow that should be accommodated.

Loop flow is an inherent characteristic of interconnected AC systems and the mere presence of loop flow on circuits other than those of the transfer path is not necessarily an indication of a problem in planning or in scheduling practices.

4. Each system should provide, by ownership or agreement, sufficient reactive capacity and voltage control facilities to satisfy the requirements of its own system without imposing an undue burden upon other systems.

5. Because numerous transfers on different systems take place at any given time, each system should establish its transfer capability ratings based upon a credible range of simultaneous transfers on other systems. A system may rate its transfer capability based on less than credible maximum simultaneous transfers if its plans include schedule limitations under these conditions in accordance with WSCC guidelines. Applicable WSCC facility rating guidelines or procedures should be followed.

Regarding power supply design criteria, WSCC states that :

The criteria in this document are intended to provide, for the guidance of members, recommended minimum levels of installed and planned generation for systems and areas within the WSCC in order to permit evaluation, upon a common basis, of the relative reliability of the interconnected bulk power systems. The criteria do not purport to establish any measure of industry design standards as to member systems, nor are they created for such purpose, it being recognized that the systems of members, pools, or other groups of Council members, may be properly and adequately designed to different criteria.

Each member of the Council, and each Pool or other group of Council members, may utilize criteria which differ from the criteria presented in this document. Such differences may be based upon the geography of the area, type of load being served, system configuration, customer expectations based upon past performance, or other reasons considered appropriate by such member, Pool or group, as long as the minimum requirements of the WSCC criteria are met.

Regarding minimum operating reliability criteria, WSCC states:

The Western Systems Coordinating Council (WSCC) members will operate their systems in accordance with the NERC or WSCC Reliability Criteria whichever is more specific or stringent...

The bulk power systems will be operated at all times so that general system instability, uncontrolled separation, cascading outages, or voltage collapse will not occur as a result of the most severe single contingency...

When it is agreed that a disturbance on specific facilities occurs more often than should be reasonably expected and results in an undue burden on other systems, the owners of the facilities should take measures to reduce the frequency of occurrence of the disturbance, and cooperate with other systems in taking measures to reduce the effects of such disturbance.

1. DOE has the authority to order temporary interconnections and the generation and transmission of electric energy in emergency situations under Section 202(c) of the Federal Power Act [16 U.S.C. Sec824a(c)]; the authority to define reliability regions and encourage interconnection and coordination within and among regions under Section 202(a) of the Federal Power Act [16 U.S.C. sec824a(a)]; and the authority to gather information regarding reliability issues and make recommendations regarding industry standards for reliability under Section 209 of the Public Utility Regulatory Policies Act [16 U.S.C. sec824a-2)].

On December 18, DOE created a task force on reliability headed by former House Energy & Power Subcommittee Chairman Philip Sharp which is charged with evaluating the reliability of the U.S. electric power system. The task force is to examine technical, institutional and policy questions surrounding reliability issues.

2. The Electric Power Outages in the Western United States, July 2-3, 1996, Report to the President, U.S. Department of Energy, August 1996.

3. For example, the WSCC reliability criteria document is subdivided into four parts: (1) reliability criteria for transmission system planning; (2) power supply design criteria; (3) minimum operating reliability criteria; and (4) definitions (November 1995). The NERC Operating Manual is organized into (1) operating policies (generation control and performance, transmission, interchange, system coordination, emergency operations, operations planning, telecommunications, and operator and personnel training), (2) training documents, (3) data, (4) references, and (5) operating committee. Members of the regional reliability councils are to comply with both the regional criteria and the NERC criteria. Unfortunately, these criteria are not integrated into one comprehensive document which delineates all reliability criteria applicable in the western grid.

4. The reliability criteria established by the other three regional reliability councils in the WGA states were not examined.

5. WSCC's reliability criteria do recommend that members with a significant percentage of independent power producer-owned generation utilize probability methods for reserve planning and reporting. WSCC further recommends that all systems ultimately report installed and planned reserve levels using probability methods. (WSCC Power Supply Design Criteria, p. 4)

6. A proposed change to the reliability criteria for transmission system planning is sent to the WSCC's Reliability Subcommittee. After consideration, the Reliability Subcommittee recommends its agreed-upon changes to the WSCC Planning Coordination Committee for approval. With respect to modifying the WSCC minimum operating reliability criteria, a review of the criteria at least every five years is required. The WSCC Minimum Operating Reliability Criteria Work Group is responsible for conducting the review, which is to be coordinated with the Reliability Subcommittee. The Work Group will report to the Compliance Monitoring and Operating Practices Subcommittee which will, in turn, report to the WSCC Operations Committee, which will adopt changes. Ultimately, the WSCC Board of Trustees approves changes to both system planning and operating criteria. (WSCC Reliability Criteria, November 1995)

7. While no comprehensive data on the cost of power outages exist, the California Energy Commission assembled some anecdotal evidence of the August 10, 1996 outage which cut service to 2.8 million customers in California. The "clean rooms" of computer manufacturers were contaminated. One manufacturer lost $1.4 million in the western U.S. including $500,000 at a Santa Clara plant. Another manufacturer lost an entire production run valued at $1 million. One oil refiner lost $7 million in product at two refineries. San Francisco had inadequate fire protection capability since only three of eight water storage facilities had back-up generators. The San Francisco police spent $30,000 for personnel needed for law enforcement, traffic control and elevator rescues. One cogenerator lost $571,000 when its plant tripped and then encountered fuel feed problems on restart. (Of course, the cost of grid outages can be mitigated where customers have backup power sources.) (Supplemental information for September 5, 1996 ER 96 Committee Hearing, California Energy Commission)

8. The cost associated with an outage (where customers do not have backup power sources), and thus the relative value placed on system reliability, is likely to vary significantly among customers. For example, a residential customer may not be willing to pay for 100 percent reliability because he/she can survive without electric power without incurring significant cost. On the other hand, semi-conductor manufacturers can lose millions of dollars when production runs are lost because of a failure of the electricity supply. A question arises whether reliability needs to be at the level needed by a semi-conductor manufacturer and, if so, who should pay for such a high level of reliability. The allocation of costs among customers in accordance with the benefits they receive will likely become more difficult in an industry where generation is unbundled from transmission.

9. It is important to note that both the July and August outages were initiated as a result of transmission lines sagging into trees. While the extent and severity of the outages may have been mitigated had sufficiently encompassing contingency studies been performed, the initiating events would have occurred nonetheless.

10. Less than a second after the 345 kV Jim Bridger-Kinport line was lost on July 2, the parallel 345 kV Jim Bridger-Goshen line tripped off-line due to a faulty protective device. The near simultaneous loss of two 345 kV lines at Jim Bridger led to implementation of a remedial action scheme which shut down two of the four generating units at the plant. Just seconds after the two units at Jim Bridger tripped, a 230 kV line in Oregon shut down due to a malfunctioning relay. Voltages continued to decline thereafter, causing other lines to de-energize and ultimately resulting in system islanding.

11. WSCC Reliability Criteria, November 1995.

12. Ibid.

13. Options to Ensure Compliance with NERC and Regional Reliability Council Policies, Standards and Criteria, NERC Reliability Compliance Team, October 12, 1996.

14. Statement of Puget Vice President Gary Swofford at the April 11-12, 1996 meeting of the Committee on Regional Electric Power Cooperation.

15. The framework for ensuring reliability may be undergoing change as a result of the formation of ISOs and regional transmission associations in the West.

16. Remarks of Trudy Utter, Tenaska Power Services, and Mark Bonsall, Chairman of the WSCC, at the December 5, 1996 Western Governors' Association Roundtable on Electric Industry Restructuring.

17. Mark Ziering, California PUC.

18. There are presently 33 load control areas in the Western Interconnection.

19. BPA Journal, December 1996.

20. Options to Ensure Compliance with NERC and Regional Reliability Council Policies, Standards and Criteria, NERC Reliability Compliance Team, October 12, 1996.

21. Note that new technologies can increase transmission capacity, but may be less reliable than the addition of a new transmission line because more things can fail with a control device than with a transmission line.

22. Traditional reliability criteria based on deterministic considerations may become increasingly difficult to apply as the traditional utility functions are unbundled. (Reliability Issues in Today's Electric Power Utility Environment, a soon to be published paper by R. Billinton, et al.)

23. Reliability Issues in Today's Electric Power Utility Environment, a soon to be published paper by R. Billinton, et al.

24. The Bonneville Power Administration has used public meetings to gather views on the agency's reliability criteria.

25. Note that many utilities in the West are not within the jurisdiction of the state regulatory agencies (e.g., municipal utilities, federal power marketing agencies).

26. Some argue that the flexibility to violate a reliability criterion, such as the allowable limits on power flows on a line, should be allowed if the value of the additional transactions is great enough to warrant the risk of a potential outage. (Larry Nordell, Montana DEQ)

27. Options to Ensure Compliance with NERC and Regional Reliability Council Policies, Standards and Criteria, The NERC Reliability Compliance Team, October 12, 1996.

28. This does not necessarily require that the operators and users of the grid be members of a regional reliability council. See option three for a discussion of mandatory membership in regional reliability councils.

29. FERC Order 888 states: "A Transmission Customer receiving transmission service under this Tariff agrees to provide comparable transmission service to the Transmission Provider on similar terms and conditions over facilities used for the transmission of electric energy in interstate commerce owned, controlled or operated by the Transmission Customer and over facilities used for the transmission of electric energy in interstate commerce owned, controlled or operated by the Transmission Customer's corporate affiliates."

30. WSCC Reliability Criteria, November 1995.