DOE Electric Reliability TF-2nd Meeting Minutes

Subject: UFTO Note – DOE Electric Reliability TF-2nd Meeting Minutes
Date: Mon, 19 May 1997
From: Ed Beardsworth

| ** UFTO ** Edward Beardsworth ** Consultant
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DOE SEAB Electric Reliability Task Force-2nd Meeting Minutes

According to our contacts at DOE, the second meeting went well. The group is starting to close on some basic assumptions regarding the future of the electric power industry and on a set of basic concepts/requirements for electric system reliability. In addition, the Task Force is gaining a better understanding of the differing viewpoints of NERC, Power Marketers, and DOE on how to maintain and assure reliability.

The complete minutes are posted at

Secretary of Energy Advisory Board
Task Force on Electric System Reliability

Minutes of Second Task Force Meeting March 25, 1997
Madison Hotel, Washington, D.C.

1.0 Opening Remarks and Perspectives

The second meeting of the Secretary’s Task Force on Electric System Reliability was held on March 25, 1997, in the Madison Hotel, Washington, D.C. Chairman Sharp opened the meeting at 8 a.m., noted that several new members had been added since the first meeting, and introduced those members. Following the introductions, Chairman Sharp stressed his receptiveness to advice from members at any time on how best to handle the agenda and schedule to make the best use of time. He stated his intent to try to get general consensus on a number of issues but stressed that at most some tentative conclusions might be reached at this meeting. He assured the members that they would have other opportunities to consider both the statement of the issues and the consensus Task Force position on each. He encouraged members to speak up and register their thoughts and concerns as the meeting proceeded.

Robert Hanfling, Chairman, Secretary of Energy Advisory Board (SEAB), was introduced by Chairman Sharp and welcomed the Task Force members on behalf of the SEAB and Secretary of Energy, Federico Peña.

2.0 Discussion of Assumptions Regarding the Future of the Electricity Industry

The Chairman thanked Dr. Theresa A. Flaim for her paper about how the electric industry is likely to evolve which proposed a division of assumptions into; A) those on which there may be emerging consensus; and, B) others. He asked that she lead the discussion of assumptions on which there may already be consensus among members. The Task Force opted to add several assumptions, including the one listed first, to better indicate its sense of priorities. There was preliminary consensus on each of the following assumptions:

Assumption #1: The reliability of the bulk electric power system will be maintained.
Comment: The reliability of the bulk electric power system must be a paramount objective in the transition to and maintenance of a competitive market. It was agreed among the members that introduction of competition should not be allowed to negatively impact the reliability of the nation’s integrated bulk electric power system.

Assumption #2: Retail customers will have their choice of supplier.
Comment: Retail customers in many states will also have the right not to choose (i.e., retain service from their existing supplier with a presumption that supplier would remain a provider of last resort).

Assumption #3: Generation can and likely will be deregulated as to price.
Comment: Although market power and transition costs were considered likely to be difficult issues, they were believed not to be closely linked to reliability.

Assumption #4: Transmission and distribution will remain regulated.
Comment: Some ancillary services may be purchased competitively on the open market.

Assumption #5: Power marketers, brokers and commodity retailers will have significant roles.
Comment: None.

Assumption #6: A reliable system will require a Regional Independent Operator (RIO).
Comment: The Task Force noted its unwillingness to use the term “ISO” because it is presently used in widely differing ways by other parties and to avoid appearing to support a particular type of institution at this time.

Assumption #7: The RIO will be a monopoly function and, thus, will need to be regulated.
Comment: This would not preclude a competitive process for acquiring RIO services or for outsourcing by the RIO for specific functions to for-profit contractors.

Assumption #8: Traditional obligation-to-serve compacts will be replaced by obligation-to- connect compacts.
Comment: None.

Assumption #9: RIO’s must not have a commercial interest in the market.
Comment: The security function must be separated completely from commercial operation of the market to avoid conflict of interest.

Assumption #10: RIOs must be able to direct and re-dispatch all generators and customers during emergencies.
Comment: However, RIOs would not necessarily need to have direct control of generation.

Assumption #11: The reliability of the bulk electric power system must be compatible with a range of reliability options for individual customers.
Comment: Customer end-use reliability should be conceptually distinguished from bulk electric power system reliability.

3.0 DOE Paper on Electric Systems Reliability Concepts

The Chairman moved to a discussion of a DOE staff paper intended to promote a better understanding of reliability by identifying basic system concepts and actions required for its attainment/maintenance. The members discussed the primary points made in the paper and reached general agreement on the following concepts:

Concept #1: Characteristics of Electric Systems
General Agreements: The Task Force generally agreed with the staff paper position as follows:

• The bulk power system needs continuous and near instantaneous balancing of generation and load.

• The transmission network is primarily passive but is becoming more active in time..e.g., FACTS.

• Any action can affect many other activities on the grid. — The activities of all players must be coordinated. However, all actions are not equally important.

• Cascading outages are unacceptable. — The physical system and the rules for its operation must minimize the likelihood of such outages.

• The need to be ready for the next credible contingency dominates the design and operation of the bulk power system.

Concept #2: Historical Design Criteria
General Agreements: The Task Force generally agreed with the staff paper position as follows:
• Generation & Transmission Adequacy — Capacity needed to maintain reliability is usually based on probabilistic analyses intended to meet a loss-of-load probability of one day in ten years.

• Generation & Transmission Security — Capacity needed to maintain reliability is based on
N-1 contingency.

Concept #3: Seven Critical Activities for A Reliable Power System
General Agreements: For the purposes of this discussion, the Task Force defined the term ‘system’ to include loads, transmission, distribution and generation and expanded the list of critical activities suggested in the DOE staff paper from five to seven. The additions are distinguished by an asterisk (*).

• Observe the network.
• Analyze and model the system.
• Communicate with operators of other systems.*
• Take control actions.
• Monitor and enforce compliance.
• Plan to expand and/or modify the system (including load management).
• Ensure incentive system for reliability.*

Concept #4: Time Scales for Reliability Maintenance.
General Agreements: The DOE staff paper pointed out that actions required to maintain system reliability take place in very different time frames, from cycles to minutes, to day ahead, to week ahead, to annual maintenance scheduling, and to several years ahead for transmission and generation planning. Each activity and its relative time frame is indicated in Table 1, shown at the end of this document.

Concept #5: Potential Restructuring Impacts
General Agreements: The Task Force generally agreed with the staff paper position that restructuring is likely to affect activities in different time frames, as follows:

• Automatic Protection — No effect
• Disturbance Response — Must consider contractual obligations
• Regulation and Voltage Control — Competitive markets will replace centralized control in selecting resources
• Economic Dispatch — Selecting units based on markets need not affect reliability
• Maintenance Scheduling — Scheduling of transmission maintenance should be under the authority of the Regional Independent Operator
• Fuel Planning — No effect
• Transmission Planning — If congestion rents can be captured, reliability constraints will be relieved. If not, there will be little incentive to take actions to relieve constraints.
• Generation Planning — Reliability will be maintained during the transition from central planning to the marketplace.
4.0 Panel Discussion and Roundtable on Policy and Institutional Issues

The Chairman moved to the next item on the agenda and introduced each of three panelists representing different perspectives on reliability and restructuring: Marc W. Chupka, DOE Acting Assistant Secretary for Policy and International Affairs; David R. Nevius, Vice President of the North American Electric Reliability Council (NERC); and, Barry N. P. Huddleston, Regional Manager, Regulatory Affairs, Destec Energy Corp. The Chairman pointed out that the panelists’ positions on each of the seven policy and institutional issues scheduled for discussion were documented in the meeting material and that, consequently, he would ask them to provide only brief introductions and then join in the Task Force roundtable discussion of each issue.

After a brief introduction by each panelist, the Chairman opened the discussion of the issues presented in the meeting material. While it is premature to consider any of the comments shown below as a conclusion or consensus by the Task Force, the following reflects some of the more notable opinions relative to each issue discussed.

Issue #1: Who should define and measure bulk power system reliability?
• Reliability standards should not be legislated.
• The institutions setting reliability standards must be separated from those responsible for measurement or enforcement.
• The composition of the institutions setting reliability standards should reflect that of the restructured industry (including customers).
• Setting and enforcing reliability standards probably will require a regulatory backstop.
• Relationships established by legislation and contracts will need to be well understood (e.g., who has enforcement responsibility? who has an appellate function?).
• In the future, reliability will need to be defined in terms of customer perspectives but customers will not be able to purchase higher reliability than is designed into the bulk electric system unless they are willing to acquire localized resources for themselves.
• Approved tariffs of the future will be required to specify the applicable standards and the consequences that will apply if they are not met.
• Compacts among states to address reliability issues may alleviate the need for intervention by the federal government at the time of an emergency.
• States certainly will want to continue to be involved to protect their constituents.
• Additional federal authority may be needed to resolve all the compliance matters.
• NEPOOL depends on regulatory agencies in six states that have a history of long standing coordination and cooperation, but they rely on FERC regulation for backstop.
• FERC only exercises jurisdiction over 60-70% of the power system. The system also involves Canada and Mexico — clearly not under FERC jurisdiction. Legislation, or the threat of legislation, will be needed.
• A broad based organization (like NERC) is the best option to define standards regarding the security of the bulk electric power system. However, the marketplace should decide on matters of adequacy.
• A region like New England that decides to join together and operate in a unified system may not need federal authority except on issues that may affect the Regional boundaries.
• Legislation may be required to clarify federal authorities, as opposed to expanding them.

The Chairman concluded this portion of the discussion and opened the floor to comments by members of the public.

5.0 Public Comment Period.

The Chair recognized Mr. Mark Lively who indicated his concerns about how the industry will function in a deregulated environment, particularly in terms of two sciences, physics and economics. He referred to NERC’s interests as those representing the science of physics and FERC’s interests the science of economics. He stressed a need to consider them jointly and to be very precise in the definitions used in the process (e.g., utilities have not had an obligation to serve, they have had an obligation to serve at a price). He questioned whether transmission needs to remain a natural monopoly.

The Chair next recognized Mr. Jose Calvo of the Nuclear Regulatory Commission (NRC). Mr. Calvo stressed the need to set reliability standards before problems arise…not afterwards. He indicated NRC’s interests in the possible effects of restructuring on the availability of off-site power for nuclear plants. He noted that additional on-site backup power sources may be needed at nuclear plants if backup supplies from the grid cannot be assured at all times.
6.0 Panel Discussion and Roundtable (Cont’d)

Following comments by the public, the Chairman resumed discussion of the seven issues presented in the meeting material. Again, while it is premature to consider any of the comments shown below as a conclusion or consensus by the Task Force, the following reflects some of the more notable opinions relative to each issue discussed.

Issue #2: Should a minimum capacity requirement, or reserve margin, be established for all load-serving entities?
• The Regional Independent Operator should assure that the necessary minimum reserve is available.
• If capacity reserves can be procured in the market, let the market supply them.
• The system can be operated reliably with insufficient reserves…those customers with reserves could continue to be served while those without would have service terminated.
• Customers that want to pay for 15% capacity overhang should be able to buy it — those that want 30% capacity overhang should be able to buy that — but to obtain higher reliability than the bulk system is designed for will require that customers acquire local supplies for themselves.
• The need to establish day-ahead minimum capacity requirements is clear. The issue is how far to go into the future — 6 months?–12 months?
• Another key issue is ‘who gets disconnected first?’ Those with reserves will stay connected. It is a matter of defining the rights and incentives (or penalties) of customers.
• Long term prices send signals for the investment community to build capacity and, in addition, customers are going to have contracts. The contracts will specify how much reliability customers want.
• Bulk system reliability has the characteristics of a “public good.” That is, everyone wants it. If it is obtained, everyone enjoys it whether they paid their share of its costs or not. Consequently, everyone has an incentive to avoid paying for it — which puts the good at risk.
• A basic problem: How to manage unpredictable loads while minimizing the need for installed capacity? Edicts by fiat on how much reserve capacity is needed for reliability are likely to be incorrect by a significant margin. The solution is to let the market resolve these balancing problems whenever possible.
• Legislation may be required to clarify federal authorities, as opposed to expanding them.

Issue #3: What is the appropriate use of engineering standards and markets to ensure adequate ancillary services?
• The overall presumption of this committee should be biased toward letting the market provide ancillary services …if it can. If it can’t, the Regional Independent Operator takes over. Market rules should be relied on to the maximum extent. A basic problem: Where’s the boundary? Who determines it?
• Make Regional Independent Operators responsible for providing the services but allow self-provision of ancillary services by suppliers and customers as an option.
• Let individual buyers and sellers work out their own arrangements…but assure that the Regional Independent Operator takes over in default.
• Line loading relief and re-dispatch should be a Regional Independent Operator function.

Issue #4: Who should be responsible for transmission planning, construction and maintenance?
• The issue is not who can build…but who has the capacity to collect from customers, so as to cover the costs of construction? Only a regulatory entity has the right to site.
• A regional focus for planning is essential.
• Transmission expansion does not present premium investment opportunities. There does not appear to be any way to avoid taking a regulated approach, with investment going into a rate base.
• The core issue seems to be who should be doing studies to determine whether new transmission is needed and, if so, where.
• Studies done in the 1980s on transmission siting by NGA and Keystone should be reviewed.

Issue #5: What authorities or incentives are needed to ensure that system operators will be able to compel real time actions by users of the bulk power system, when necessary, to maintain reliability?
• Additional regulatory authorities are not needed. It should be possible to design and utilize contract provisions that are capable of ensuring proper behavior by users of the bulk power system.
• Penalty-backed financial decisions could be used to force customers off the system when necessary. After-the-fact assessments of very high costs for service (e.g. $90,000/kWh) are likely to be effective.
• We need an objective, duly appointed body to say what is fair and what the standard (penalty) should be. Probably FERC.
• After-the-fact penalty assessments will assure that someone pays, but in real time someone will have already paid for whatever extra capacity is available, and that margin gives others the opportunity to “lean” on the system. We need to be careful that this sort of opportunistic behavior does not erode the system’s resilience.

Issue #6: What legal recourse should customers, other market participants, or the public have if reliability is not maintained?
• The court system permits utilities, RIOs , etc. to be sued. These entities will have to carry insurance…for which users will have to pay…somehow.
• A FERC-backed stiff penalty ($90,000/kWh) may be the answer.
• Penalties are preferable to extensive reliance on court proceedings.
• Litigation has not been effective in the Northwest.

Issue #7: What is the appropriate role for government in ensuring electric system reliability?
• FERC may be the right agency to handle oversight responsibilities, but are they equipped to handle the additional mission?
• FERC could delegate oversight responsibilities to NERC.
• Bulk power should be a federal oversight responsibility. Local reliability should be a state function.
• An industry compact could cover all sectors that are now regulated by FERC plus some areas (Canada, Mexico) that are non-FERC jurisdictional.
• States may need help in dealing with new T&D issues [EPRI has good material on this, e.g., EPRI has a power quality benchmarking capability already].

7.0 Final Public Comment

The Chairman offered a final opportunity for public comment and Mr. Mark Lively was the only commentor. He offered his opinion that, if a very large penalty ($90,000) was adopted for customers leaning on the system in the short term, the long term will take care of itself. Investors will see the opportunity and invest accordingly.

The Chairman closed the meeting by thanking the members for their participation. He advised them that the next meeting would probably be scheduled sometime in late May but would be coordinated with everyone’s schedule, and adjourned the meeting at 4 p.m.

Mr. Rich Burrow, DOE staff representative to the SEAB, suggested that Task Force members use the SEAB Home Page for information pertaining to minutes of meetings, membership, notices of future meetings, reports, etc. He announced that the Internet address of the SEAB Home Page is: http: //
Table 1:
Services Affecting Bulk Power Reliability

Service Time Scale Description
Automatic Protection Instantaneous Minimize damage to equipment and service interruptions
Disturbance Response Instantaneous-minutes-hours Adjust generation, breaker, and other transmission equipment
Regulation & Voltage Control Seconds-minutes Adjust generation to match scheduled intertie flows and actual system load
Economic Dispatch Minutes-hours Adjust committed units to maintain frequency…at minimum cost
Unit Commitment Hour ahead & week ahead Decide when to start up and shut down generating units
Maintenance Scheduling
(Long Term) 1-3 years ahead Schedule and coordinate interutility sales and planned maintenance
Fuel Planning
(Long Term) 1-5 years ahead Develop least cost fuel supplies, contracts and delivery schedules
Transmission Planning
(Long Term) 2-10 years ahead Design regional and local system additions
Generation Planning
(Long Term) 2-5 years ahead Develop mix of new units, retirements, life extensions, and repowering based on long term load forecasts

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